e10vk
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
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Annual Report Pursuant to Section 13 or 15 (d)
of the Securities Exchange Act of 1934 |
For the fiscal year ended December 31, 2007
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Transition Report Pursuant to Section 13 of 15(d) of the
Securities Exchange Act of 1934 |
For the transition period from to
Commission File Number: 000 13305
PARALLEL PETROLEUM CORPORATION
(Exact Name of Registrant as Specified in its Charter)
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Delaware
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75-1971716 |
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(State or Other Jurisdiction of
Incorporation or Organization)
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(I.R.S. Employer
Identification No.) |
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1004 N. Big Spring, Suite 400
Midland, Texas
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79701 |
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(Address of Principal Executive Offices
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(Zip Code) |
Registrants Telephone Number, Including Area Code: (432) 684-3727
Securities Registered Pursuant to Section 12(b) of the Act:
Common Stock, $.01 par value
Common Stock Purchase Warrants
Rights to Purchase Series A Preferred Stock
(Title of Class)
Securities Registered Pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule
405 of the Securities Act.
Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section
13 or Section 15(d) of the Act.
Yes o No þ
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation
S-K is not contained herein, and will not be contained, to the best of registrants knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer,
a non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in
Rule 12b-2 of the Exchange Act. (Check one):
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
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Smaller reporting company o |
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(Do not check if a smaller reporting company) |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act).
Yes o No þ
The aggregate market value of voting and non-voting common equity held by non-affiliates of
the Registrant as of February 1, 2008 was approximately $578,055,034, based on the closing price of
the common stock on the same date.
At February 1, 2008 there were 41,252,644 shares of common stock outstanding.
FORM 10-K
PARALLEL PETROLEUM CORPORATION
TABLE OF CONTENTS
(i)
Cautionary Statement Regarding Forward -Looking Statements
Some statements contained in this Annual Report on Form 10-K are forward-looking statements.
These forward-looking statements relate to, among others, the following:
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our future financial and operating performance and results; |
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our drilling plans and ability to secure drilling rigs to effectuate our plans; |
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production volumes; |
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availability of natural gas gathering and transmission facilities; |
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our business strategy; |
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market prices; |
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sources and availability of funds necessary to conduct operations and complete acquisitions; |
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development costs; |
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number and location of planned wells; |
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our future commodity price risk management activities; |
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our plans and forecasts; and |
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any other statements that are not historical facts. |
We have based these forward-looking statements on our current assumptions, expectations and
projections about future events.
We use the words may, will, expect, could, anticipate, estimate, believe,
continue, intend, plan, budget, future, reserves and other similar words to identify
forward-looking statements. These statements also involve risks and uncertainties that could cause
our actual results or financial condition to materially differ from our expectations. We believe
the assumptions and expectations reflected in these forward-looking statements are reasonable.
However, we cannot give any assurance that our assumptions and expectations will prove to be
correct or that we will be able to take any actions that are presently planned. All of these
statements involve assumptions of future events and risks and uncertainties. Risks and
uncertainties associated with forward-looking statements include, but are not limited to:
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fluctuations in prices of oil and natural gas; |
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dependence on key personnel; |
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reliance on technological development and technology development programs; |
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demand for oil and natural gas; |
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losses due to future litigation; |
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future capital requirements and availability of financing; |
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geological concentration of our reserves; |
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risks associated with drilling and operating wells; |
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competition; |
(ii)
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general economic conditions; |
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governmental regulations and liability for environmental matters; |
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receipt of amounts owed to us by customers and counterparties to our derivative contracts; |
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hedging decisions, including whether or not to hedge; |
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terrorist attacks or war; |
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actions of third party co-owners of interests in properties in which we also own an interest; and |
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fluctuations in interest rates and availability of capital. |
For these and other reasons, actual results may differ materially from those projected or
implied. We believe it is important to communicate our expectations of future performance to our
investors. However, events may occur in the future that we are unable to accurately predict or
over which we have no control. We caution you against putting undue reliance on forward-looking
statements or projecting any future results based on such statements.
Before you invest in our common stock or our 101/4% senior notes, you should be aware that there
are various risks associated with an investment. We have described some of these risks in other
sections of this Annual Report on Form 10-K and under Item 1A. Risk Factors, beginning on page 13.
Unless the context requires otherwise, references in this Annual Report on Form 10-K to we,
us, our, Parallel or Company mean the registrant, Parallel Petroleum Corporation and, where
applicable, its former consolidated subsidiaries.
(iii)
PART I
ITEM 1. BUSINESS
About Our Company
We are a Midland, Texas-based independent oil and natural gas exploration and production
company focused on the acquisition, development and exploitation of long-lived oil and natural gas
reserves and, to a lesser extent, exploring for new oil and natural gas reserves. The majority of
our current producing properties are in the Permian Basin of West Texas and New Mexico, the Fort
Worth Basin of North Texas, and the onshore Gulf Coast area of South Texas. We are a publicly
traded company listed on Nasdaq under the ticker symbol PLLL.
Throughout this report, we refer to some terms that are commonly used and understood in the
oil and natural gas industry. These terms are:
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Bbl or Bbls barrel or barrels of oil or other liquid hydrocarbons; |
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Bcf billion cubic feet of natural gas; |
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BOE equivalent barrel of oil or 6 Mcf of natural gas for one barrel of oil; |
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MBbls thousand barrels of oil or other liquid hydrocarbons; |
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MBoe thousand barrels of oil equivalent; |
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MMBbls million barrels of oil or other liquid hydrocarbons; |
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MMBoe million barrels of oil equivalent; |
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MMBtu million British thermal units; |
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Mcf thousand cubic feet of natural gas; and |
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MMcf million cubic feet of natural gas. |
Parallel was incorporated in Texas on November 26, 1979, and reincorporated in the State of
Delaware on December 18, 1984.
Our executive offices are located at 1004 N. Big Spring, Suite 400, Midland, Texas 79701. Our
telephone number is (432) 684-3727.
Available Information
You may read and copy any materials we file with, or furnish to, the Securities and Exchange
Commission at the SECs public reference facilities at 100 F Street, N.E., Room 1580, Washington,
D.C. 20549. You may obtain information on the operation of the public reference facilities by
calling the SEC at 1-800-SEC-0330. The SEC maintains a website (www.sec.gov) that contains
reports, proxy and information statements, and other information regarding issuers, including
Parallel, that file electronically with the SEC.
Our website address is www.plll.com. Information on our website or any other website
is not incorporated by reference into this Annual Report on Form 10-K and does not constitute a
part of this Annual Report on Form 10-K.
We make available free of charge on our Internet website our annual reports on Form 10-K,
quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed
or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as
reasonably practicable after we electronically file such material with, or furnish it to, the SEC.
We will provide electronic or paper copies of our SEC filings free of charge upon request made
to Cindy Thomason, Manager of Investor Relations, cindyt@plll.com, 1-800-299-3727.
(1)
Developments in 2007; 2008 Capital Budget
On July 31, 2007, we completed a private offering of unsecured senior notes (the senior
notes or 101/4% senior notes) in the principal amount of $150.0 million. The senior notes mature
on August 1, 2014 and bear interest at 10.25% which is payable semi-annually beginning on February
1, 2008. Prior to August 1, 2010, we may redeem up to 35% of the senior notes for a price equal to
110.250% of the original principal amount of the senior notes with the proceeds of certain equity
offerings. On or after August 1, 2011 we may redeem all or some of the senior notes at a redemption
price that will decrease from 105.125% of the principal amount of the senior notes to 100% of the
principal amount on August 1, 2013. In addition, prior to August 1, 2011, we may redeem some or all
of the senior notes at a redemption price equal to 100% of the principal amount of the senior notes
to be redeemed, plus a make-whole premium, plus any accrued and unpaid interest. We have agreed to
use our reasonable best efforts to exchange the senior notes for registered, freely tradable notes
which otherwise have substantially identical terms to the senior notes within 210 days of July 31,
2007. A registration statement on Form S-4 allowing holders of the senior notes to exchange the
notes for freely tradable notes became effective on January 29, 2008.
On November 30, 2007, we entered into a Fourth Amendment to our Third Amended and Restated
Credit Agreement, dated December 23, 2005. In addition to amending certain covenants, our
borrowing base under the revolving credit facility was increased from $150.0 million to $200.0
million.
On December 6, 2007, we sold 3,000,000 shares of our common stock in an underwritten public
offering.
Our 2008 capital investment budget for properties we owned at February 1, 2008 is estimated to
be approximately $127.2 million, which includes $18.4 million for the purchase of leasehold and
seismic in our areas of activity. The budget will be funded from our estimated operating cash flows
and our bank borrowings. If our cash flows and bank borrowings are not sufficient to fund all of
our estimated capital expenditures, we may fund any shortfall with proceeds from the sale of our
debt or equity securities, reduce our capital budget or effect a combination of these alternatives.
The amount and timing of our expenditures are subject to change based upon market conditions,
results of expenditures, new opportunities and other factors.
Proved Reserves as of December 31, 2007
Cawley Gillespie & Associates, Inc., our independent petroleum engineers, estimated the total
proved reserves attributable to all of our oil and natural gas properties to be approximately 28.4
MMBbls of oil and approximately 57.2 Bcf of natural gas as of December 31, 2007.
Approximately 75% of our proved reserves are oil and approximately 56% are categorized as
proved developed reserves.
About Our Business and Strategy
We have positioned our property portfolio on premier acreage in established geologic trends
where we use our engineering, operational, financial and technical expertise to provide consistent
long-term production and attractive returns on our investments. We prefer obtaining positions in
long-lived oil and natural gas reserves to properties that have shorter reserve lives. We manage
financial, reservoir, drilling and geological risks by emphasizing lower-risk acquisition,
exploitation, enhancement and development drilling opportunities over higher-risk exploration
projects. Furthermore, aggressive application of advanced technologies and production techniques,
such as horizontal drilling and multi-stage fracture stimulation techniques have allowed us to
achieve what we believe to be best-in-class productivity in our Barnett Shale natural gas resource
play.
Our experienced executive management team, together with our technical staff, has
significantly grown our asset base, accumulating large acreage positions and working interests in
high-quality oil and natural gas properties that demonstrate attractive returns on investment. From
2001 to 2007, we have replaced approximately 456% of our production. For the year ended December
31, 2007, our depletion per BOE was $13.02, and our related lifting costs, excluding production
taxes, were $9.70 per BOE. Our long-lived Permian Basin reserves demonstrate shallow decline
profiles, high margins, low replacement costs and consistent positive cash flows. We continue to
utilize this reliable stream of cash flows from our oil production to support the development of
our natural gas resource plays. We believe we are positioned in some of the most attractive areas
of both the Barnett Shale and Wolfcamp Carbonate plays, and we have experienced a 95% drilling
success rate in these projects as of December 31, 2007. Chesapeake Energy Corporation, or
Chesapeake, as the operator of the majority of our interests in the Barnett Shale,
(2)
provides substantial operating expertise in the development of this project. We believe
through the development of our existing core oil and gas properties we have significant growth
potential.
Approximately 90% of our proved undeveloped reserves are assigned to our Permian Basin
long-lived oil properties and 10% are assigned to our two emerging resource gas projects. As of
December 31, 2007, our standardized measure of discounted future net cash flows was $634.4 million.
The following table presents proved reserves as of December 31, 2007 by our areas of operation.
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Proved Reserves as of December 31, 2007(1) |
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Oil |
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Natural Gas |
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Total |
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% of Total |
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(MBbl) |
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(MBoe) |
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MBoe |
Resource projects: |
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Barnett Shale |
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17,714 |
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2,952 |
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8 |
% |
New Mexico Wolfcamp |
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1 |
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24,284 |
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4,048 |
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10 |
% |
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Total resource projects |
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1 |
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41,998 |
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7,000 |
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18 |
% |
Permian Basin of West Texas |
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28,332 |
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12,365 |
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30,393 |
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% |
Onshore Gulf Coast of South Texas |
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101 |
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2,871 |
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580 |
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% |
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Total |
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28,434 |
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57,234 |
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37,973 |
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% |
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(1) |
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Period end market pricing, as of December 31, 2007, was $96.01
per Bbl and $7.46 per MMBtu. |
In 2007, we spent $154.3 million on oil and natural gas related capital expenditures, and our
2008 capital budget is $127.2 million. We have primarily focused our efforts on achieving
substantial growth in our production and proved reserves including our growth gas resource plays in
the North Texas Barnett Shale and New Mexico Wolfcamp Carbonate regions. In 2008, we plan to drill
over 108 gross infill wells, extension wells or well deepenings and to perform approximately 67
gross well workovers, refracs or restimulations. We plan to allocate our $127.2 million capital
budget for 2008 as follows:
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$60.0 million for the drilling and completion of new wells and the acquisition of
additional leasehold acreage in our North Texas Barnett Shale project; |
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$40.0 million for the drilling and completion of new wells, pipeline construction,
seismic and leasehold acquisitions in our New Mexico Wolfcamp Carbonate project; |
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$24.5 million for the drilling and completion of new wells, refracs, restimulations,
well deepenings and waterflood implementation in our Permian Basin of West Texas
project; and |
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$2.7 million for the drilling and completion of new wells in our Yegua/Frio,
Utah/Colorado and Cotton Valley Reef projects. |
Our Strategy
Conduct Exploitation Activities on Our Existing Assets. We seek to maximize economic return on
our existing assets by maximizing production rates and ultimate recovery, while managing
operational efficiency to minimize direct lifting costs. For the year ended December 31, 2007, our
lease operating expense per BOE produced was approximately $9.70, excluding production taxes.
Development and production growth activities include infill and extension drilling of new wells,
re-completion, pay adds and re-stimulation of existing wells and implementation and management of
enhanced oil recovery projects such as waterflood operations. Operational efficiencies and cost
reduction measures include optimization of surface facilities, such as fluid handling systems, gas
compression or artificial lift installations. Efficiencies are also increased through aggressive
monitoring and management of electrical power consumption, injection water quality programs,
chemical and corrosion prevention programs and the use of production surveillance equipment and
software. In all instances, a proactive approach is taken to achieve the desired result while
ensuring minimal environmental impact.
Accelerate Horizontal Drilling and Fracture Stimulation Activities in Gas Resource Plays. We
believe the use of horizontal drilling and fracture stimulations has enabled us to develop reserves
economically. The successful
application of these technologies has increased net production in these resource plays from
inception in July 2004 in the Wolfcamp to 9,306 Mcf per day and from inception in August 2005 in
the Barnett Shale to 10,068 Mcf per day
(3)
during the quarter ended December 31, 2007. Based on this
success, we plan to continue our activities in these two plays in 2008. Our current budget calls
for the drilling and completing of 53 gross (20.0 net) wells in the Barnett Shale and the drilling
and completing of 18 gross (15.3 net) wells in the Wolfcamp Carbonate. In addition to the drilling
of these new wells, we intend to invest $19.9 million for leasehold, pipeline, gathering, seismic,
and other infrastructure in these plays.
Use Advanced Technologies and Production Techniques. We believe that 3-D seismic surveys,
horizontal drilling, fracture stimulation and other advanced technologies and production techniques
are useful tools that help improve normal drilling operations and enhance our production and
returns. We believe that our use of these technologies and production techniques in exploring for,
developing and exploiting oil and natural gas properties can: reduce drilling risks, lower finding
costs, provide for more efficient production of oil and natural gas from our properties and
increase the probability of locating and producing reserves that might not otherwise be discovered.
Acquire Long-Lived Properties with Enhancement Opportunities. Our acquisition strategy is
focused on leveraging our geographical expertise in our core areas of operation and seeking assets
located in and around these areas. We selectively evaluate acquisition opportunities and expect
that they will continue to play a role in increasing our reserve base and future drilling
inventory. When identifying target assets, we focus primarily on
reserve quality and assets in new
developing plays with upside potential. Through this approach, we have traditionally targeted
smaller asset acquisitions which allow us to absorb, enhance and exploit properties without taking
on significant integration risk.
Conduct Exploratory Activities. Although we do not emphasize exploratory drilling, we will
selectively undertake exploratory projects that have known geological and reservoir characteristics
are in close proximity to existing wells so data from the existing wells can be correlated with
seismic data on or near the prospect being evaluated, and that could have a potentially meaningful
impact on our reserves.
Drilling Activities in 2007
The following table shows our gross and net wells drilled, by geographic area, during 2007 and
the number of wells in process at December 31, 2007.
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Number of Wells |
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Number of |
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Gross |
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Depth |
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Waiting on Completion |
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Productive |
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Gross |
Area |
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Range (feet) |
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Wells Drilled |
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at December 31, 2007 |
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Wells |
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Dry Wells |
North Texas |
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Barnett Shale |
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7,000 8,000 |
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52 |
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17 |
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34 |
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1 |
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Permian Basin of West Texas
and New Mexico |
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Carm-Ann/Means |
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4,000 4,500 |
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2 |
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2 |
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Harris |
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4,000 4,500 |
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9 |
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9 |
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Fullerton |
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4,000 5,000 |
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5 |
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5 |
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Wolfcamp Gas |
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4,300 4,500 |
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34 |
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1 |
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32 |
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1 |
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Onshore Gulf Coast of Texas |
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Frio/Yegua/Wilcox |
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5,000 10,000 |
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3 |
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3 |
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105 |
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18 |
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85 |
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2 |
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(4)
Drilling and Acquisition Costs
The table below shows our oil and natural gas property acquisition, exploration and
development costs for the periods indicated.
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Year Ended December 31, |
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2007 |
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2006 |
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2005 |
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($ in thousands) |
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Proved property acquisition costs |
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$ |
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$ 27,370 |
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$ |
23,763 |
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Unproved property acquisition costs |
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36,750 |
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30,058 |
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11,743 |
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Exploration costs |
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55,827 |
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71,003 |
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15,455 |
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Development costs |
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61,766 |
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69,285 |
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26,640 |
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$ |
154,343 |
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$197,716 |
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$ |
77,601 |
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Current Drilling Projects
Summarized below are our more significant current projects, including our capital budget for
these projects in 2008:
Resource Natural Gas Projects
We have two resource natural gas projects in varying stages of development. They are the
Barnett Shale gas project in the Fort Worth Basin of north Texas and the Wolfcamp gas project in
the Permian Basin of New Mexico.
We have budgeted approximately $100.0 million for these two resource natural gas projects in
2008 for the drilling and completion of approximately 71 new gross wells, leasehold acquisition,
pipeline construction and pipeline compression.
Fort Worth Basin of North Texas and Permian Basin of New Mexico
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Barnett Shale Gas Project, Tarrant County, Texas |
We have budgeted approximately $60.0 million for this project in 2008 for the drilling and
completion of 53 new gross (20.0 net) wells, pipeline construction and leasehold acquisition. As
of February 1, 2008, there were 3 drilling rigs running and 15 wells awaiting completion and
pipeline connection in the Barnett Shale gas project.
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Wolfcamp Gas Project, Eddy and Chavez Counties, New Mexico |
Our New Mexico Wolfcamp gas project consists of three areas of mutual interest in which the
primary target is the Wolfcamp formation at a depth of approximately 4,500 feet. We anticipate
participating in the drilling of approximately 18 gross (15.3 net) operated horizontal wells in New
Mexico during 2008 in the Northern Area. We have budgeted approximately $40.0 million for this
project in 2008 to fund the drilling in the Northern Area, the installation of pipelines and
related infrastructure, the acquisition of additional leasehold, and the acquisition of 3-D seismic
data in the Southern Area. As of February 1, 2008, 1 drilling rig was running, 2 wells were in the
process of completion and 1 well was awaiting completion.
Permian Basin of West Texas
Our significant producing properties in the Permian Basin of west Texas are described below.
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Fullerton San Andres Field, Andrews County, Texas |
We have budgeted approximately $4.0 million in 2008 to fund the drilling of an estimated 7
gross (6.2 net) new wells and the conversion to injection of 2 gross (1.6 net) existing wells. Our
average working interest in the Fullerton properties is approximately 85%.
(5)
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Carm-Ann San Andres Field / N. Means Queen Unit,
Andrews & Gaines Counties, Texas |
We have budgeted approximately $3.3 million for the Carm-Ann/N. Means Queen properties in 2008
for the drilling and completion of 5 gross (4.3 net) wells and the conversion to injection of 6
gross (5.1 net) existing wells. Our average working interest in these properties is approximately
77%.
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Harris San Andres Field, Andrews and Gaines Counties, Texas |
We have budgeted approximately $5.3 million for the Harris San Andres properties in 2008 for
the drilling of an estimated 7 gross (6.3 net) wells and the re-frac workover or conversion to
injection of 16 gross (14.4 net) existing wells. Our average working interest in these properties
is approximately 90%.
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Diamond M Canyon Reef Unit, Scurry County, Texas |
A total of $9.6 million has been budgeted in 2008 for the Diamond M Canyon Reef project for
the drilling and completion of approximately 12 gross (7.9 net) new wells and the workover or
deepening of approximately 18 gross (11.8 net) existing wells. Our average working interest in
these properties is approximately 66% with our work-to-earn arrangement with Southwestern Energy
Company.
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Diamond M Shallow leases, Scurry County, Texas |
A total of $1.3 million has been budgeted in 2008 for the Diamond M Shallow project for the
installation of dual injection strings in approximately 25 gross (16.5 net) existing wells. Our
average working interest in these properties is approximately 66% with our work-to-earn arrangement
with Southwestern Energy Company.
Onshore Gulf Coast of South Texas
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Yegua/Frio/Wilcox and Cook Mountain Gas Projects, Jackson, Wharton and Liberty
Counties, Texas |
We have budgeted approximately $0.7 million for the south Texas projects in 2008 for the
drilling and completion of 2 gross (0.5 net) wells.
Other Projects
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Utah/Colorado Conventional Oil & Gas and Heavy Oil Sands Projects, Uinta Basin |
We have budgeted approximately $1.5 million for the Utah/Colorado project in 2008 for the
drilling and completion of 3 gross (2.9 net) wells and the acquisition of additional leasehold.
We own and operate 97.5% of this project.
Oil and Natural Gas Prices
The average wellhead prices we received for the oil and natural gas we produced in 2007, 2006
and 2005 are shown in the table below.
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Average Price Received for the |
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Year Ended December 31, |
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2007 |
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2006 |
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2005 |
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Oil (Bbl) |
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$ |
65.97 |
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$ |
59.86 |
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$ |
51.78 |
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Natural gas (Mcf) |
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$ |
6.29 |
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$ |
6.19 |
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$ |
8.54 |
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The average price we received for our oil sales at February 1, 2008 was approximately $85.17
per Bbl. At the same date, the average price we were receiving for our natural gas was
approximately $6.91 per Mcf.
(6)
There is substantial uncertainty regarding future oil and natural gas prices and we can
provide no assurance that prices will remain at current levels. We have entered into derivative
contracts in an attempt to reduce the risk of fluctuating oil and natural gas prices.
Employees and Consultants
At February 1, 2008, we had 43 full time employees. We also retain independent land,
geological, geophysical, engineering, drilling and financial consultants from time to time and
expect to continue to do so in the future. Additionally, we retain contract pumpers on a
month-to-month basis.
Until his retirement on June 26, 2007, Thomas R. Cambridge, our former Chairman of the Board
of Directors, served in the capacity of a geological consultant and not as a full-time employee.
We consider our employee relations to be satisfactory. None of our employees are represented
by a union and we have not experienced work stoppages or strikes.
Wells Drilled
The following table shows certain information concerning the number of gross and net wells we
drilled during the three-year period ended December 31, 2007.
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Exploratory Wells (1) |
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Development Wells (2) |
Year Ended |
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Productive |
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Dry |
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Productive |
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Dry |
December 31, |
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Gross |
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Net |
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Gross |
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Net |
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Gross |
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Net |
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Gross |
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Net |
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2007 |
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36.0 |
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13.93 |
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1.0 |
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1.00 |
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67.0 |
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32.3 |
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1.00 |
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0.37 |
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2006 |
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5.0 |
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2.87 |
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3.0 |
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1.42 |
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122.0 |
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68.4 |
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1.00 |
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0.08 |
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2005 |
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21.0 |
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5.32 |
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6.0 |
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0.64 |
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48.0 |
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27.5 |
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(1) |
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An exploratory well is a well drilled to find and produce oil or natural gas in an unproved
area, to find a new reservoir in a field previously found to be productive of oil or natural
gas in another reservoir, or to extend a known reservoir. |
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(2) |
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A development well is a well drilled within the proved area of an oil or natural gas
reservoir to the depth of a stratigraphic horizon known to be productive. |
All of our drilling is performed on a contract basis by third-party drilling contractors. We
do not own any drilling equipment. We maintain a limited number of supervisory and field personnel
to oversee drilling and production operations. Our plans to drill additional wells are determined
in part by the anticipated availability of acceptable drilling equipment and crews. We do not
currently have any contractual commitments that ensure we will have adequate drilling equipment or
crews to achieve our drilling plans. As of February 1, 2008, we had 3 drilling rigs in operation at
our Barnett Shale project and 1 drilling rig in operation at our New Mexico project. We believe
that we currently can secure commitments from drilling companies that will make equipment available
to us for drilling wells on our operated projects. In the case of our non-operated properties, we
also believe that the operators of these other properties will be able to secure equipment for
drilling on our non-operated properties. However, we can provide no assurance that our
expectations regarding the availability of drilling equipment from these companies will be met.
At February 1, 2008, we were participating in the completion of 10 gross (4.69 net) wells, 6
gross (1.92 net) wells were awaiting completion, 2 gross (0.66 net) wells were shut-in waiting on
pipelines and 4 gross (1.47 net) wells were in process of drilling.
(7)
Volumes, Prices and Lifting Costs
The following table shows certain information about our oil and natural gas production
volumes, average sales prices per Mcf of natural gas and Bbl of oil and the average lifting
(production) cost per BOE for the three-year period ended December 31, 2007.
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Year Ended December 31, |
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2007 |
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2006 |
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2005 |
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(in thousands, except per unit data) |
Production, Prices and Lifting Costs: |
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Oil (Bbls) |
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1,051 |
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1,137 |
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923 |
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Natural gas (Mcf) |
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7,422 |
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6,539 |
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3,592 |
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BOE |
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2,288 |
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2,227 |
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1,522 |
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Oil price (per Bbl) (1) |
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$ |
65.97 |
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$ |
59.86 |
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$ |
51.78 |
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Natural gas price (per Mcf) (1) |
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$ |
6.29 |
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$ |
6.19 |
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$ |
8.54 |
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BOE price (1) |
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$ |
50.72 |
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$ |
48.73 |
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$ |
51.57 |
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Average Lifting Cost (including production taxes) per BOE |
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$ |
11.60 |
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$ |
10.06 |
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$ |
9.24 |
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(1) |
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Average price received at the wellhead for our oil and natural gas. |
In 2007, approximately 46% of the volume of our production was oil and 54% was natural gas.
The majority of the oil production is from our Permian Basin longer-lived oil assets. The majority
of the natural gas production is from our Barnett Shale and New Mexico Wolfcamp assets.
The following table summarizes our revenues by product sold for each year in the three year
period ended December 31, 2007.
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2007 |
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2006 |
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2005 |
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($ in thousands) |
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Oil revenue |
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$ |
69,315 |
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$68,076 |
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$ |
47,800 |
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Effect of oil hedges |
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(11,512 |
) |
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(12,139 |
) |
Natural gas revenue |
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46,716 |
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40,461 |
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30,690 |
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Effect of natural gas hedges |
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(201 |
) |
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$ |
116,031 |
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$97,025 |
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$ |
66,150 |
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Our oil sales in 2007 represented approximately 60% of our combined oil and natural gas
revenues (not considering the effect of hedging) for the year ended December 31, 2007, as compared
to 63% in 2006, and 61% in 2005.
Markets and Customers
Our oil and natural gas production is sold at the well site on an as produced basis at
market-related prices in the areas where the producing properties are located. We do not refine or
process any of the oil or natural gas we produce and all of our production is sold to unaffiliated
purchasers on a month-to-month basis.
(8)
In the table below, we show the purchasers that accounted for 10% or more of our revenues
during the specified years.
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2007 |
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2006 |
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2005 |
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Allegro Investments, Inc. |
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(1 |
) |
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(1 |
) |
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14 |
% |
Conoco, Inc. |
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21 |
% |
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20 |
% |
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12 |
% |
Texland Petroleum, Inc. |
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30 |
% |
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30 |
% |
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40 |
% |
Tri-C Resources, Inc. |
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(1 |
) |
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12 |
% |
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(1 |
) |
Dale Operating Company |
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(1 |
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10 |
% |
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(1 |
) |
Chesapeake Operating, Inc. |
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12 |
% |
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(1 |
) |
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(1 |
) |
We do not believe the loss of any one of our purchasers would materially affect our ability to
sell the oil and natural gas we produce. Other purchasers are available in our areas of operations.
Our future ability to market our oil and natural gas production depends upon the availability
and capacity of natural gas gathering systems and pipelines and other transportation facilities. We
are not obligated to provide a fixed or determinable quantity of oil and natural gas under any
existing arrangements or contracts.
Our business does not require us to maintain a backlog of products, customer orders or
inventory.
Office Facilities
Our principal executive offices are located in Midland, Texas, where we lease approximately
22,200 square feet of office space at 1004 North Big Spring, Suite 400, Midland, Texas 79701. Our
current rental rate is $16,650 per month. The lease expires on February 28, 2010.
We have three field offices and storage facilities. These three offices are located in Andrews
and Snyder, Texas and Hagerman, New Mexico. The current monthly rental rate is $1,200 for the
Snyder office. The Snyder office lease expires upon the cessation of production from the Diamond
M area wells.
Competition
The oil and natural gas industry is highly competitive, particularly in the areas of acquiring
exploratory and development prospects and producing properties. The principal means of competing
for the acquisition of oil and natural gas properties are the amount and terms of the consideration
offered. Our competitors include major oil companies, independent oil and natural gas firms and
individual producers and operators. Many of our competitors have financial resources, staffs and
facilities much larger than ours.
We are also affected by competition for drilling rigs and the availability of related
equipment. With relatively high oil and natural gas prices, the oil and natural gas industry
typically experiences shortages of drilling rigs, equipment, pipe and qualified field personnel.
Although we are unable to predict when or to what extent our exploration and development activities
will be affected by rig, equipment or personnel shortages, we have recently experienced, and
continue to experience, delays in some of our planned activities and operations because of these
shortages.
Intense competition among independent oil and natural gas producers requires us to react
quickly to available exploration and acquisition opportunities. We try to position for these
opportunities by maintaining:
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adequate capital resources for projects in our core areas of operations; |
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the technological capabilities to conduct a thorough evaluation of a particular
project; and |
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a small staff that can respond quickly to exploration and acquisition opportunities. |
The principal resources we need for acquiring, exploring, developing, producing and selling
oil and natural gas are:
(9)
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leasehold prospects under which oil and natural gas reserves may be discovered or
developed; |
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drilling rigs and related equipment to explore for such reserves; and |
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knowledgeable and experienced personnel to conduct all phases of oil and natural gas
operations. |
Oil and Natural Gas Regulations
Our operations are regulated by certain federal and state agencies. Oil and natural gas
production and related operations are or have been subject to:
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price controls; |
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taxes; and |
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environmental and other laws relating to the oil and natural gas industry. |
We cannot predict how existing laws and regulations may be interpreted by governmental
agencies or court rulings, whether additional laws and regulations will be adopted, or the effect
such interpretations or new laws and regulations may have on our business, financial condition or
results of operations.
Our oil and natural gas exploration, production and related operations are subject to
extensive rules and regulations that are enforced by federal, state and local governmental
agencies. Failure to comply with these rules and regulations can result in substantial penalties.
The regulatory burden on the oil and natural gas industry increases our cost of doing business and
affects our profitability. Because these rules and regulations are frequently amended or
reinterpreted, we are not able to predict the future cost or impact of compliance with these laws.
Texas and many other states require drilling permits, bonds and operating reports. Other
requirements relating to the exploration and production of oil and natural gas are also imposed.
These states also have statutes or regulations addressing conservation matters, including
provisions for:
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the unitization of pooling of oil and natural gas properties; |
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the establishment of maximum rates of production from oil and natural gas wells; and |
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the regulation of spacing, plugging and abandonment of wells. |
Sales of natural gas we produce are not regulated and are made at market prices. However, the
Federal Energy Regulatory Commission (FERC) regulates interstate and certain intrastate natural gas
transportation rates and services conditions, which affect the marketing of our natural gas, as
well as the revenues we receive for sales of our production. Since the mid-1980s, FERC has issued a
series of orders, culminating in Order Nos. 636, 636-A, 636-B, and 636-C. These orders, commonly
known as Order 636, have significantly altered the marketing and transportation service, including
the unbundling by interstate pipelines of the sales, transportation, storage and other components
of the city-gate sales services these pipelines previously performed.
One of FERCs purposes in issuing the orders was to increase competition in all phases of the
natural gas industry. Order 636 and subsequent FERC orders issued in individual pipeline
restructuring proceedings has been the subject of appeals, the results of which have generally been
supportive of the FERCs open-access policy. In 1996, the United States Court of Appeals for the
District of Columbia Circuit largely upheld Order No. 636. Because further review of certain of
these orders is still possible, and other appeals remain pending, it is difficult to predict the
ultimate impact of the orders on Parallel and our natural gas marketing efforts. Generally, Order
636 has eliminated or substantially reduced the interstate pipelines traditional role as
wholesalers of natural gas, and has substantially increased competition and volatility in natural
gas markets. While significant regulatory uncertainty remains, Order 636 may ultimately enhance our
ability to market and transport our natural gas, although it may also subject us to greater
competition.
Sales of oil we produce are not regulated and are made at market prices. The price we receive
from the sale of oil is affected by the cost of transporting the product to market. Effective
January 1, 1995, FERC implemented regulations establishing an indexing system for transportation
rates for interstate common carrier oil pipelines, which, generally, would index such rates to
inflation, subject to certain conditions and limitations. These regulations
(10)
could increase the cost of transporting oil by interstate pipelines, although the most recent
adjustment generally decreased rates. These regulations have generally been approved on judicial
review. We are unable to predict with certainty what effect, if any, these regulations will have on
us. The regulations may, over time, tend to increase transportation costs or reduce wellhead prices
for oil.
We are also required to comply with various federal and state regulations regarding plugging
and abandonment of oil and natural gas wells.
Environmental Regulations
Various federal, state and local laws and regulations governing the discharge of materials
into the environment, or otherwise relating to the protection of the environment, health and
safety, affect our operations and costs. These laws and regulations sometimes:
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require prior governmental authorization for certain activities; |
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limit or prohibit activities because of protected areas or species; |
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impose substantial liabilities for pollution related to our operations or
properties; and |
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provide significant penalties for noncompliance. |
In particular, our exploration and production operations, our activities in connection with
storing and transporting oil and other liquid hydrocarbons, and our use of facilities for treating,
processing or otherwise handling hydrocarbons and related exploration and production wastes are
subject to stringent environmental regulations. As with the industry generally, compliance with
existing and anticipated regulations increases our overall cost of business. While these
regulations affect our capital expenditures and earnings, we believe that they do not affect our
competitive position in the industry because our competitors are also affected by the same
environmental regulatory programs. Since environmental regulations have historically been subject
to frequent change, we cannot predict with certainty the future costs or other future impacts of
environmental regulations on our future operations. A discharge of hydrocarbons or hazardous
substances into the environment could subject us to substantial expense, including the cost to
comply with applicable regulations that require a response to the discharge, such as claims by
neighboring landowners, regulatory agencies or other third parties for costs of:
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containment or cleanup; |
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personal injury; |
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property damage; and |
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penalties assessed or other claims sought for natural resource damages. |
The following are examples of some environmental laws that potentially impact our operations.
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Water. The Oil Pollution Act, or OPA, was enacted in 1990 and amends
provisions of the Federal Water Pollution Control Act of 1972 (FWPCA) and other
statutes as they pertain to prevention of and response to major oil spills. The OPA
subjects owners of facilities to strict, joint and potentially unlimited liability for
removal costs and certain other consequences of an oil spill, where such spill is into
navigable waters, or along shorelines. In the event of an oil spill into such waters,
substantial liabilities could be imposed upon us. States in which we operate have also
enacted similar laws. Regulations are currently being developed under the OPA and
similar state laws that may also impose additional regulatory burdens on us. |
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The FWPCA imposes restrictions and strict controls regarding the discharge of produced
waters, other oil and gas wastes, any form of pollutant, and, in some instances, storm
water runoff, into waters of the United States. The FWPCA provides for civil, criminal
and administrative penalties for any unauthorized discharges and, along with the OPA,
imposes substantial potential liability for the costs of removal, remediation or damages
resulting from an unauthorized discharge. State laws for the control of water pollution
also provide civil, criminal and administrative penalties and liabilities in the case of
an unauthorized discharge into state waters. The cost of compliance with the OPA and the
FWPCA have |
(11)
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not historically been material to our operations, but there can be no assurance that
changes in federal, state or local water pollution control programs will not materially
adversely affect us in the future. Although no assurances can be given, we believe that
compliance with existing permits and compliance with foreseeable new permit requirements
will not have a material adverse effect on our financial condition or results of
operations. |
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Solid Waste. We generate non-hazardous solid waste that fall under the
requirements of the Federal Resource Conservation and Recovery Act and comparable state
statues. The EPA and the states in which we operate are considering the adoption of
stricter disposal standards for the type of non-hazardous waste we generate. The
Resource Conservation and Recovery Act also governs the generation, management, and
disposal of hazardous wastes. At present, we are not required to comply with a
substantial portion of the Resource Conservation and Recovery Act requirements because
our operations generate minimal quantities of hazardous wastes. However, it is
anticipated that additional wastes, which could include wastes currently generated
during operations, could in the future be designated as hazardous wastes. Hazardous
wastes are subject to more rigorous and costly disposal and management requirements
than are non-hazardous wastes. Such changes in the regulations may result in us
incurring additional capital expenditures or operating expenses. |
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Superfund. The Comprehensive Environmental Response, Compensation, and
Liability Act, sometimes called CERCLA or Superfund, imposes liability, without regard
to fault or the legality of the original act, on certain classes of persons in
connection with the release of a hazardous substance into the environment. These
persons include the current owner or operator of any site where a release historically
occurred and companies that disposed or arranged for the disposal of the hazardous
substances found at the site. CERCLA also authorizes the EPA and, in some instances,
third parties to act in response to threats to the public health or the environment and
to seek to recover from the responsible classes of persons the costs they incur. In the
course of our ordinary operations, we may have managed substances that may fall within
CERCLAs definition of a hazardous substance. We may be jointly and severally liable
under CERCLA for all or part of the costs required to clean up sites where we disposed
of or arranged for the disposal of these substances. This potential liability extends
to properties that we owned or operated as well as to properties owned and operated by
others at which disposal of our hazardous substances occurred. |
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We currently own or lease numerous properties that for many years have been used for
exploring and producing oil and natural gas. Although we believe we use operating and
disposal practices standard in the industry, hydrocarbons or other wastes may have been
disposed of or released by us on or under properties that we have owned or leased. In
addition, many of these properties have been previously owned or operated by third
parties who may have disposed of or released hydrocarbons or other wastes at these
properties. Under CERCLA, and analogous state laws, we could be required to remove or
remediate previously disposed wastes, including wastes disposed of or released by prior
owners or operators, to clean up contaminated property, including contaminated
groundwater, or to perform remedial plugging operations to prevent future contamination. |
Recent scientific studies have suggested that emissions of certain gases, commonly referred to
as greenhouse gases, may be contributing to warming of the Earths atmosphere. Methane, a primary
component of natural gas, and carbon dioxide, a byproduct of the burning of fossil fuels, are
examples of greenhouse gases. In response to such studies, the U.S. Congress is actively
considering legislation to reduce emissions of greenhouse gases. In addition, at least nine states
in the Northeast and five states in the West including New Mexico have declined to wait on Congress
to develop and implement climate control legislation and have already taken legal measures to
reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas
emission inventories and/or regional greenhouse gas cap and trade programs. Also, as a result of
the U.S. Supreme Courts decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be
required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if
Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The
Courts holding in Massachusetts that greenhouse gases fall under the federal Clean Air Acts
definition of air pollutant may also result in future regulation of greenhouse gas emissions from
stationary sources under certain Clean Air Act programs. Passage of climate control legislation or
other regulatory initiatives by Congress or various states of the U.S. or the adoption of
regulations by the EPA or analogous state agencies that restrict emissions of greenhouse gases in
areas in which we conduct business could have an adverse affect on our operations and demand for
our products.
(12)
ITEM 1A. RISK FACTORS
The following should be considered carefully with the information provided elsewhere in this
Annual Report on Form 10-K in reaching a decision regarding an investment in our securities.
Risks Related to Our Business
The volatility of the oil and natural gas industry may have an adverse impact on our operations.
Our revenues, cash flows and profitability are substantially dependent upon prevailing prices
for oil and natural gas. In recent years, oil and natural gas prices and, therefore, the level of
drilling, exploration, development and production, have been extremely volatile. Any significant or
extended decline in oil or natural gas prices will have a material adverse effect on our business,
financial condition and results of operations and could impair access to future sources of capital.
Volatility in the oil and natural gas industry results from numerous factors, over which we have no
control, including:
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the level of oil and natural gas prices, expectations about future oil and natural
gas prices and the ability of international cartels to set and maintain production
levels and prices; |
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the cost of exploring for, producing and transporting oil and natural gas; |
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the level and price of foreign oil and natural gas transportation; |
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available pipeline and other oil and natural gas transportation capacity; |
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weather conditions; |
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international political, military, regulatory and economic conditions; |
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the level of consumer demand; |
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the price and the availability of alternative fuels; |
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the effect of worldwide energy conservation measures; and |
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the ability of oil and natural gas companies to raise capital. |
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Significant declines in oil and natural gas prices for an extended period may:
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impair our financial condition, liquidity, ability to finance planned capital
expenditures and results of operations; |
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reduce the amount of oil and natural gas that we can produce economically; |
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cause us to delay or postpone some of our capital projects; |
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reduce our revenues, operating income and cash flow; and |
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reduce the recorded value of our oil and natural gas properties. |
No assurance can be given that current levels of oil and natural gas prices will continue. We
expect oil and natural gas prices, as well as the oil and natural gas industry generally, to
continue to be volatile.
We must replace oil and natural gas reserves that we produce. Failure to replace reserves may
negatively affect our business.
Our future performance depends in part upon our ability to find, develop and acquire
additional oil and natural gas reserves that are economically recoverable. Our proved reserves
decline as they are depleted and we must locate and develop or acquire new oil and natural gas
reserves to replace reserves being depleted by production. No assurance can be given that we will
be able to find and develop or acquire additional reserves on an economic basis. If we cannot
economically replace our reserves, our results of operations may be materially adversely
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affected and our stock price may decline and the price at which a note holder would be able to
sell our 101/4% senior notes could decline.
We are subject to uncertainties in reserve estimates and future net cash flows.
There is substantial uncertainty in estimating quantities of proved reserves and projecting
future production rates and the timing of development expenditures. No one can measure underground
accumulations of oil and natural gas in an exact way. Accordingly, oil and natural gas reserve
engineering requires subjective estimations of those accumulations. Estimates of other engineers
might differ widely from those of our independent petroleum engineers, and our independent
petroleum engineers may make material changes to reserve estimates based on the results of actual
drilling, testing, and production. As a result, our reserve estimates often differ from the
quantities of oil and natural gas we ultimately recover. Also, we make certain assumptions
regarding future oil and natural gas prices, production levels, and operating and development costs
that may prove incorrect. Any significant variance from these assumptions could greatly affect our
estimates of reserves, the economically recoverable quantities of oil and natural gas attributable
to any particular group of properties, the classifications of reserves based on risk of recovery,
and estimates of the future net cash flows. Some of our reserve estimates are made without the
benefit of a lengthy production history and are calculated using volumetric analysis. Those
estimates are less reliable than estimates based on a lengthy production history. Volumetric
analysis involves estimating the volume of a reservoir based on the net feet of pay and an
estimation of the productive area.
The present value of future net cash flows from our proved reserves is not necessarily the
same as the current market value of our estimated oil and natural gas reserves. We base the
estimated discounted future net cash flows from our proved reserves on prices and costs in effect
on the day of estimate. However, actual future net cash flows from our oil and natural gas
properties also will be affected by factors such as:
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actual prices we receive for oil and natural gas; |
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the amount and timing of actual production; |
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supply and demand of oil and natural gas; |
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limits of increases in consumption by natural gas purchasers; and |
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changes in governmental regulations or taxation. |
The timing of both our production and our incurrence of expenses in connection with the
development and production of oil and natural gas properties will affect the timing of actual
future net cash flows from proved reserves, and thus their actual present value. In addition, the
10% discount factor we use when calculating discounted future net cash flows may not be the most
appropriate discount factor based on interest rates in effect from time to time and risks
associated with us or the oil and natural gas industry in general.
Competition in the oil and natural gas industry is intense, and many of our competitors have
greater financial, technological and other resources than we do.
We operate in the highly competitive areas of oil and natural gas acquisition, development,
exploitation, exploration and production. The oil and natural gas industry is characterized by
rapid and significant technological advancements and introductions of new products and services
using new technologies. We face intense competition from independent, technology-driven companies
as well as from both major and other independent oil and natural gas companies in each of the
following areas:
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seeking to acquire desirable producing properties or new leases for future
exploration; |
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marketing our oil and natural gas production; |
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integrating new technologies; and |
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seeking to acquire the equipment and expertise necessary to develop and operate our
properties. |
Many of our competitors have financial, technological and other resources substantially
greater than ours, and some of them are fully integrated oil and natural gas companies. These
companies may be able to pay more for
(14)
development prospects and productive oil and natural gas properties and may be able to define,
evaluate, bid for and purchase a greater number of properties and prospects than our financial or
human resources permit. Further, these companies may enjoy technological advantages and may be able
to implement new technologies more rapidly than we can. Our ability to develop and exploit our oil
and natural gas properties and to acquire additional properties in the future will depend upon our
ability to successfully conduct operations, implement advanced technologies, evaluate and select
suitable properties and consummate transactions in this highly competitive environment.
We do not control all of our operations and development projects, which may adversely affect our
production, revenues and results of operations.
Substantially all of our business activities are conducted through joint operating agreements
under which we own partial interests in oil and natural gas wells. As of December 31, 2007, we
owned interests in 369 gross (306.55 net) oil and natural gas wells for which we were the operator
and 569 gross (270.84 net) oil and natural gas wells where we were not the operator. Included in
these wells are 175 gross (79.07 net) wells which are shut in or temporarily abandoned and 128
gross (98.30 net) injection wells. Furthermore, we are not the operator of any of our interests in
the Barnett Shale project. As a result, the success and timing of our drilling and development
activities on properties operated by others depends upon a number of factors outside of our
control, including the operators:
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timing and amount of capital expenditures; |
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expertise and financial resources; |
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inclusion of other participants in drilling wells; and |
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use of technology. |
Further, we may not be in a position to remove the operator in the event of poor performance,
and we may not have control over normal operating procedures, expenditures or future development of
underlying properties. If drilling and development activities are not conducted on these properties
or are not conducted on a timely basis, we may be unable to increase our production or offset
normal production declines, which may adversely affect our production, revenues and results of
operations.
Our business is subject to many inherent risks, including operating risks, which may result in
substantial losses, and insurance may be unavailable or inadequate to protect us against these
risks.
Oil and natural gas drilling activities and production operations are highly speculative and
involve a high degree of risk. These operations are marked by unprofitable efforts because of dry
holes and wells that do not produce oil or natural gas in sufficient quantities to return a profit.
The success of our operations depends, in part, upon the ability of our management and technical
personnel. The cost of drilling, completing and operating wells is often uncertain. There is no
assurance that our oil and natural gas drilling or acquisition activities will be successful, that
any production will be obtained, or that any such production, if obtained, will be profitable.
Our operations are subject to all of the operating hazards and risks normally incident to
drilling for and producing oil and natural gas. These hazards and risks include, but are not
limited to:
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explosions, blowouts and fires; |
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natural disasters; |
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pressure forcing oil or natural gas out of the wellbore at a dangerous velocity
coupled with the potential for fire or explosion; |
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weather; |
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failure of oilfield drilling and service equipment and tools; |
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changes in underground pressure in a formation that causes the surface to collapse
or crater; |
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pipeline ruptures or cement failures; |
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environmental hazards such as natural gas leaks, oil spills and discharges of toxic
gases; and |
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availability of needed equipment at acceptable prices, including steel tubular
products. |
Any of these risks can cause substantial losses resulting from:
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injury or loss of life; |
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damage to and destruction of property, natural resources and equipment; |
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pollution and other environmental damage; |
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regulatory investigations and penalties; |
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suspension of our operations; and |
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repair and remediation costs. |
As is customary in the industry, we maintain insurance against some, but not all, of these
hazards. We maintain general liability insurance and obtain Operators Extra Expense insurance on a
well-by-well basis. We carry insurance against certain pollution hazards, subject to our insurance
policys terms, conditions and exclusions. If we sustain an uninsured loss or liability, our
ability to operate could be materially adversely affected.
Our oil and natural gas operations are not subject to renegotiation of profits or termination
of contracts at the election of the federal government.
The oil and natural gas industry is capital intensive.
The oil and natural gas industry is capital intensive. We make substantial capital
expenditures for the acquisition, exploration for and development of oil and natural gas reserves.
Historically, we have financed capital expenditures primarily with cash generated by
operations, proceeds from borrowings and sales of our equity securities. In addition, we have
sold and may consider selling additional assets to raise additional operating capital. From time to
time, we may also reduce our ownership interests in our projects in order to reduce our capital
expenditure requirements.
Our cash flow from operations and access to capital is subject to a number of variables,
including:
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our proved reserves; |
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the level of oil and natural gas we are able to produce from existing wells; |
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the prices at which oil and natural gas are sold; and |
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our ability to acquire, locate and produce new reserves. |
Any one of these variables can materially affect our ability to borrow under our revolving
credit facility.
If our revenues or the borrowing base under our revolving credit facility decrease as a result
of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other
reason, we may have limited ability to obtain the capital necessary to undertake or complete future
drilling projects. We may, from time to time, seek additional financing, either in the form of
increased bank borrowings, sale of debt or equity securities or other forms of financing and there
can be no assurance as to the availability of any additional financing upon terms acceptable to us.
There are risks in acquiring producing properties, including difficulties in integrating acquired
properties into our business, additional liabilities and expenses associated with acquired
properties, diversion of management attention, increasing the scope, geographic diversity and
complexity of our operations and incurrence of additional debt.
(16)
Our business strategy includes growing our reserve base through acquisitions. Our failure to
integrate acquired businesses successfully into our existing business, or the expense incurred in
consummating future acquisitions, could result in unanticipated expenses and losses. In addition,
we may assume cleanup or reclamation obligations or other unanticipated liabilities in connection
with these acquisitions. The scope and cost of these obligations may ultimately be materially
greater than estimated at the time of the acquisition.
We are continually investigating opportunities for acquisitions. In connection with future
acquisitions, the process of integrating acquired operations into our existing operations may
result in unforeseen operating difficulties and may require significant management attention and
financial resources that would otherwise be available for the ongoing development or expansion of
existing operations. Our ability to make future acquisitions may be constrained by our ability to
obtain additional financing.
Possible future acquisitions could result in our incurring additional debt, contingent
liabilities and expense, all of which could have a material adverse effect on our financial
condition and operating results.
We could experience delays in securing drilling equipment and crews, which would cause us to fail
to meet our drilling plans and negatively impact our operations.
We utilize drilling contractors to perform all of the drilling on our projects. We maintain
a limited number of supervisory and field personnel to oversee drilling and production operations.
Our plans to drill additional wells are determined in large part by the anticipated availability of
acceptable drilling equipment and crews. We do not currently have any contractual commitments that
ensure we will have adequate drilling equipment or crews to achieve our drilling plans. If our
anticipated levels of drilling equipment are not made available to us, we will have to modify our
drilling plans, which would cause us to fail to meet our drilling plans and negatively impact our
operations. If we cannot meet our drilling plans, the value of your investment in us may decline.
The marketability of our natural gas production depends on facilities that we typically do not own
or control.
The marketability of our natural gas production depends in part upon the availability,
proximity and capacity of natural gas gathering systems, pipelines and processing facilities. We
generally deliver natural gas through natural gas gathering systems and natural gas pipelines that
we do not own. Our ability to produce and market natural gas on a commercial basis could be harmed
by any significant change in the cost or availability of such systems and pipelines.
Our producing properties are geographically concentrated.
A substantial portion of our proved oil and natural gas reserves are located in the Permian
Basin of West Texas and Eastern New Mexico. Specifically, as of December 31, 2007, approximately
93.5% of the present value of our estimated future net revenues from our proved reserves relates to
our proved reserves located in the Permian Basin. As a result, we may be disproportionately exposed
to the impact of delays or interruptions of production from these wells due to mechanical problems,
damages to the current producing reservoirs, significant governmental regulation, including any
curtailment of production, or interruption of transportation of oil or natural gas produced from
the wells.
Our derivative activities create a risk of financial loss.
In order to manage our exposure to price risks in the marketing of our oil and natural gas, we
have in the past and expect to continue to enter into oil and natural gas price risk management
arrangements with respect to a portion of our expected production. We use derivative arrangements
such as swaps, puts and collars that generally result in a fixed price or a range of minimum and
maximum price limits over a specified time period. Certain derivative contracts may limit the
benefits we could realize if actual prices received are above the contract price. In a typical
derivative transaction utilizing a swap arrangement, we will have the right to receive from the
counterparty the excess of the fixed price specified in the contract over a floating price based on
a market index, multiplied by the quantity identified in the derivative contract. If the floating
price exceeds the fixed price, we are required to pay the counterparty this difference multiplied
by the quantity identified in the derivative contract. Derivative arrangements could prevent us
from receiving the full advantage of increases in oil or natural gas prices above the fixed amount
specified in the derivative contract. In addition, these transactions may expose us to the risk of
financial loss in certain circumstances, including instances in which:
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the counterparties to our future contracts fail to perform under the contract; or |
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a sudden, unexpected event materially impacts oil or natural gas prices. |
(17)
In the past, some of our derivative contracts required us to deliver cash collateral or other
assurances of performance to the counterparties in the event that our payment obligations exceeded
certain levels. Future collateral requirements are uncertain but will depend on arrangements with
our counterparties and highly volatile oil and natural gas prices.
In addition, increases in oil and natural gas prices negatively affect the fair value of
certain of our derivatives contracts as recorded in our balance sheet and, consequently, our
reported net income. Changes in the recorded fair value of certain of our derivatives contracts are
marked to market through earnings and the decrease in the fair value of these contracts during any
period could result in significant charges to earnings. The increase in oil and natural gas prices,
should it continue, will cause this negative effect on earnings to become more significant. We are
currently unable to estimate the effects on earnings in future periods, but the effects could be
significant.
We are subject to complex federal, state and local laws and regulations that could adversely affect
our business.
Extensive federal, state and local regulation of the oil and natural gas industry
significantly affects our operations. In particular, our oil and natural gas exploration,
development and production activities are subject to stringent environmental regulations. These
regulations have increased the costs of planning, designing, drilling, installing, operating and
abandoning our oil and natural gas wells and other related facilities. These regulations may become
more demanding in the future. Matters subject to regulation include:
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permits for drilling operations; |
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drilling bonds; |
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spacing of wells; |
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unitization and pooling of properties; |
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environmental protection; |
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reports concerning operations; and |
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taxation. |
Under these laws and regulations, we could be liable for:
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personal injuries; |
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property damage; |
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oil spills; |
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discharge of hazardous materials; |
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reclamation costs; |
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remediation and clean-up costs; and |
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other environmental damages. |
Failure to comply with these laws and regulations also may result in the suspension or
terminations of our operations and subject us to administrative, civil and criminal penalties.
Further, these laws and regulations could change in ways that substantially increase our costs. Any
of these liabilities, penalties, suspensions, terminations or regulatory changes could make it more
expensive for us to conduct our business or cause us to limit or curtail some of our operations.
(18)
Declining oil and natural gas prices may cause us to record ceiling test write-downs.
We use the full cost method of accounting to account for our oil and natural gas operations.
This means that we capitalize the costs to acquire, explore for and develop oil and natural gas
properties. Under full cost accounting rules, the capitalized costs of oil and natural gas
properties may not exceed a ceiling limit, which is based on the present value of estimated future
net revenues, net of income tax effects, from proved reserves, discounted at 10%, plus the lower of
cost or fair market value of unproved properties. These rules generally require pricing future oil
and natural gas production at unescalated oil and natural gas prices in effect at the end of each
fiscal quarter, with effect given to cash flow hedge positions. If our capitalized costs of oil and
natural gas properties, net of related deferred taxes, exceed the ceiling limit, we must charge the
amount of the excess against earnings. This is called a ceiling test write-down. This non-cash
impairment charge does not affect cash flow from operating activities, but it does reduce
stockholders equity. Generally, impairment charges cannot be restored by subsequent increases in
the prices of oil and natural gas.
The risk that we will be required to write-down the carrying value of our oil and natural gas
properties increases when oil and natural gas prices decline. In addition, write-downs may occur if
we experience substantial downward adjustments to our estimated proved reserves.
We did not recognize an impairment in 2007. We cannot assure you that we will not experience
ceiling test write-downs in the future.
Terrorist activities may adversely affect our business.
Terrorist activities, including events similar to those of September 11, 2001, or armed
conflict involving the United States may adversely affect our business activities and financial
condition. If events of this nature occur and persist, the resulting political and social
instability could adversely affect prevailing oil and natural gas prices and cause a reduction in
our revenues. In addition, oil and natural gas production facilities, transportation systems and
storage facilities could be direct targets of terrorist attacks, and our operations could be
adversely impacted if infrastructure integral to our operations is destroyed or damaged. Costs
associated with insurance and other security measures may increase as a result of these threats,
and some insurance coverage may become more difficult to obtain, if available at all.
We are highly dependent upon key personnel.
Our success is highly dependent upon the services, efforts and abilities of key members of our
management team. Our operations could be materially and adversely affected if one or more of these
individuals become unavailable for any reason.
We do not have employment agreements with any of our officers or other key employees. Without
these agreements, our ability to obtain and retain qualified officers and employees may be
adversely affected, especially in periods of improving market conditions.
Our future growth and profitability will also be dependent upon our ability to attract and
retain other qualified management personnel and to effectively manage our growth. There can be no
assurance that we will be successful in doing so.
Part of our business is seasonal in nature.
Weather conditions affect the demand for and price of oil and natural gas and can also delay
drilling activities, temporarily disrupting our overall business plans. Demand for oil and natural
gas is typically higher during winter months than summer months. However, warm winters can also
lead to downward price trends. As a result, our results of operations may be adversely affected by
seasonal conditions.
Failure to maintain effective internal controls could have a material adverse effect on our
operations.
Section 404 of the Sarbanes-Oxley Act requires annual management assessments of the
effectiveness of our internal control over financial reporting. Effective internal controls are
necessary for us to produce reliable financial reports. If, as a result of deficiencies in our
internal controls, we cannot provide reliable financial reports, our business decision process may
be adversely affected, our business and operating results could be harmed, and investors could lose
confidence in our reported financial information.
(19)
Our business can be adversely impacted by downward changes in oil and natural gas prices, and most
significantly by declines in oil prices.
Our revenues, cash flows and profitability are substantially dependent on prevailing oil and
natural gas prices, which are volatile. Declines in oil and natural gas prices would not only
reduce revenue, but could reduce the amount of oil and natural gas that we can produce economically
and, as a result, could have a material adverse effect on our financial condition, results of
operations and reserves. Further, oil and natural gas prices do not necessarily move in tandem.
Because approximately 87.0% of our estimated future revenues from our proved reserves as of
December 31, 2007 are from oil production, we will be more affected by movements in oil prices.
A shortage of available drilling rigs, equipment and personnel may delay or restrict our
operations.
The oil and natural gas industry is cyclical and, from time to time, there is a shortage of
drilling rigs, equipment, supplies or personnel. During these periods, the costs and delivery times
of drilling rigs, equipment and supplies are substantially greater. In addition, demand for, and
wage rates of, qualified drilling rig crews rise with increases in the number of active rigs in
service. Shortages of drilling rigs, equipment, supplies or personnel may increase drilling costs
or delay or restrict our exploration and development operations, all or any one of which could harm
our business financial condition and results of operations.
Risks Relating to Our Common Stock
We do not pay dividends on our common stock.
We have never paid dividends on our common stock, and do not intend to pay cash dividends on
the common stock in the foreseeable future. Net income from our operations, if any, will be used
for the development of our business, including capital expenditures and to retire debt. Any
decisions to pay dividends on the common stock in the future will depend upon our profitability at
the time, the available cash and other factors. Our ability to pay dividends on our common stock is
further limited by the terms of our revolving credit facility and the Indenture governing our 101/4%
senior notes
Our stockholders rights plan, provisions in our corporate governance documents and Delaware law
may delay or prevent an acquisition of Parallel, which could decrease the value of our common
stock.
Our certificate of incorporation, our bylaws and the Delaware General Corporation Law contain
provisions that may discourage other persons from initiating a tender offer or takeover attempt
that a stockholder might consider to be in the best interest of all stockholders, including
takeover attempts that might result in a premium to be paid over the market price of our stock.
On October 5, 2000, our Board of Directors adopted a stockholder rights plan. The plan is
designed to protect Parallel from unfair or coercive takeover attempts and to prevent a potential
acquirer from gaining control of Parallel without fairly compensating all of the stockholders. The
plan authorized 50,000 shares of $0.10 par Series A Preferred Stock Purchase Rights. A dividend of
one Right for each share of our outstanding common stock was distributed to stockholders of record
at the close of business on October 16, 2000. If a public announcement is made that a person has
acquired 15% or more of our common stock, or a tender or exchange offer is made for 15% of more of
the common stock, each Right entitles the holder to purchase from the company one one-thousandth of
a share of Series A Preferred Stock, at an exercise price of $26.00 per one one-thousandth of a
share, subject to adjustment. In addition, under certain circumstances, the rights entitle the
holders to buy Parallels stock at a 50% discount. We are authorized to issue 10.0 million shares
of preferred stock; there are no outstanding shares as of December 31, 2007. Our Board of Directors
has total discretion in the issuance and the determination of the rights and privileges of any
shares of preferred stock which might be issued in the future, which rights and privileges may be
detrimental to the holders of the common stock. It is not possible to state the actual effect of
the authorization and issuance of a new series of preferred stock upon the rights of holders of the
common stock and other series of preferred stock unless and until the Board of Directors determines
the attributes of any new series of preferred stock and the specific rights of its holders. These
effects might include:
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restrictions on dividends on common stock and other series of preferred stock if
dividends on any new series of preferred stock have not been paid; |
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dilution of the voting power of common stock and other series of preferred stock to
the extent that a new series of preferred stock has voting rights, or to the extent
that any new series of preferred stock is convertible into common stock; |
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dilution of the equity interest of common stock and other series of preferred stock;
and |
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limitation on the right of holders of common stock and other series of preferred
stock to share in Parallels assets upon liquidation until satisfaction of any
liquidation preference attributable to any new series of preferred stock. |
The issuance of preferred stock in the future could discourage, delay or prevent a tender
offer, proxy contest or other similar transaction involving a potential change in control of
Parallel that might be viewed favorably by stockholders.
Future sales of our common stock could adversely affect our stock prices.
Substantial sales of our common stock in the public market, or the perception by the market
that those sales could occur, may lower our stock price or make it difficult for us to raise
additional equity capital in the future. These potential sales could include sales of our common
stock by our directors and officers, who beneficially owned approximately 3.35% of the outstanding
shares of our common stock as of February 14, 2008.
The price of our common stock may fluctuate which may cause our common stock to trade at a
substantially lower price than the price which you paid for our common stock.
The trading price of our common stock and the price at which we may sell securities in the
future is subject to substantial fluctuations in response to various factors, including any of the
following: our ability to successfully accomplish our business strategy; the trading volume in our
stock; changes in governmental regulations; actual or anticipated variations in our quarterly or
annual financial results; our involvement in litigation; general market conditions; the prices of
oil and natural gas; our ability to economically replace our reserves; announcements by us and our
competitors; our liquidity; our ability to raise additional funds; and other events.
If securities analysts downgrade our stock or cease coverage of us, the price of our stock could
decline.
The trading market for our common stock relies in part on the research and reports that
industry or financial analysts publish about us or our business. We do not control these analysts.
Furthermore, there are many large, well-established, publicly traded companies active in our
industry and market, which may mean that it is less likely that we will receive widespread analyst
coverage. If one or more of the analysts who do cover us downgrade our stock, our stock price would
likely decline rapidly. If one or more of these analysts cease coverage of our company, we could
lose visibility in the market, which in turn could cause our stock price to decline.
Risks Relating to Our 10 1/4% Senior Notes and Our Other Indebtedness
We have a substantial amount of indebtedness, which may adversely affect our cash flow and our
ability to operate our business, remain in compliance with debt covenants and make payments on our
debt, including our 10 1/4% senior notes.
As of December 31, 2007, we had total debt of approximately $205.4 million (of which $150.0
million consisted of our 101/4% senior notes due 2014 net of $4.6 million in unamortized issue
discount and $60.0 million consisted of borrowings under our revolving credit facility, excluding
letters of credit). Our level of debt could have important consequences for you, including the
following:
|
|
|
we may have difficulty borrowing money in the future for acquisitions, capital
expenditures or to meet our operating expenses or other general corporate obligations; |
|
|
|
|
we will need to use a substantial portion of our cash flows to pay principal and
interest on our debt, which will reduce the amount of money we have for operations,
working capital, capital expenditures, expansion, acquisitions or general corporate or
other business activities; |
|
|
|
|
we may have a higher level of debt than some of our competitors, which may put us at
a competitive disadvantage; |
(21)
|
|
|
we may be more vulnerable to economic downturns and adverse developments in our
industry or the economy in general, especially declines in oil and natural gas prices;
and |
|
|
|
|
our debt level could limit our flexibility in planning for, or reacting to, changes
in our business and the industry in which we operate. |
We may incur substantially more debt, which may intensify the risks described above, including our
ability to service our indebtedness.
We
may be able to incur substantially more debt in the future. Although the Indenture
governing our 101/4% senior notes and the amended and restated credit agreement governing our
revolving credit facility contain restrictions on our incurrence of additional indebtedness, these
restrictions are subject to a number of qualifications and exceptions, and under certain
circumstances, indebtedness incurred in compliance with these restrictions could be substantial. As
of December 31, 2007, we had approximately $140.0 million of additional borrowing capacity under
our revolving credit facility, excluding letters of credit, subject to specific requirements,
including compliance with financial covenants. In addition, the
Indenture governing our 101/4% senior
notes and our revolving credit facility do not prevent us from incurring obligations that do not
constitute indebtedness. To the extent new indebtedness is added to our current indebtedness
levels, the risks described above could substantially intensify.
To service our indebtedness, we will require a significant amount of cash. Our ability to generate
cash depends on many factors beyond our control, and any failure to meet our debt obligations could
harm our business, financial condition and results of operations.
Our ability to make payments on and to refinance our indebtedness, including the 101/4% senior
notes, and to fund planned capital expenditures will depend on our ability to generate cash from
operations in the future. This, to a certain extent, is subject to general economic, financial,
competitive, legislative, regulatory and other factors that are beyond our control, including the
prices that we receive for oil and natural gas. We cannot assure you that our business will
generate sufficient cash flow from operations or that future borrowings will be available to us
under our revolving credit facility in an amount sufficient to enable us to pay our indebtedness,
including the notes, or to fund our other liquidity needs.
If our cash flow and capital resources are insufficient to fund our debt obligations, we may
be forced to sell assets, seek additional equity or debt capital or restructure our debt. The
Indenture governing our 101/4% senior notes and the amended and restated credit agreement governing
our revolving credit facility restrict our ability to dispose of assets and use the proceeds
from the disposition. We cannot assure you that any of these remedies could, if necessary, be
effected on commercially reasonable terms, or at all. In addition, any failure to make scheduled
payments of interest and principal on our outstanding indebtedness, including our revolving credit
facility, would likely result in a reduction of our credit rating, which could harm our ability to
incur additional indebtedness on acceptable terms. If we fail to meet our payment obligations under
our revolving credit facility, those lenders would be entitled to foreclose on substantially all of
our assets and liquidate those assets. Under those circumstances, our cash flow and capital
resources could be insufficient for payment of interest on and principal of our debt in the future,
including payments on our 101/4% senior notes, and any such alternative measures may be unsuccessful
or may not permit us to meet scheduled debt service obligations, which could cause us to default on
our obligations, impair our liquidity, or cause the holders of our 101/4% senior notes to lose a
portion of or the entire value of their investment.
A default on our obligations could result in:
|
|
|
our debt holders declaring all outstanding principal and interest due and payable; |
|
|
|
|
the lenders under our revolving credit facility terminating their commitments to
loan us money and foreclose against the assets securing their loans to us; and |
|
|
|
|
our bankruptcy or liquidation, which is likely to result in delays in the payment of
our
101/4%
senior notes and in the exercise of enforcement remedies under our 101/4% senior
notes. |
In addition, provisions under the bankruptcy code or general principles of equity that could
result in the impairment of your rights include the automatic stay, avoidance of preferential
transfers by a trustee or a debtor-in-possession, limitations of collectibility of unmatured
interest or attorneys fees and forced restructuring of our 101/4% senior notes.
(22)
Restrictive debt covenants in the Indenture and the amended and restated credit agreement governing
our revolving credit facility restrict our business in many ways.
The Indenture governing our 101/4% senior notes contains a number of significant covenants that,
among other things, restrict our ability to:
|
|
|
transfer or sell assets; |
|
|
|
|
make investments; |
|
|
|
|
pay dividends, redeem subordinated indebtedness or make other restricted payments; |
|
|
|
|
incur or guarantee additional indebtedness or issue disqualified capital stock; |
|
|
|
|
create or incur liens; |
|
|
|
|
incur dividend or other payment restrictions affecting certain subsidiaries; |
|
|
|
|
consummate a merger, consolidation or sale of all or substantially all of our
assets; |
|
|
|
|
enter into transactions with affiliates; and |
|
|
|
|
engage in businesses other than the oil and gas business. |
These covenants could limit our ability to obtain future financings, make needed capital
expenditures, withstand a future downturn in our business or the economy in general or otherwise
conduct necessary corporate activities. We may also be prevented from taking advantage of business
opportunities that arise because of the limitations that the restrictive covenants impose on us. A
breach of any of these covenants could result in a default under the 101/4% senior notes which, if
not cured or waived, could result in acceleration of the 101/4% senior notes.
In addition, the amended and restated credit agreement governing our revolving credit facility
contains restrictive covenants and requires us to maintain specified financial ratios and satisfy
other financial condition tests. Our ability to meet those financial ratios and tests can be
affected by events beyond our control, and we cannot assure you that we will meet those tests. A
breach of any of these covenants could result in a default under the facility. Upon the occurrence
of an event of default, the lenders could elect to declare all amounts outstanding to be
immediately due and payable and terminate all commitments to extend further credit. If we were
unable to repay those amounts, the lenders could proceed against the collateral granted to them to
secure that indebtedness. We have pledged substantially all of our assets as collateral under the
revolving credit facility. If the lenders accelerate the repayment of borrowings, we cannot assure
you that we will have sufficient assets to repay our revolving credit facility and our other
indebtedness, including the 101/4% senior notes.
Our borrowings under our revolving credit facility expose us to interest rate risk.
Our borrowings under our revolving credit facility are, and are expected to continue to be, at
variable rates of interest and expose us to interest rate risk. If interest rates increase, our
debt service obligations on the variable rate indebtedness would increase even though the amount
borrowed remained the same, and our net income would decrease.
We are subject to many restrictions under our revolving credit facility. If we default under our
revolving credit facility, the lenders could foreclose on, and acquire control of, substantially
all of our assets.
Our revolving credit facility limits the amounts we can borrow to a borrowing base amount,
determined by the lenders in their sole discretion, based upon projected revenues from the oil and
natural gas properties securing our loan. The lenders can unilaterally adjust the borrowing base
and the borrowings permitted to be outstanding under the revolving credit facility. Any increase in
the borrowing base requires the consent of all lenders. If all lenders do not agree on an increase,
then the borrowing base will be the lowest borrowing base determined by any lender. Outstanding
borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other oil
and natural gas properties as additional collateral. We do not currently have any substantial
properties that are not pledged and no assurance can be given that we would be able to make any
mandatory principal prepayments required under the revolving credit facility.
(23)
The lenders under our revolving credit facility have liens on substantially all of our assets.
Additionally, the revolving credit facility restricts our ability to obtain additional financing,
make investments, lease equipment, sell assets and engage in business combinations. We are also
required to comply with certain financial covenants and ratios under this facility. Although we
were in compliance with these covenants at December 31, 2007, in the past we have had to request
waivers from our banks because of our non-compliance with certain financial covenants and ratios.
Our ability to comply with these restrictions and covenants in the future is uncertain and will be
affected by the levels of cash flow from our operations and events or circumstances beyond our
control. As a result of the liens held by our lenders, if we fail to meet our payment or other
obligations under this credit facility, including our failure to meet any of the required financial
covenants or ratios, the lenders would be entitled to foreclose on substantially all of our assts
and liquidate those assets. Our failure to comply with any of the restrictions and covenants under
the revolving credit facility could result in a default under both the revolving credit facility
and the Indenture governing our 101/4% senior notes, which could cause all of our existing
indebtedness to be immediately due and payable.
Our 101/4% senior notes are structurally subordinated to any of our secured indebtedness to the
extent of the assets securing such indebtedness.
Our obligations under the 101/4% senior notes are unsecured, but our obligations under our
revolving credit facility are secured by liens on substantially all of our assets. Holders of this
indebtedness and any other secured indebtedness that we may incur in the future will have claims
with respect to our assets constituting collateral for such indebtedness that are prior to claims
of holders of the 101/4% senior notes. In the event of a default on such secured indebtedness or our
bankruptcy, liquidation or reorganization, those assets would be available to satisfy obligations
with respect to the indebtedness secured thereby before any payment could be made on the 101/4%
senior notes. Accordingly, any such secured indebtedness will effectively be senior to the 101/4%
senior notes to the extent of the value of the collateral securing the indebtedness. While the
Indenture governing the 101/4% senior notes places some limitations on our ability to create liens,
there are significant exceptions to these limitations that will allow us to secure some kinds of
indebtedness without equally and ratably securing the 101/4% senior notes, including any future
indebtedness we may incur under a credit facility. To the extent the value of the collateral is not
sufficient to satisfy our secured indebtedness, the holders of that indebtedness would be entitled
to share with the holders of the 101/4% senior notes and the holders of other claims against us with
respect to our other assets. As of December 31, 2007, we had approximately $60 million in secured
indebtedness outstanding under our revolving credit facility, excluding letters of credit.
A subsidiary guarantee could be voided if it constitutes a fraudulent transfer under U.S.
bankruptcy or similar state laws, which would prevent the holders of our 101/4% senior notes from
relying on the subsidiary to satisfy our payment obligations under the 101/4% senior notes.
Initially, there will be no subsidiary guarantees of the 101/4% senior notes, but in the future
such guarantees may occur. Federal and state statutes allow courts, under specific circumstances,
to void subsidiary guarantees, or require that claims under the subsidiary guarantee be
subordinated to all other debts of the subsidiary guarantor, and to require creditors such as the
noteholders to return payments received from subsidiary guarantors. Under federal bankruptcy law
and comparable provisions of state fraudulent transfer laws, a subsidiary guarantee could be voided
or claims in respect of a subsidiary guarantee could be subordinated to all other debts of that
subsidiary guarantor if, for example, the subsidiary guarantor, at the time it issued its
subsidiary guarantee:
|
|
|
was insolvent or rendered insolvent by making the subsidiary guarantee; |
|
|
|
|
was engaged in a business or transaction for which the subsidiary guarantors
remaining assets constituted unreasonably small capital; or |
|
|
|
|
intended to incur, or believed that it would incur, debts beyond its ability to pay
them as they mature. |
A guarantee may also be voided, without regard to the above factors, if a court found that the
guarantor entered into the guarantee with the actual intent to hinder, delay or defraud any present
or future creditor or received less than reasonably equivalent value or fair compensation for the
subsidiary guarantee. A court would likely find that a guarantor did not receive reasonably
equivalent value or fair compensation for its guarantee if the guarantor did not substantially
benefit directly or indirectly from the issuance of the guarantees.
(24)
The measures of insolvency for purposes of these fraudulent transfer laws will vary depending
upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred.
Generally, a subsidiary guarantor would be considered insolvent if:
|
|
|
the sum of its debts, including contingent liabilities, was greater than the fair
saleable value of all of its assets; |
|
|
|
|
the present fair saleable value of its assets was less than the amount that would be
required to pay its probable liability on its existing debts, including contingent
liabilities, as they become absolute and mature; or |
|
|
|
|
it could not pay its debts as they become due. |
To the extent a court voids a subsidiary guarantee as a fraudulent transfer or holds the
subsidiary guarantee unenforceable for any other reason, holders of 101/4% senior notes would cease
to have any direct claim against the subsidiary guarantor. If a court were to take this action, the
subsidiary guarantors assets would be applied first to satisfy the subsidiary guarantors
liabilities, if any, before any portion of its assets could be distributed to us to be applied to
the payment of the 101/4% senior notes. We cannot assure you that a subsidiary guarantors remaining
assets would be sufficient to satisfy the claims of the holders of 101/4% senior notes related to any
voided portions of the subsidiary guarantees.
We may not have sufficient liquidity to repurchase the 101/4% senior notes upon a change of control.
Upon the occurrence of a change of control, holders of 101/4% senior notes will have the right
to require us to repurchase all or any part of such holders 101/4% senior notes at a price equal to
101% of the principal amount of the 101/4% senior notes, plus accrued and unpaid interest, if any,
to the date of repurchase. We may not have sufficient funds at the time of the change of control to
make the required repurchases, or restrictions under our revolving credit facility may not allow
such repurchases. In addition, an event constituting a change of control (as defined in the
indenture governing the 101/4% senior notes) could be an event of default under our revolving credit
facility that would, if it should occur, permit the lenders to accelerate that debt and that, in
turn, would cause an event of default under the indenture governing the 101/4% senior notes, each of
which could have material adverse consequences for us and the holders of the 101/4% senior notes. The
source of any funds for any repurchase required as a result of a change of control will be our
available cash or cash generated from our business operations or other sources, including
borrowings, sales of assets, sales of equity or funds provided by a new controlling entity. We
cannot assure you, however, that sufficient funds would be available at the time of any change of
control to make any required repurchases of the 101/4% senior notes tendered and to repay debt under
our revolving credit facility.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
We have not received any written comments from the staff of the Securities and Exchange
Commission that remain unresolved.
(25)
ITEM 2. PROPERTIES
General
Our principal properties consist of working interests in developed and undeveloped oil and
natural gas leases and the reserves associated with those leases. Generally, developed oil and
natural gas leases remain in force so long as production is maintained. Undeveloped oil and natural
gas leaseholds are generally for a primary term of five or ten years. In most cases, we can extend
the term of our undeveloped leases by paying delay rentals or by producing reserves that we
discover under our leases.
The map below shows our principal areas of operations.
(26)
Producing Wells and Acreage
We have presented the table below to provide you with a summary of the producing oil and
natural gas wells and the developed and undeveloped acreage in which we owned an interest at
December 31, 2007. We have not included in the table acreage in which our interest is limited to
options to acquire leasehold interests, royalty or similar interests. Also excluded are 150 gross
wells for which we were serving as operator at December 31, 2007, but in which we did not own an
interest.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing Wells(1) |
|
Acreage |
|
|
Oil(2) |
|
Gas |
|
Developed |
|
Undeveloped |
|
|
Gross |
|
Net(3) |
|
Gross |
|
Net(3) |
|
Gross |
|
Net(4) |
|
Gross |
|
Net(4) |
Resource Projects |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
|
|
|
|
|
|
|
|
|
|
55 |
|
|
|
14.68 |
|
|
|
2,400 |
|
|
|
785 |
|
|
|
26,363 |
|
|
|
7,774 |
|
New Mexico |
|
|
|
|
|
|
|
|
|
|
69 |
|
|
|
32.30 |
|
|
|
13,877 |
|
|
|
8,920 |
|
|
|
92,480 |
|
|
|
68,347 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Resource Projects |
|
|
|
|
|
|
|
|
|
|
124 |
|
|
|
46.98 |
|
|
|
16,277 |
|
|
|
9,705 |
|
|
|
118,843 |
|
|
|
76,121 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin of West Texas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fullerton |
|
|
151 |
|
|
|
127.50 |
|
|
|
|
|
|
|
|
|
|
|
3,683 |
|
|
|
3,155 |
|
|
|
|
|
|
|
|
|
Carm-Ann/N. Means Queen |
|
|
89 |
|
|
|
75.84 |
|
|
|
|
|
|
|
|
|
|
|
5,560 |
|
|
|
4,843 |
|
|
|
235 |
|
|
|
235 |
|
Harris |
|
|
69 |
|
|
|
61.75 |
|
|
|
|
|
|
|
|
|
|
|
1,303 |
|
|
|
1,176 |
|
|
|
1,816 |
|
|
|
1,783 |
|
Diamond M |
|
|
50 |
|
|
|
32.94 |
|
|
|
|
|
|
|
|
|
|
|
5,805 |
|
|
|
3,809 |
|
|
|
|
|
|
|
|
|
Other Permian |
|
|
73 |
|
|
|
31.66 |
|
|
|
28 |
|
|
|
12.67 |
|
|
|
23,079 |
|
|
|
15,469 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Permian Basin |
|
|
432 |
|
|
|
329.69 |
|
|
|
28 |
|
|
|
12.67 |
|
|
|
39,430 |
|
|
|
28,452 |
|
|
|
2,051 |
|
|
|
2,018 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Onshore Gulf Coast of South Texas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Yegua/Frio/Wilcox |
|
|
3 |
|
|
|
0.62 |
|
|
|
34 |
|
|
|
8.45 |
|
|
|
4,732 |
|
|
|
1,993 |
|
|
|
2,734 |
|
|
|
1,022 |
|
Cook Mountain |
|
|
|
|
|
|
|
|
|
|
12 |
|
|
|
1.31 |
|
|
|
1,059 |
|
|
|
150 |
|
|
|
74 |
|
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Onshore Gulf Coast
of South Texas |
|
|
3 |
|
|
|
0.62 |
|
|
|
46 |
|
|
|
9.76 |
|
|
|
5,791 |
|
|
|
2,143 |
|
|
|
2,808 |
|
|
|
1,036 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Projects |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cotton Valley |
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
0.30 |
|
|
|
561 |
|
|
|
74 |
|
|
|
10,463 |
|
|
|
1,077 |
|
Utah/Colorado |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
163,196 |
|
|
|
155,454 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Other Projects |
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
0.30 |
|
|
|
561 |
|
|
|
74 |
|
|
|
173,659 |
|
|
|
156,531 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grand Total |
|
|
435 |
|
|
|
330.31 |
|
|
|
200 |
|
|
|
69.71 |
|
|
|
62,059 |
|
|
|
40,374 |
|
|
|
297,361 |
|
|
|
235,706 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Does not include 175 gross (79.07 net) wells that were shut in or temporarily abandoned as of
December 31, 2007. |
|
(2) |
|
Does not include 128 gross (98.30 net) injection wells as of December 31, 2007. |
|
(3) |
|
Net wells are computed by multiplying the number of gross wells by our working interest in the
gross wells. |
|
(4) |
|
Net acres are computed by multiplying the number of gross acres by our working interest in the
gross acres. |
At December 31, 2007, we owned interests in 369 gross (306.55 net) oil and natural gas wells
for which we were the operator and 569 gross (270.84 net) oil and natural gas wells where we were
not the operator.
The operator of a well has significant control over its location and the timing of its
drilling. In addition, the operator receives fees from other working interest owners as
reimbursement for general and administrative expenses for operating the wells.
Except for our oil and natural gas leases and related and seismic data, we do not own any
patents, licenses, franchises or concessions which are significant to our oil and natural gas
operations.
For a more detailed description of our exploration and development activities, you should read
Item 1, Business Current Drilling Projects beginning on page 5 of this Annual Report on Form
10-K.
(27)
Title to Properties
As in customary in the oil and natural gas industry, we make only a cursory review of title to
undeveloped oil and natural gas leases at the time they are acquired. These cursory title reviews,
while consistent with industry practices, are necessarily incomplete. We believe that it is not
economically feasible to review in depth every individual property we acquire, especially in the
case of producing property acquisitions covering a large number of leases. Ordinarily, when we
acquire producing properties, we focus our review efforts on properties believed to have higher
values and will sample the remainder. However, even an in-depth review of all properties and
records may not necessarily reveal existing or potential defects nor will it permit a buyer to
become sufficiently familiar with the properties to assess fully their deficiencies and
capabilities. In the case of producing property acquisitions, inspections may not always be
performed on every well, and environmental problems, such as ground water contamination, are not
necessarily observable even when an inspection is undertaken. In the case of undeveloped leases or
prospects we acquire, before any drilling commences, we will usually cause a more thorough title
search to be conducted, and any material defects in title that are found as a result of the title
search are generally remedied before drilling a well on the lease commences. We believe that we
have good title to our oil and natural gas properties, some of which are subject to immaterial
encumbrances, easements and restrictions. The oil and natural gas properties we own are also
typically subject to royalty and other similar non-cost bearing interests customary in the
industry. We do not believe that any of these encumbrances or burdens will materially affect our
ownership or the use of our properties.
Oil and Natural Gas Reserves
For the year ended December 31, 2007, our oil and natural gas reserves were estimated by
Cawley Gillespie & Associates, Inc., Fort Worth, Texas.
At December 31, 2007, our total estimated proved reserves were approximately 28.4 MMBbls of
oil and approximately 57.2 Bcf of natural gas, or 38.0 MMBOE.
The information in the following table provides you with certain information regarding our
proved reserves as estimated by Cawley Gillespie & Associates, Inc. at December 31, 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed |
|
Proved Developed |
|
Proved |
|
Total |
|
|
Producing |
|
Non-Producing |
|
Undeveloped |
|
Proved |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
13,570 |
|
|
|
808 |
|
|
|
14,056 |
|
|
|
28,434 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (MMcf) |
|
|
41,375 |
|
|
|
181 |
|
|
|
15,678 |
|
|
|
57,234 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MBOE |
|
|
20,466 |
|
|
|
838 |
|
|
|
16,669 |
|
|
|
37,973 |
|
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural
gas liquids which geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and operating conditions
(i.e., prices and costs as of the date the estimate is made). Proved developed reserves are
reserves that can be expected to be recovered through existing wells with existing equipment and
operating methods. Proved undeveloped reserves are reserves that are expected to be recovered from
new wells on undrilled acreage, or from existing wells where a relatively major expenditure is
required for recompletion.
(28)
The table below shows the production from our oil and natural gas properties for the year
ended December 31, 2007 and the proved reserves attributable to those properties as of December 31, 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserves |
|
|
Production |
|
Total Proved |
|
Proved Developed |
|
|
|
|
|
|
Natural |
|
|
|
|
|
|
|
|
|
Natural |
|
|
|
|
|
Natural |
|
|
Oil |
|
Gas |
|
|
|
|
|
Oil |
|
Gas |
|
Oil |
|
Gas |
|
|
(MBbls) |
|
(MMcf) |
|
BOE |
|
(MBbls) |
|
(MMcf) |
|
(MBbls) |
|
(MMcf) |
Resource Projects |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
|
|
|
|
|
|
3,030 |
|
|
|
505 |
|
|
|
|
|
|
|
17,714 |
|
|
|
|
|
|
|
14,530 |
|
New Mexico Wolfcamp |
|
|
4 |
|
|
|
2,731 |
|
|
|
459 |
|
|
|
1 |
|
|
|
24,284 |
|
|
|
1 |
|
|
|
17,150 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Resource Projects |
|
|
4 |
|
|
|
5,761 |
|
|
|
964 |
|
|
|
1 |
|
|
|
41,998 |
|
|
|
1 |
|
|
|
31,680 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin of West Texas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fullerton |
|
|
536 |
|
|
|
110 |
|
|
|
554 |
|
|
|
9,358 |
|
|
|
1,744 |
|
|
|
8,945 |
|
|
|
1,661 |
|
Carm-Ann San
Andres/N. Means Queen |
|
|
161 |
|
|
|
146 |
|
|
|
186 |
|
|
|
6,554 |
|
|
|
4,159 |
|
|
|
1,694 |
|
|
|
1,161 |
|
Harris |
|
|
194 |
|
|
|
42 |
|
|
|
201 |
|
|
|
8,086 |
|
|
|
1,113 |
|
|
|
2,362 |
|
|
|
467 |
|
Diamond M |
|
|
80 |
|
|
|
107 |
|
|
|
98 |
|
|
|
3,855 |
|
|
|
2,195 |
|
|
|
796 |
|
|
|
562 |
|
Other Permian Basin |
|
|
45 |
|
|
|
306 |
|
|
|
96 |
|
|
|
479 |
|
|
|
3,154 |
|
|
|
479 |
|
|
|
3,154 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Permian Basin |
|
|
1,016 |
|
|
|
711 |
|
|
|
1,135 |
|
|
|
28,332 |
|
|
|
12,365 |
|
|
|
14,276 |
|
|
|
7,005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Onshore Gulf Coast of South Texas |
|
|
31 |
|
|
|
950 |
|
|
|
189 |
|
|
|
101 |
|
|
|
2,871 |
|
|
|
101 |
|
|
|
2,871 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
1,051 |
|
|
|
7,422 |
|
|
|
2,288 |
|
|
|
28,434 |
|
|
|
57,234 |
|
|
|
14,378 |
|
|
|
41,556 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimates of our proved reserves and future net revenues are made using sales prices and
costs, estimated to be in effect as of the date of our reserve estimates that are held constant
throughout the life of the properties, except to the extent a contract specifically provides for
escalation of prices or costs. The average prices utilized in the estimation of our reserve
calculations as of December 31, 2007 were $89.93 per Bbl of oil and $6.77 per Mcf of natural gas.
For additional information concerning our estimated proved oil and natural gas reserves, you
should read Note 16 to the Consolidated Financial Statements.
The reserve data in this Annual Report on Form 10-K represent estimates only. Reservoir
engineering is a subjective process. There are numerous uncertainties inherent in estimating our
oil and natural gas reserves and their estimated values. Many factors are beyond our control.
Estimating underground accumulations of oil and natural gas cannot be measured in an exact manner.
The accuracy of any reserve estimate is a function of the quality of available data, engineering
and geological interpretation and judgment and the costs we actually incur in the development of
our reserves. As a result, estimates of different engineers often vary. In addition, estimates of
reserves are subject to revision by the results of drilling, testing and production after the date
of the estimates. Consequently, reserve estimates are often different from the quantities of oil
and natural gas that are ultimately recovered. The meaningfulness of estimates is highly dependent
upon the accuracy of the assumptions upon which they were based.
The volume of production from oil and natural gas properties declines as reserves are produced
and depleted. Unless we acquire properties containing proved reserves or conduct successful
drilling activities, our proved reserves will decline as we produce our existing reserves. Our
future oil and natural gas production is highly dependent upon our level of success in acquiring or
finding additional reserves.
We do not have any oil or natural gas reserves outside the United States. Our oil and natural
gas reserves and production are not subject to any long term supply or similar agreements with
foreign governments or authorities.
Our estimated reserves have not been filed with or included in reports to any federal agency
other than the Securities and Exchange Commission.
(29)
|
|
|
ITEM 3. |
|
LEGAL PROCEEDINGS |
On May 21, 2007, we received a Notice of Proposed Adjustment, or the Notice from the
Internal Revenue Service, or the Service, advising us of proposed adjustments to our calculations
of federal income tax resulting in a proposed alternative minimum tax liability in the aggregate
amount of approximately $2.0 million for the years 2004 and 2005. After advising the Service that
we intended to appeal the Notice, we received correspondence from the Service on July 10, 2007
stating that the issue remains in development pending receipt of additional documents requested and
any proposed tax adjustment would not be made until after reviewing the documents requested. On
November 5, 2007, we received an examination report related to this matter which reduces the amount
of proposed adjustment to approximately $1.1 million, which includes interest. On December 21,
2007, we filed an appeal with the Service protesting the proposed adjustment of $1.1 million. We
intend to vigorously contest the adjustment proposed by the Service and believe that we will
ultimately prevail in our position. We would expect the recording of any adjustment, if later
determined to be required, to entail recognition of a deferred tax asset and a corresponding
current liability for federal income taxes payable. Such an adjustment would generally not result
in a charge to earnings except for amounts which might be assessed for penalties or interest on
underpayment of current tax for our fiscal years ended December 31, 2004 and 2005. If a liability
for penalties or interest were determined to be probable, the amounts of such penalties and/or
interest would be charged to earnings. We believe that the effects of this matter will not have a
material adverse effect on our financial position or results of operations for any fiscal year, but
could have a material adverse effect on our results of operations for the fiscal quarter in which
we actually incur or establish a liability for penalties or interest.
We are not a defendant in any other litigation or other proceedings and we are not aware of
any other threatened material litigation, nor have we been a party to any bankruptcy, receivership,
reorganization, adjustment or similar proceeding.
|
|
|
ITEM 4. |
|
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS |
We did not submit any matter to a vote of our stockholders during the fourth quarter of 2007.
PART II
|
|
|
ITEM 5. |
|
MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURITIES |
Market Information
Our common stock trades on the Nasdaq Global Market under the symbol PLLL. The following
table shows, for the periods indicated, the high and low closing price per share for our common
stock as reported on the Nasdaq Global Market.
|
|
|
|
|
|
|
|
|
|
|
Price Per Share |
|
|
High |
|
Low |
2005 |
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
7.60 |
|
|
$ |
5.01 |
|
Second Quarter |
|
$ |
9.00 |
|
|
$ |
6.26 |
|
Third Quarter |
|
$ |
14.15 |
|
|
$ |
8.29 |
|
Fourth Quarter |
|
$ |
18.52 |
|
|
$ |
11.41 |
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
21.13 |
|
|
$ |
15.67 |
|
Second Quarter |
|
$ |
25.56 |
|
|
$ |
18.47 |
|
Third Quarter |
|
$ |
26.39 |
|
|
$ |
18.90 |
|
Fourth Quarter |
|
$ |
20.96 |
|
|
$ |
16.34 |
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
23.31 |
|
|
$ |
16.00 |
|
Second Quarter |
|
$ |
24.69 |
|
|
$ |
21.79 |
|
Third Quarter |
|
$ |
22.88 |
|
|
$ |
16.76 |
|
Fourth Quarter |
|
$ |
20.96 |
|
|
$ |
16.65 |
|
|
|
|
|
|
|
|
|
|
(30)
The closing price of our common stock on February 1, 2008 was $14.38 per share, as reported on
the Nasdaq Global Market.
As of February 1, 2008, there were approximately 2,355 stockholders of record. This number
does not include any beneficial owners for whom shares of common stock may be held in nominee or
street name.
Dividends
We have not paid, and do not intend to pay in the foreseeable future, cash dividends on our
common stock. We intend to retain earnings to finance the expansion of our business and for general
corporate purposes. Any declaration of dividends will be at the discretion of our Board of
Directors and will depend upon the earnings, financial condition, capital requirements, level of
indebtedness, contractual restrictions with respect to payment of dividends and other factors. Our
revolving credit facility and the Indenture governing our 101/4% senior notes restrict our ability to
pay dividends on our common stock. See Risks Related to Our Common Stock We do not pay
dividends on our common stock on page 20.
Sale of Unregistered Securities
At our annual meeting of stockholders held on June 22, 2004, the stockholders approved the
Parallel Petroleum Corporation 2004 Non-Employee Director Stock Grant Plan. You can find a
description of this plan on page 83. Historically, Directors fees had been paid solely in cash.
However, upon approval of the plan by the stockholders, we began paying an annual retainer fee to
each non-employee Director in the form of common stock. Only Directors of Parallel who are not
employees of Parallel or any of its subsidiaries are eligible to participate in the plan. Under the
plan, each non-employee Director is entitled to receive an annual retainer fee consisting of shares
of common stock that are automatically granted on the first day of July in each year, beginning on
July 1, 2004. The actual number of shares received is determined by dividing $25,000 by the average
daily closing price of the common stock on the Nasdaq Global Market for the ten consecutive trading
days commencing fifteen trading days be-fore the first day of July of each year. On July 1, 2007,
and in accordance with the terms of the plan, a total of 4,400 shares of common stock were granted
to four non-employee Directors as follows: Jeffrey G. Shrader 1,100 shares; Edward A. Nash
1,100 shares; Martin B. Oring 1,100 shares; and Ray M. Poage 1,100 shares. The shares of
common stock were issued without registration under the Securities Act of 1933, as amended, in
reliance on the exemption provided by Section 4(2) of the Securities Act of 1933, as amended.
Generally, shares issued under this plan are not transferable as long as the non-employee Director
holding the shares remains a Director of Parallel.
On July 31, 2007, we completed a private offering of unsecured 101/4% senior notes in the principal amount of $150.0 million. The net proceeds, after payment of typical
transaction expenses, of the senior notes of approximately $143.5 million were used first to retire
all of our indebtedness under our Second Lien Term Loan Agreement, with the remainder being applied
to the repayment of indebtedness under our revolving credit facility.
Repurchase of Equity Securities
Neither we nor any affiliated purchaser repurchased any of our equity securities during the
fourth quarter of the fiscal year ended December 31, 2007.
(31)
|
|
|
ITEM 6. |
|
SELECTED FINANCIAL DATA |
In the table below, we provide you with selected historical financial data. We have prepared
this information using our audited Consolidated Financial Statements for the five-year period ended
December 31, 2007. It is important that you read this data along with our audited Consolidated
Financial Statements and related notes, and Managements Discussion and Analysis of Financial
Condition and Results of Operations under Item 7 below. The selected financial data provided are
not necessarily indicative of our future results of operations or financial performance.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2007 |
|
2006(1) |
|
2005 |
|
2004 |
|
2003 |
|
|
|
|
|
|
($ in thousands, except per share and per unit data) |
|
|
|
|
Consolidated Income Statements Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
116,031 |
|
|
$ |
97,025 |
|
|
$ |
66,150 |
|
|
$ |
35,837 |
|
|
$ |
33,855 |
|
Operating expenses |
|
$ |
67,066 |
|
|
$ |
56,606 |
|
|
$ |
32,805 |
|
|
$ |
23,571 |
|
|
$ |
21,138 |
|
Income (loss) before cumulative effect
of change in accounting principle |
|
$ |
(4,661 |
) |
|
$ |
26,155 |
|
|
$ |
(1,589 |
) |
|
$ |
2,271 |
|
|
$ |
7,664 |
|
Net income (loss) |
|
$ |
(4,661 |
) |
|
$ |
26,155 |
|
|
$ |
(1,589 |
) |
|
$ |
2,271 |
|
|
$ |
7,602 |
|
Cumulative preferred stock dividend |
|
$ |
|
|
|
$ |
|
|
|
$ |
(271 |
) |
|
$ |
(572 |
) |
|
$ |
(580 |
) |
Net income (loss) available to common stockholders |
|
$ |
(4,661 |
) |
|
$ |
26,155 |
|
|
$ |
(1,860 |
) |
|
$ |
1,699 |
|
|
$ |
7,022 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) per common share before cumulative effect of change in accounting principle |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(0.12 |
) |
|
$ |
0.73 |
|
|
$ |
(0.06 |
) |
|
$ |
0.07 |
|
|
$ |
0.33 |
|
Diluted |
|
$ |
(0.12 |
) |
|
$ |
0.71 |
|
|
$ |
(0.06 |
) |
|
$ |
0.07 |
|
|
$ |
0.31 |
|
Weighted average common stock and common stock
equivalents outstanding
|
|
Basic |
|
|
38,120 |
|
|
|
35,888 |
|
|
|
32,253 |
|
|
|
25,323 |
|
|
|
21,264 |
|
Diluted |
|
|
38,120 |
|
|
|
36,756 |
|
|
|
32,253 |
|
|
|
25,688 |
|
|
|
24,175 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash dividends common stock |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated Balance Sheet Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
563,093 |
|
|
$ |
442,818 |
|
|
$ |
253,008 |
|
|
$ |
170,671 |
|
|
$ |
118,343 |
|
Total liabilities |
|
$ |
327,831 |
|
|
$ |
259,036 |
|
|
$ |
163,506 |
|
|
$ |
110,677 |
|
|
$ |
57,111 |
|
Long-term debt, less current maturities |
|
$ |
205,383 |
|
|
$ |
165,000 |
|
|
$ |
100,000 |
|
|
$ |
79,000 |
|
|
$ |
39,750 |
|
Total stockholders equity |
|
$ |
235,262 |
|
|
$ |
183,782 |
|
|
$ |
89,502 |
|
|
$ |
59,994 |
|
|
$ |
61,232 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated Statement of Cash Flow Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by (used in) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities |
|
$ |
76,619 |
|
|
$ |
74,186 |
|
|
$ |
37,118 |
|
|
$ |
18,156 |
|
|
$ |
19,493 |
|
Investing activities |
|
$ |
(167,397 |
) |
|
$ |
(200,548 |
) |
|
$ |
(84,949 |
) |
|
$ |
(69,518 |
) |
|
$ |
(15,494 |
) |
Financing activities |
|
$ |
92,684 |
|
|
$ |
125,854 |
|
|
$ |
49,468 |
|
|
$ |
38,765 |
|
|
$ |
1,567 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product Sales |
Oil (Bbls) |
|
|
1,051 |
|
|
|
1,137 |
|
|
|
923 |
|
|
|
729 |
|
|
|
629 |
|
Gas (Mcf) |
|
|
7,422 |
|
|
|
6,539 |
|
|
|
3,592 |
|
|
|
2,690 |
|
|
|
3,356 |
|
BOE |
|
|
2,288 |
|
|
|
2,227 |
|
|
|
1,522 |
|
|
|
1,177 |
|
|
|
1,188 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price(2)
|
Oil (per Bbl) |
|
$ |
65.97 |
|
|
$ |
59.86 |
|
|
$ |
51.78 |
|
|
$ |
39.05 |
|
|
$ |
29.11 |
|
Gas (per M cf) |
|
$ |
6.29 |
|
|
$ |
6.19 |
|
|
$ |
8.54 |
|
|
$ |
5.85 |
|
|
$ |
5.40 |
|
Proved reserves |
|
Oil (Bbls) |
|
|
28,434 |
|
|
|
28,721 |
|
|
|
21,192 |
|
|
|
18,916 |
|
|
|
12,084 |
|
Gas (M cf) |
|
|
57,234 |
|
|
|
58,896 |
|
|
|
25,237 |
|
|
|
16,825 |
|
|
|
16,271 |
|
|
|
|
(1) |
|
Results include $9.0 million of equity in income of pipeline and gathering systems
representing Parallels share of net gain on sale of certain pipeline assets. |
|
(2) |
|
Excludes the effects of hedging. |
(32)
|
|
|
ITEM 7. |
|
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The following discussion is intended to assist you in understanding our financial position and
results of operations for each year in the three-year period ended December 31, 2007. You should
read the following discussion and analysis in conjunction with our selected financial data and our
accompanying audited Consolidated Financial Statements and the related notes to those financial
statements included elsewhere in this report.
The following discussion contains forward-looking statements. For a description of limitations
inherent in forward-looking statements, see Cautionary Statement Regarding Forward-Looking
Statements on page (ii).
Overview and Strategy
We are a Midland, Texas-based independent oil and natural gas exploration and production
company focused on the acquisition, development and exploitation of long-lived oil and natural gas
reserves and, to a lesser extent, exploring for new oil and natural gas reserves. The majority of
our current producing properties are in the Permian Basin of West Texas and New Mexico, the Fort
Worth Basin of North Texas, and the onshore Gulf Coast area of South Texas.
Our primary objective is to increase stockholder value by increasing reserves, production,
cash flow and earnings. We have shifted the balance of our investments from properties having high
rates of production in early years to properties expected to produce more consistently over a
longer term. We attempt to reduce our financial risks by dedicating a smaller portion of our
capital to high risk projects, while reserving the majority of our available capital for
acquisitions, exploitation and development drilling opportunities. Obtaining positions in
long-lived oil and natural gas reserves are given priority over properties that might provide more
cash flow in the early years of production, but which have shorter reserve lives. We also attempt
to further reduce risk by emphasizing acquisition possibilities over high risk exploration
projects.
Since the latter part of 2002, we have reduced our emphasis on high risk exploration efforts
and started focusing on established geologic trends where we can utilize the engineering,
operational, financial and technical expertise of our entire staff. Although we expect to continue
participating in exploratory drilling activities, reducing financial, reservoir, drilling and
geological risks and diversifying our property portfolio are important criteria in the execution of
our business plan. In summary, our current business plan:
|
|
|
focuses on projects having less geologic risk; |
|
|
|
|
emphasizes acquisition, exploitation, development and enhancement activities; |
|
|
|
|
includes the utilization of horizontal and fracture stimulation technologies on
certain types of reservoirs; |
|
|
|
|
focuses on acquiring producing properties; and |
|
|
|
|
expands the scope of operations by diversifying our exploratory and development
efforts, both in and outside of our current areas of operation. |
Although the direction of our exploration and development activities has shifted from
higher-risk exploratory activities to lower-risk development opportunities, we will continue our
efforts, as we have in the past, to maintain low general and administrative expenses relative to
the size of our overall operations, utilize advanced technologies, serve as operator in appropriate
circumstances, and reduce operating costs.
The extent to which we are able to implement and follow through with our business plan will be
influenced by:
|
|
|
the prices we receive for the oil and natural gas we produce; |
|
|
|
|
the results of reprocessing and reinterpreting our 3-D seismic data; |
|
|
|
|
the results of our drilling activities; |
|
|
|
|
the costs of obtaining high quality field services; |
(33)
|
|
|
our ability to find and consummate acquisition opportunities; and |
|
|
|
|
our ability to negotiate and enter into work to earn arrangements, joint venture or
other similar agreements on terms acceptable to us. |
Significant changes in the prices we receive for our oil and natural gas, or the occurrence of
unanticipated events beyond our control may cause us to defer or deviate from our business plan,
including the amounts we have budgeted for our activities.
Operating Performance
Our operating performance is influenced by several factors, the most significant of which are
the prices we receive for our oil and natural gas and the quantities of oil and natural gas that we
are able to produce. The world price for oil has overall influence on the prices that we receive
for our oil production. The prices received for different grades of oil are based upon the world
price for oil, which is then adjusted based upon the particular grade. Typically, light oil is sold
at a premium, while heavy grades of crude are discounted. Natural gas prices we receive are
influenced by:
|
|
|
seasonal demand; |
|
|
|
|
weather; |
|
|
|
|
hurricane conditions in the Gulf of Mexico; |
|
|
|
|
availability of pipeline transportation to end users; |
|
|
|
|
proximity of our wells to major transportation pipeline infrastructures; and |
|
|
|
|
world oil prices. |
Results of Operations
As described under Item 1. Business About Our Business and Strategy, we changed our
business model in 2002. At the beginning of 2002, our total proved reserves were approximately 3.2
MMBoe with a reserves to production ratio of approximately 4 to 1. Through the execution of this
business model, our reserves at the end of 2007 were approximately 38.0 MMBoe with a reserves to
production ratio of approximately 16.6 to 1. As described on page 13 of this Annual Report on Form
10-K, the failure to replace oil and natural gas reserves may negatively affect our business. We
monitor this risk by comparing the quantity of our oil and natural gas reserves at the end of each
year to our production for that year. This comparison, which is made in the form of a reserves to
production ratio, helps us measure our ability to offset produced volumes with new reserves that
will be produced in the future. The reserves to production ratio is calculated by dividing the
total proved reserves at the end of a year by the actual production for the same year. The annual
change in this ratio provides us with an indication of our performance in replenishing annual
production volumes. The reserves to production ratio is a statistical indicator that has
limitations. The ratio is limited because it can vary widely based on the extent and timing of new
discoveries and property acquisitions. In addition, the ratio does not take into account the cost
or timing of future production of new reserves. For that reason, the ratio does not, and is not
intended to, provide a measurement of value. For the year ended 2002, our production was 77%
natural gas and 23% oil, as compared to approximately 54% natural gas and 46% oil for the year
ended December 31, 2007. The production stream changed from shorter lived gulf coast natural gas to
longer lived Permian Basin oil production and longer lived natural gas production in the Barnett
Shale and New Mexico Wolfcamp areas. This has increased our lease operating expense primarily due
to increased utilities and chemicals associated with the operation of oil properties and salt water
disposal and compression associated with these longer lived resource gas projects.
(34)
The following table shows selected data and operating income comparisons for each of the three
years ended December 31, 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
($ in thousands, except per unit data) |
|
Production
Volumes |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
1,051 |
|
|
|
1,137 |
|
|
|
923 |
|
Natural gas (Mcf) |
|
|
7,422 |
|
|
|
6,539 |
|
|
|
3,592 |
|
BOE |
|
|
2,288 |
|
|
|
2,227 |
|
|
|
1,522 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
Price |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)(1) |
|
$ |
65.97 |
|
|
$ |
59.86 |
|
|
$ |
51.78 |
|
Natural gas (per Mcf)(1) |
|
$ |
6.29 |
|
|
$ |
6.19 |
|
|
$ |
8.54 |
|
BOE Price(1) |
|
$ |
50.72 |
|
|
$ |
48.73 |
|
|
$ |
51.57 |
|
BOE Price(2) |
|
$ |
50.72 |
|
|
$ |
43.56 |
|
|
$ |
43.46 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
69,315 |
|
|
$ |
68,076 |
|
|
$ |
47,800 |
|
Effect of oil hedges |
|
|
|
|
|
|
(11,512 |
) |
|
|
(12,139 |
) |
Natural gas |
|
|
46,716 |
|
|
|
40,461 |
|
|
|
30,690 |
|
Effect of natural gas hedges |
|
|
|
|
|
|
|
|
|
|
(201 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
116,031 |
|
|
|
97,025 |
|
|
|
66,150 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
|
|
22,200 |
|
|
|
16,819 |
|
|
|
9,947 |
|
Production taxes |
|
|
5,545 |
|
|
|
5,577 |
|
|
|
4,102 |
|
Production tax refund |
|
|
(1,209 |
) |
|
|
|
|
|
|
|
|
General and administrative |
|
|
10,415 |
|
|
|
9,523 |
|
|
|
6,712 |
|
Depreciation, depletion and amortization |
|
|
30,115 |
|
|
|
24,687 |
|
|
|
12,044 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
67,066 |
|
|
|
56,606 |
|
|
|
32,805 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
48,965 |
|
|
$ |
40,419 |
|
|
$ |
33,345 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Excludes hedge transactions. |
|
(2) |
|
Includes hedge transactions. |
Critical Accounting Policies and Practices
The preparation of financial statements in conformity with accounting principles generally
accepted in the United States requires us to make estimates and use assumptions that can affect the
reported amounts of assets, liabilities, revenues or expenses. Certain accounting policies that
require significant management estimates and that are deemed critical to our results of operations
or financial position are discussed below. Our management reviews our critical accounting policies
with the Audit Committee of our Board of Directors.
Full Cost and Impairment of Assets. We account for our oil and natural gas exploration
and development activities using the full cost method of accounting. Under this method, all costs
incurred in the acquisition, exploration and development of oil and natural gas properties are
capitalized. Costs of non-producing properties, wells in process of being drilled and significant
development projects are excluded from depletion until such time as the related project is
developed and proved reserves are established or impairment is determined. At the end of each
quarter, the net capitalized costs of our oil and natural gas properties, net of related deferred
taxes, is limited to the lower of unamortized cost or a ceiling, based on the present value of
estimated future net revenues, net of income tax effects, discounted at 10%, plus the lower of cost
or fair market value of our unproved properties. Estimated future net revenues are measured at
unescalated oil and natural gas prices at the end of each quarter, with effect given to our cash
flow hedge positions. If the net capitalized costs of our oil and natural gas properties exceed the
ceiling, we are subject to a ceiling test write-down to the extent of the excess. A ceiling test
write-down is a non-cash charge to
(35)
earnings. It reduces earnings and impacts stockholders equity in the period of occurrence and
may result in lower depreciation, depletion and amortization expense in future periods.
The risk that we will be required to write down the carrying value of oil and natural gas
properties increases when oil and natural gas prices decline. If commodity prices deteriorate, it
is possible that we could incur an impairment in future periods.
Depletion. Provision for depletion of oil and natural gas properties under the full
cost method is calculated using the unit of production method based upon estimates of proved oil
and natural gas reserves with oil and natural gas production being converted to a common unit of
measurement based upon relative energy content. Investments in unproved properties and major
development projects are not amortized until proved reserves associated with the projects can be
determined or until impairment occurs. The cost of any impaired property is transferred to the
balance of oil and natural gas properties subject to depletion. The amortizable base includes
estimated future development costs and where significant, dismantlement, restoration and
abandonment costs, net of estimated salvage value. Oil and natural gas properties included $86.4
million and $50.4 million for 2007 and 2006, respectively, for unevaluated properties not included
in depletion.
In arriving at rates under the unit of production method, the quantities of recoverable oil
and natural gas reserves are established based on estimates made by our geologists and engineers
and require significant judgment as does the projection of future production volumes and levels of
future costs, including future development costs. In addition, considerable judgment is necessary
in determining when unproved properties become impaired and in determining the existence of proved
reserves once a well has been drilled. All of these judgments may have significant impact on the
calculation of depletion expense. There have been no material changes in our methodology of
calculating the depletion of oil and gas properties under the full cost method during the three
years ended December 31, 2007.
Proved Reserve Estimates. The discounted present value of our proved oil and natural
gas reserves is a major component of the ceiling calculation, and represents the component that
requires the most subjective judgments. Estimates of reserves are forecasts based on engineering
data, projected future rates of production and the timing of future expenditures. The process of
estimating oil and natural gas reserves requires substantial judgment, resulting in imprecise
determinations, particularly for new discoveries. Different reserve engineers may make different
estimates of reserve quantities based on the same data. Our reserve estimates are prepared by
independent petroleum engineers.
The passage of time provides more qualitative information regarding estimates of reserves, and
revisions are made to prior estimates to reflect updated information. However, there can be no
assurance that more significant revisions will not be necessary in the future. If future revisions
significantly reduce previously estimated reserve quantities, it could result in a full cost
ceiling write-down. At December 31, 2007, our ceiling was in excess of our capitalized costs. In
addition to the impact of the estimates of proved reserves in calculating the ceiling test,
estimates of proved reserves are also a significant component of the calculations of depreciation,
depletion and amortization.
While estimates of the quantities of proved reserves require substantial subjective judgment,
the associated prices of oil and natural gas reserves that are included in the discounted present
value of the reserves do not require judgment. Accounting principles generally accepted in the
United States require that prices and costs in effect as of the last day of the period are held
constant indefinitely. Accordingly, the resulting value is not indicative of the true fair value of
the reserves. Oil and natural gas prices have historically been cyclical and, on the last day of a
quarter, can be either substantially higher or lower than prices we actually receive in the
long-term, which are a barometer for true fair value.
Use of Estimates. The preparation of our Consolidated Financial Statements in
accordance with accounting principles generally accepted in the United States requires management
to make estimates and assumptions that affect reported assets, liabilities, expenses, and some
narrative disclosures. Hydrocarbon reserves, future development costs and certain hydrocarbon
production expenses are the most critical estimates used in the preparation of our Consolidated
Financial Statements.
Derivatives. The Financial Accounting Standards Board issued SFAS No. 133, as amended
by SFAS No. 138, that requires all derivative instruments to be recorded on the balance sheet at
their respective fair values. We adopted SFAS no. 133 on January 1, 2001.
(36)
During the period from January 1, 2003 to June 30, 2004, new derivative contracts were
designated as cash flow hedges. These contracts remained designated as cash flow hedges through
their settlement. Accordingly, the effective portion of the unrealized gains or losses was recorded
in other comprehensive loss until the settlement of the contract position occurred. At settlement
of these contracts, the cash value paid was recorded in revenue along with oil and natural gas
sales, or in interest expense along with the interest expense that we incurred under our credit
facilities. As of December 31, 2006, we had no remaining contracts which were designated as
hedges.
For periods prior to 2003 and for periods after July 1, 2004, derivative contracts entered
into were not designated as cash flow hedges. Accordingly, the unrealized gain or loss on these
derivative contracts was recorded in other income. At settlement of these contracts, the realized
gain or loss remains in other income and is not offset against oil and natural gas sales or
interest expense.
Although we have designated our derivative contracts differently in different periods, the
purpose of all of our derivative contracts is to provide a measure of stability in our oil and
natural gas receipts and interest rate payments and to manage exposure to commodity price and
interest rate risk under existing sales contracts.
Years Ended December 31, 2007 and December 31, 2006
Our oil and natural gas revenues and production product mix are shown in the following table
for the years ended December 31, 2007 and 2006.
Oil and Gas Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues(1) |
|
Production |
|
|
2007 |
|
2006 |
|
2007 |
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
60 |
% |
|
|
58 |
% |
|
|
46 |
% |
|
|
51 |
% |
Natural gas
(Mcf) |
|
|
40 |
% |
|
|
42 |
% |
|
|
54 |
% |
|
|
49 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes the effects of derivative transactions accounted for as hedges. |
The following table shows our production volumes, product sale prices and operating revenues for
the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent |
|
|
|
Year Ended December 31, |
|
|
Increase |
|
|
Increase |
|
|
|
2007 |
|
|
2006 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
($ in thousands, except per unit data) |
|
|
|
|
|
Production
Volumes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
1,051 |
|
|
|
1,137 |
|
|
|
(86 |
) |
|
|
(8 |
)% |
Natural gas
(Mcf) |
|
|
7,422 |
|
|
|
6,539 |
|
|
|
883 |
|
|
|
14 |
% |
BOE |
|
|
2,288 |
|
|
|
2,227 |
|
|
|
61 |
|
|
|
3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)(1) |
|
$ |
65.97 |
|
|
$ |
59.86 |
|
|
$ |
6.11 |
|
|
|
10 |
% |
Natural gas (per Mcf)(1) |
|
$ |
6.29 |
|
|
$ |
6.19 |
|
|
$ |
0.10 |
|
|
|
2 |
% |
BOE price(1) |
|
$ |
50.72 |
|
|
$ |
48.73 |
|
|
$ |
1.99 |
|
|
|
4 |
% |
BOE price(2) |
|
$ |
50.72 |
|
|
$ |
43.56 |
|
|
$ |
7.16 |
|
|
|
16 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
69,315 |
|
|
$ |
68,076 |
|
|
$ |
1,239 |
|
|
|
2 |
% |
Effect of oil hedges |
|
|
|
|
|
|
(11,512 |
) |
|
|
11,512 |
|
|
|
(100 |
)% |
Natural gas |
|
|
46,716 |
|
|
|
40,461 |
|
|
|
6,255 |
|
|
|
15 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
116,031 |
|
|
$ |
97,025 |
|
|
$ |
19,006 |
|
|
|
20 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Excludes hedge transactions. |
|
(2) |
|
Includes hedge transactions. |
(37)
Oil revenues
Average wellhead realized crude oil prices increased $6.11 per Bbl, or 10%, to $65.97 per Bbl
for 2007, as compared to 2006. This price increase caused our revenues to increase by
approximately $6.4 million in 2007, as compared to 2006. Oil production decreased 8% attributable
to a decline of approximately 43,000 Bbls, 41,000 Bbls and 33,000 Bbls in the Diamond M Deep,
Carm-Ann and south Texas area, respectively comparing the twelve months ended December 31, 2007 to
twelve months ended December 31, 2006. These decreases were as a result of natural declines and
limited developmental activity occurring within these areas. These decreases were partially offset
with increases in the Harris field where we benefited from our development programs in 2006 and
late 2007. The decrease in oil production reduced revenue approximately $5.2 million for 2007.
Natural gas revenues
Average realized wellhead natural gas prices received were up slightly to $6.29 per Mcf for
the twelvemonths ended December 31, 2007 from $6.19 per Mcf received for the twelve months ended
December 31, 2006. This slight price increase accounted for an increase in revenue of
approximately $742,000. Natural gas production increased 14% primarily due to new wells in New
Mexico Wolfcamp area where volumes were up 1.7 Bcf and the Barnett Shale area where volumes were up
approximately 628,000 Mcf. These increases were offset by a production decline of approximately
1.2 Bcf in our south Texas wells comparing twelve months ended December 31, 2007 to twelve months
ended December 31, 2006. The net increase in natural gas volumes increased revenue approximately
$5.5 million for 2007.
Oil hedges
We settled all remaining derivatives classified as cash flow hedges in December 2006.
Therefore, oil hedge losses were $0 in 2007 compared to a loss of approximately $11.5 million in
2006. We continue to employ derivative contracts in the form of oil and natural collars
and swaps which are intended to mitigate the effects of commodity price volatility. These
derivative contracts are not designated or accounted for as cash flow hedges and, therefore, the
changes in their fair values and any settlement amounts are recorded to other income (expense) as
described below.
Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent |
|
|
|
Year Ended December |
|
|
Increase |
|
|
Increase |
|
|
|
2007 |
|
|
2006 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
($ in thousands) |
|
|
|
|
|
Lease operating expense |
|
$ |
22,200 |
|
|
$ |
16,819 |
|
|
$ |
5,381 |
|
|
|
32 |
% |
Production taxes |
|
|
5,545 |
|
|
|
5,577 |
|
|
|
(32 |
) |
|
|
(1 |
)% |
Production tax refund |
|
|
(1,209 |
) |
|
|
|
|
|
|
(1,209 |
) |
|
|
N/A |
|
General and administrative |
|
|
10,415 |
|
|
|
9,523 |
|
|
|
892 |
|
|
|
9 |
% |
Depreciation, depletion and amortization |
|
|
30,115 |
|
|
|
24,687 |
|
|
|
5,428 |
|
|
|
22 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
67,066 |
|
|
$ |
56,606 |
|
|
$ |
10,460 |
|
|
|
18 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
Lease operating expenses are higher partly due to new wells. Of the $5.4 million increase,
$2.3 million of these charges are on wells that have been completed in the past year or completed
late in 2006. Therefore, the costs are higher for the twelve months ended December 31, 2007
compared to the same period 2006. Well repair, workover expenses, salt water disposal and
compressor expense increased approximately $4.0 million for the twelve months ended December 31,
2007 compared to the twelve months ended December 31, 2006. Overall higher costs for well repair
and workover result from our refocused efforts on lease maintenance and away from developmental
activity during 2007 on our oil properties. Salt water disposal and compression charges increased
significantly during 2007 resulting from new well activity in the south New Mexico area and Barnett
shale area. These amounts are included in the previously discussed $2.3 million increase for new
wells. Lifting costs (excluding production taxes) were $9.70 per BOE in 2007 compared to $7.55 per
BOE in 2006.
(38)
Production taxes
Production taxes showed no significant change even though revenue increased $7.5 million from
December 31, 2006 to December 31, 2007. The expected increase was offset by qualifying lower
severance tax rates used during 2007. The lower severance tax rates are a result of certain
properties qualifying for state tax incentive programs. The lower tax rates will continue on a
forward basis until the term of the tax incentives are expired.
A production tax refund was received in June 2007 in the amount of $1.2 million for gas
production taxes on non-operated wells in the Wilcox area of south Texas for production periods
March 2005 through January 2007. This refund was received by the operator of these wells only
after the operators application for tax abatement was approved by state regulatory agencies. The
reduction in our production tax expense was recognized only when approval of the application for
tax abatement was granted by the state.
General and administrative
General and administrative expenses increased 9% or $892,000 in 2007 over 2006. During
2007, salaries increased by $488,000. This was due to a larger staff and increased salary rates
when compared to 2006. Also, we incurred increased legal fees in 2007 in the amount of $413,000.
This increase in legal fees was primarily related to general corporate matters. In addition, we
incurred increased costs of $334,000 associated with accounting and reporting requirements.
Although there can be no assurance, we do not expect legal, accounting and reporting costs to
increase significantly in 2008. Our insurance premiums increased by $219,000.
Offsetting the above general and administrative expense increases were the following two
items. First, during the second quarter of 2006, we determined that stock options to purchase
30,000 shares of common stock had been granted in 2003 to four of our employees under our 1998
Stock Option Plan, but which were not available for issuance under the plan. In June 2006, the
Board of Directors authorized us to enter into settlement and release agreements with the four
employees. Under these agreements, we made a one-time lump sum cash payment to each employee in an
amount equal to the spread between the exercise price of the options and the closing price of our
stock on June 21, 2006. The total cash payments were approximately $511,000. This amount was
charged to general and administrative expense during the second quarter of 2006. Secondly, during
the second quarter of 2007, we revised our estimates of expected forfeitures of stock options
granted to directors due to the resignation of a director and the subsequent forfeiture of 40,000
stock options held by him. As a result we reduced our estimate of the grant date fair value of
shares expected to ultimately vest under our stock option plan by approximately $283,000.
Depreciation, depletion and amortization
Depreciation, depletion and amortization expense increased 22%, or $5.4 million, for 2007 as
compared to 2006. Depletion per BOE was $13.02 for 2007 and $10.88 for 2006. This increase is
attributable to an overall increase in actual and anticipated drilling costs and related oilfield
service costs. Increased cost levels affect both the depletable amounts of capitalized costs in
2007 and the depletion attributable to amounts of estimated future development costs on proved
undeveloped properties. Throughout 2006 and 2007, the majority of our drilling activity was in our
natural gas resource projects in the Permian Basin of west Texas and the Barnett Shale areas.
These areas have higher associated per BOE drilling and development costs due to the use of
horizontal drilling and multi-stage stimulation techniques. These factors, when combined with the
increase in the absolute level of our capital expenditures during this time period have led to a
significant increase in our depletion rate per BOE.
(39)
Other income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent |
|
|
|
Year Ended December |
|
|
Increase |
|
|
Increase |
|
|
|
2007 |
|
|
2006 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
($ dollars in thousands) |
|
|
|
|
|
Gain (loss) on derivatives not classified as hedges |
|
$ |
(36,776 |
) |
|
$ |
2,802 |
|
|
$ |
(39,578 |
) |
|
|
(1,412 |
)% |
Gain (loss) on ineffective portion of hedges |
|
|
|
|
|
|
626 |
|
|
|
(626 |
) |
|
|
(100 |
)% |
Interest and other income |
|
|
197 |
|
|
|
158 |
|
|
|
39 |
|
|
|
25 |
% |
Interest expense |
|
|
(19,177 |
) |
|
|
(12,360 |
) |
|
|
(6,817 |
) |
|
|
55 |
% |
Cost of debt retirement |
|
|
(760 |
) |
|
|
|
|
|
|
(760 |
) |
|
|
N/A |
|
Other expense |
|
|
(118 |
) |
|
|
(189 |
) |
|
|
71 |
|
|
|
(38 |
)% |
Equity in income (loss) of pipelines
and gathering system ventures |
|
|
(311 |
) |
|
|
8,593 |
|
|
|
(8,904 |
) |
|
|
(104 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(56,945 |
) |
|
$ |
(370 |
) |
|
$ |
(56,575 |
) |
|
|
15,291 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives not classified as hedges
We recorded a loss of $36.8 million in 2007 for derivatives not classified as hedges as
compared to a gain of $2.8 million for 2006. The greatest impact of the change in fair market
valuation was within our crude oil contracts due to the significant increase in oil prices during
2007. We settled in cash a net of $16.6 million in derivative contracts during the year.
The ineffective portion of our hedges was a gain of approximately $626,000 in 2006. As of
December 31, 2006, all cash flow hedge contracts as defined by SFAS 133 were settled.
Interest expense
Interest expense increased in 2007 as the result of increased borrowings and an increase in
our weighted average interest rate. Our bank debt decreased from $165.0 million to $60.0 million
during 2007. However, interest expense increased $6.6 million as a result of our $150.0 million
senior notes offering in July 2007 and an increase in the average interest rate on our revolving
credit facility in 2007. Our weighted average interest rate increased to 8.92% from 8.33% for 2007
and 2006, respectively. Due to the issuance of our 101/4% senior notes, we expect that our average
interest rate for 2008 will increase over the 2007 average.
Capitalized interest on work in progress decreased interest expense by $423,000 in 2007, a
decrease of $214,000 compared to 2006.
Cost of debt retirement
Cost of debt retirement represent the write off of previously capitalized debt issuance costs
associated with our Second Lien Term Loan that was retired with the proceeds of our senior notes
offering.
Equity in income (loss) of pipelines and gathering system ventures
Since 2004, we have invested in four pipelines and gathering system joint ventures. During
2006, the assets of two of these ventures were sold. As a result, we recognized our share of net
gains on sale of $9.0 million in 2006.
During 2006, we and two other unaffiliated parties formed a joint venture known as the
Hagerman Gas Gathering System, which was formed for the purpose of constructing, owning and
operating a gas gathering system in New Mexico.
The loss associated with our equity investments totaled $311,000 in 2007 versus a gain of $8.6
million in 2006. The gains realized in 2006 were the result of the sale of our interests in two
pipeline joint ventures. We did not sell any interests in pipeline joint ventures during 2007. In
addition, the Hagerman Gas Gathering System in New Mexico was operational for the entire twelve
months of 2007 versus a few months in 2006. During 2006 and the first nine months 2007, production
levels and related transportation volumes were not sufficient for profitable operation of this
system. This resulted in an increase in our equity loss for this investment of $601,000. We also
received final payout settlements for the divestiture of our investments in West Fork Pipeline
Company I and West Fork Pipeline Company V of $161,000 and $126,000 respectively in the fourth
quarter of 2007.
(40)
Income tax
Income tax was a benefit of $3.3 million in 2007 compared to an expense of $13.9 million in
2006. Income tax expense for 2008 will be dependent on our earnings and is expected to be
approximately 35% of income before income taxes.
Included in the $3.3 million income tax benefit amount was a net state tax benefit of the
$592,000. Prior to 2007, we had not recognized a tax credit for state net operating loss
carryovers due to the uncertainty about their ultimate realization. However, with the State of
Texas revising its state tax laws in 2007 and our election to utilize the credit, we recognized
this credit as we now expect to realize this benefit over future periods. See Note 9 to the
Consolidated Financial Statements.
Basic and diluted net income
We had basic net income (loss) per share of $(0.12) and $0.73 and diluted net income (loss)
per share of $(0.12) and $0.71 for 2007 and 2006, respectively. Basic weighted average common
shares outstanding increased from approximately 35.9 million shares in 2006 to approximately 38.1
million shares in 2007. The increase was primarily due to our public offering of 3.0 million
shares of common stock in December 2007 and the exercise of employee and nonemployee stock options
during 2007.
Years Ended December 31, 2006 and December 31, 2005
Our oil and natural gas revenues and production product mix are shown in the table below for
the years ended December 31, 2006 and 2005.
Oil and Gas Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues(1) |
|
Production |
|
|
2006 |
|
2005 |
|
2006 |
|
2005 |
Oil (Bbls) |
|
|
58 |
% |
|
|
54 |
% |
|
|
51 |
% |
|
|
61 |
% |
Natural gas
(M cf) |
|
|
42 |
% |
|
|
46 |
% |
|
|
49 |
% |
|
|
39 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes hedge transactions. |
The following table sets forth certain information about our operating revenues for the
periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent |
|
|
|
Year Ended December 31, |
|
|
Increase |
|
|
Increase |
|
|
|
2006 |
|
|
2005 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
($ in thousands, except per unit data) |
|
|
|
|
|
Production
Volumes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
1,137 |
|
|
|
923 |
|
|
|
214 |
|
|
|
23 |
% |
Natural gas
(M cf) |
|
|
6,539 |
|
|
|
3,592 |
|
|
|
2,947 |
|
|
|
82 |
% |
BOE |
|
|
2,227 |
|
|
|
1,522 |
|
|
|
705 |
|
|
|
46 |
% |
Sales
Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)(1) |
|
$ |
59.86 |
|
|
$ |
51.78 |
|
|
$ |
8.08 |
|
|
|
16 |
% |
Natural gas
(per M cf)(1) |
|
$ |
6.19 |
|
|
$ |
8.54 |
|
|
$ |
(2.35 |
) |
|
|
(28 |
)% |
BOE price(1) |
|
$ |
48.73 |
|
|
$ |
51.57 |
|
|
$ |
(2.84 |
) |
|
|
(6 |
)% |
BOE price(2) |
|
$ |
43.56 |
|
|
$ |
43.46 |
|
|
$ |
0.10 |
|
|
|
0 |
% |
Operating
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
68,076 |
|
|
$ |
47,800 |
|
|
$ |
20,276 |
|
|
|
42 |
% |
Oil hedges |
|
|
(11,512 |
) |
|
|
(12,139 |
) |
|
|
627 |
|
|
|
5 |
% |
Natural gas |
|
|
40,461 |
|
|
|
30,690 |
|
|
|
9,771 |
|
|
|
32 |
% |
Natural gas hedges |
|
|
|
|
|
|
(201 |
) |
|
|
201 |
|
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
97,025 |
|
|
$ |
66,150 |
|
|
$ |
30,875 |
|
|
|
47 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Excludes hedge transactions. |
|
(2) |
|
Includes hedge transactions. |
(41)
Oil revenues
Oil revenues, excluding hedges, increased $20.3 million, or 42%, for the year ended 2006, as
compared to 2005. Oil production volumes increased 23%, which was attributable to our 2006 drilling
program in the Harris San Andres field that we acquired in 2005 and early 2006, re-stimulations and
additional drilling in the Fullerton San Andres field and our drilling program in the Carm-Ann/N.
Means Queen and Diamond M Canyon Reef. The increase in oil production increased revenue
approximately $12.8 million for 2006. Average realized wellhead crude oil prices increased $8.08
per Bbl, or 16%, to $59.86 per Bbl for 2006, compared to 2005. The increase in oil price increased
revenue approximately $7.5 million for 2006.
Natural gas revenues
Natural gas revenues, excluding hedges, increased $9.8 million, or 32%, for the year ended
2006, as compared to 2005. Natural gas production volumes increased 82% as a result of added
production from drilling discoveries in our gulf coast area of south Texas, Fort Worth Basin
Barnett Shale wells and initial production from our New Mexico Wolfcamp wells. The increase in
natural gas volumes increased revenue approximately $18.2 million for 2006. Average realized
wellhead natural gas prices decreased 28%, or $2.35 per Mcf, to $6.19 per Mcf. The decrease in
natural gas prices had a negative effect on revenues of approximately $8.4 million for the year
ended December 31, 2006.
Oil hedges
The negative effect on oil revenues of oil hedges decreased approximately $600,000, or 5%, for
2006, as compared to 2005, because contracts settled in 2006 had relatively higher strike prices in
relation to the related market price at settlement. On a BOE basis, the negative effects of hedges
declined from $8.11 per BOE in 2005 compared to $5.17 per BOE in 2006.
Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent |
|
|
|
Year Ended December 31, |
|
|
Increase |
|
|
Increase |
|
|
|
2006 |
|
|
2005 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
($ in thousands) |
|
|
|
|
|
Lease operating expense |
|
$ |
16,819 |
|
|
$ |
9,947 |
|
|
$ |
6,872 |
|
|
|
69 |
% |
Production taxes |
|
|
5,577 |
|
|
|
4,102 |
|
|
|
1,475 |
|
|
|
36 |
% |
General and administrative: |
|
|
9,523 |
|
|
|
6,712 |
|
|
|
2,811 |
|
|
|
42 |
% |
Depreciation, depletion and amortization |
|
|
24,687 |
|
|
|
12,044 |
|
|
|
12,643 |
|
|
|
105 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
56,606 |
|
|
$ |
32,805 |
|
|
$ |
23,801 |
|
|
|
73 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
Lease operating expense increased 69%, or $6.9 million, compared to 2005. Fifty-three percent
(53%) of our 2006 production was from our long-life oil assets located in our west Texas Fullerton,
Carm-Ann, Diamond M and Harris properties. Our increase in lease operating expenses is due to
mechanical, ad valorem and utility costs which increased our related lifting costs (excluding
production taxes) to $7.55 per BOE in 2006, as compared to $6.54 per BOE in 2005. We experienced a
15% increase in our per BOE lifting costs primarily due to higher lifting costs associated with
non-operated wells and newly acquired operated wells for the year ended December 31, 2006.
Production taxes
Production taxes increased 36%, or $1.5, million in 2006, which was associated with an
increase in revenues of $30.0 million. Production taxes in future periods will continue to be a
function of product mix, production volumes and product prices.
General and administrative
Total general and administrative expenses increased 42%, or $2.8 million, in 2006 over 2005.
During the second quarter of 2006, we determined that stock options to purchase 30,000 shares of
common stock had been granted in 2003 to four of our employees under our 1998 Stock Option Plan,
but which were not available for issuance under the plan. In June 2006, the Board of Directors
authorized us to enter into settlement and release agree
(42)
ments with the four employees. Under these agreements, we made a one-time lump sum cash
payment to each employee in an amount equal to the spread between the exercise price of the
options and the closing price of our stock on June 21, 2006. The total cash payments were
approximately $511,000. This amount was charged to general and administrative expense during the
second quarter of 2006. Increased public reporting costs included, but were not limited to,
increases in road show expenses, corporate counseling and oil and natural gas reserve analysis also
contributed to the overall increases in general and administrative costs. In addition, we incurred
additional public reporting costs associated with the stock options granted to our board of
directors in late 2005. General and administrative expenses capitalized to the full cost pool were
$1.7 million for 2006, compared to $1.3 million for 2005.
Depreciation, depletion and amortization
Depreciation, depletion and amortization expense increased 105%, or $12.6 million, for 2006
compared to 2005. Depletion per BOE was $10.88 for 2006 and $7.61 for 2005. This increase is
attributable to recent increases in overall drilling and related oilfield service costs and the
costs of property acquisitions. Increased cost levels affect both the depletable amounts of
capitalized costs in recent periods and the depletion attributable to amounts of estimated future
development costs on proved undeveloped properties. In addition, our drilling efforts in 2006
were, and our future drilling plans are, focused on our natural gas resource projects which have
higher associated per BOE drilling and development costs than our drilling projects in the Permian
Basin of west Texas and onshore gulf coast of south Texas due to the use of horizontal drilling and
multi-stage stimulation techniques. These factors, when combined with the increase in the absolute
level of our capital expenditures during the recent period, have led to a significant increase in
our depletion rate per BOE. Our annual costs incurred in the acquisition of, exploration for and
development of oil and natural gas properties have increased by approximately 188% since 2004.
Other
income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent |
|
|
|
Year Ended December 31, |
|
|
Increase |
|
|
Increase |
|
|
|
2006 |
|
|
2005 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
($ in thousands) |
|
|
|
|
|
|
Gain (loss) on derivatives not classified as hedges |
|
$ |
2,802 |
|
|
$ |
(31,669 |
) |
|
$ |
34,471 |
|
|
|
109 |
% |
Gain (loss) on ineffective portion of hedges |
|
|
626 |
|
|
|
(137 |
) |
|
|
763 |
|
|
|
557 |
% |
Interest and other income |
|
|
158 |
|
|
|
167 |
|
|
|
(9 |
) |
|
|
5 |
% |
Interest expense |
|
|
(12,360 |
) |
|
|
(4,780 |
) |
|
|
(7,580 |
) |
|
|
(159 |
)% |
Other expense |
|
|
(189 |
) |
|
|
(102 |
) |
|
|
(87 |
) |
|
|
(85 |
)% |
Equity in income (loss) of pipelines and
gathering system ventures |
|
|
8,593 |
|
|
|
(89 |
) |
|
|
8,682 |
|
|
|
9,755 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(370 |
) |
|
$ |
(36,610 |
) |
|
$ |
36,240 |
|
|
|
99 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives not classified as hedges
We recorded a gain of $2.8 million in 2006 for derivatives not classified as hedges in 2006,
as compared to a loss of $31.7 million for 2005. Future gains or losses on derivatives not
classified as hedges will be impacted by the volatility of commodity prices and interest rates, as
well as by the terms of any new derivative contracts.
The ineffective portion of our hedges was a gain of approximately $626,000 in 2006, as
compared to a loss of approximately $137,000 in 2005. As of December 31, 2006, all cash flow hedge
contracts as defined by SFAS 133 were settled.
Interest expense
Interest expense increased with the increase in our bank debt from $100.0 million to $165.0
million in 2006, along with an increase of our average loan interest rate from 7.96% to 8.30% in
2006. Interest expense will increase for 2007 with increased borrowings for leasehold acquisitions
and amounts expended for drilling.
Equity in income (loss) of pipelines and gathering system ventures
We invested in four pipelines and gathering system joint ventures beginning in 2004. During
2006, the assets of two of these ventures were sold. As a result, we recognized our share of net
gains on sale of $9.0 million in 2006.
(43)
Income tax
We had an income tax expense of $13.9 million in 2006, compared to a $1.7 million income tax
benefit in 2005. The income tax rate for 2007 will be dependent on our earnings and is expected to
be approximately 35% of income before income taxes.
Basic and diluted net income
We had basic and diluted net earnings per share of $0.73 and $0.71, respectively, for 2006 and
basic and diluted net loss per share of $0.06 for 2005. Basic weighted average common shares
outstanding increased from 32.3 million shares in 2005 to 35.9 million shares in 2006. Diluted
weighted average common shares increased from 32.3 million shares in 2005 to 36.8 million shares in
2006. The increase in common shares was primarily due to our public offering of 2.5 million shares
of common stock in August 2006.
Capital Resources and Liquidity
Our capital resources consist primarily of cash flows from our oil and natural gas properties,
borrowings supported by our oil and natural gas reserves and equity offerings. Our level of
earnings and cash flows depends on many factors, including the prices we receive for oil and
natural gas we produce.
Working capital decreased approximately $24.5 million as of December 31, 2007 compared with
December 31, 2006. Current liabilities exceeded current assets by $33.2 at December 31, 2007. The
working capital decrease was primarily due to the increase in obligations associated with crude oil
derivative contracts. In addition, our accounts payables have increased since last year as we have
increased our drilling activity in the Barnett Shale area and due to the timing of payment of
accrued interest associated with our senior notes.
The following table summarizes our cash flows from operating, investing and financing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, |
|
|
2007 |
|
2006 |
|
2005 |
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities |
|
$ |
76,619 |
|
|
$ |
74,186 |
|
|
$ |
37,118 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing activities |
|
$ |
(167,397 |
) |
|
$ |
(200,548 |
) |
|
$ |
(84,949 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing activities |
|
$ |
92,684 |
|
|
$ |
125,854 |
|
|
$ |
49,468 |
|
Cash provided from operating activities in 2007 increased $2.4 million over 2006 largely due
to increased operating income which was offset partially with reductions in return on investment in
pipelines and gathering system ventures.
Cash used in investing activities decreased in 2007 compared to 2006, primarily as a result of
the completion of the Harris field acquisition at the start of 2006.
Cash provided by financing activities decreased in 2007 compared to 2006. This is a result of
increased cash flow provided in operations and a decrease in cash used in investing activities in
2007. The result of these two factors allowed the company to reduce its financing activities in
2007.
Historically, we have funded our operations, capital requirements and interest expense
requirements with cash flows from our oil and natural gas properties, borrowings and proceeds from
sales of our equity securities. Although we expect these same capital resources to support our
future activities, we continually review and consider alternative methods of financing.
(44)
Senior Notes Offering
On July 31, 2007, we completed a private offering of unsecured senior notes in the principal amount of $150.0 million. The net proceeds, after payment of typical
transaction expenses, of the senior notes of approximately $143.5 million were used first to retire
all of our indebtedness under our Second Lien Term Loan Agreement, with the remainder being applied
to the repayment of indebtedness under our revolving credit facility.
Shelf Registration Statement; Common Stock Offering
On November 6, 2007, the United States Securities and Exchange Commission declared effective a
shelf registration statement on Form S-3 filed by us to register $250.0 million of securities for
potential future issuance.
On December 6, 2007, we sold 3,000,000 shares of common stock in a public offering for net
proceeds of approximately $52.5 million. We used the net proceeds for general corporate purposes
and for conducting our exploitation, development and acquisition activities in certain core areas
such as our Permian Basin properties and our Barnett Shale gas project. The proceeds were not
deployed all at once. Pending such use, we used the net proceeds to repay borrowings under our
revolving credit facility. We anticipate that the net proceeds will be available under our
revolving credit facility as needed in the future to finance our exploitation, development and
acquisition activities, subject to our compliance with provisions of our revolving credit facility
that are conditions to loans and funding under our revolving credit facility and any recalculation
of our borrowing base.
The available balance of our $250.0 million universal shelf registration statement was $194.5
million as of December 31, 2007.
In the future, we may, in one or more offerings, offer and sell debt securities and additional
equity securities under our shelf registration statement.
Revolving Credit Facility
Our
Third Amended and Restated Credit Agreement, or the Revolving
Credit Agreement, with a
group of bank lenders provides us with a revolving line of credit having a borrowing base
limitation of $200.0 million at December 31, 2007. The total amount that we can borrow and have
outstanding at any one time is limited to the lesser of $350.0 million or the borrowing base
established by the lenders. At December 31, 2007, the principal amount outstanding under our
revolving credit facility was $60.0 million, excluding $445,000 reserved for our letters of credit.
We have pledged substantially all of our producing and natural gas properties to secure the
repayment of our indebtedness under the Revolving Credit Agreement.
The Revolving Credit Agreement allows us to borrow, repay and reborrow amounts available under
the revolving credit facility. The amount of the borrowing base is based primarily upon the
estimated value of our oil and natural gas reserves. The borrowing base amount is redetermined by
the lenders semi-annually on or about April 1 and October 1 of each year or at other times required
by the lenders or at our request. If, as a result of the lenders redetermination of the borrowing
base, the outstanding principal amount of our loans exceeds the borrowing base, we must either
provide additional collateral to the lenders or repay the outstanding principal of our loans in an
amount equal to the excess. Except for the principal payments that may be required because of our
outstanding loans being in excess of the borrowing base, interest only is payable monthly.
Loans made to us under this revolving credit facility bear interest at the base rate of
Citibank, N.A. or the LIBOR rate, at our election. Generally, Citibanks base rate is equal to
its prime rate as announced from time to time by Citibank.
The LIBOR rate is generally equal to the sum of (a) the rate designated as British Bankers
Association Interest Settlement Rates and offered in one, two, three, six or twelve month interest
periods for deposits of $1.0 million, and (b) a margin ranging from 2.00% to 2.50%, depending upon
the outstanding principal amount of our loans. If the principal amount outstanding is equal to or
greater than 75% of the borrowing base, the margin is 2.50%. If the principal amount outstanding is
equal to or greater than 50%, but less than 75% of the borrowing base, the margin is 2.25%. If the
principal amount outstanding is less than 50% of the borrowing base, the margin is 2.00%.
(45)
The interest rate we are required to pay on our borrowings, including the applicable margin,
may never be less than 5.00%. At December 31, 2007, our weighted average base rate and LIBOR rate,
plus the applicable margin, was 6.84% on $60.0 million, the outstanding principal amount of our
revolving loan on that same date.
In the case of base rate loans, interest is payable on the last day of each month. In the case
of LIBOR loans, interest is payable on the last day of each applicable interest period.
If the total outstanding borrowings under the revolving credit facility are less than the
borrowing base, we are required to pay an unused commitment fee to the lenders in an amount equal
to .25% of the daily average of the unadvanced portion of the borrowing base. The fee is payable
quarterly.
If the borrowing base is increased, we are also required to pay a fee of .375% on the amount
of any such increase.
All outstanding principal and accrued and unpaid interest under the revolving credit facility
is due and payable on October 31, 2010. The maturity date of our outstanding loans may be
accelerated by the lenders upon the occurrence of an event of default under the Revolving Credit
Agreement.
The Revolving Credit Agreement presently contains financial covenants and other restrictions,
some of which prohibit us from:
|
|
|
creating, incurring, assuming or permitting to exist any lien, security interest or
other encumbrance on any of our assets or properties, except specified permitted liens; |
|
|
|
|
selling, leasing, transferring or otherwise disposing of any of our assets, except
(a) extracted petroleum hydrocarbons sold in the ordinary course of our business; (b)
worthless or obsolete equipment, and interests in oil and natural gas leases, or
portions thereof, not capable of being held by production of oil, natural gas or other
hydrocarbons or minerals in commercial quantities; and (c) transfers to us or any
subsidiary; |
|
|
|
|
allowing our current ratio (as adjusted for available borrowing and unrealized
derivative losses) to be less than 1.0 to 1.0 as of the end of any fiscal quarter; |
|
|
|
|
allowing our ratio of consolidated funded debt to consolidated EBITDA for any fiscal
quarter (calculated at the end of each fiscal quarter using the results of the
immediately preceding twelve-month period) to exceed (a) 4.25 to 1.00 during 2007, (b)
4.00 to 1.00 during 2008, or (c) 3.50 to 1.00 during 2009 and thereafter; |
|
|
|
|
allowing our adjusted consolidated net worth to be less than the sum of (a) $85.0
million, plus (b) 75% of the net proceeds from the sale of any equity securities, plus
(c) 50% of our consolidated net income for each fiscal quarter determined on a
cumulative basis from September 30, 2005; |
|
|
|
|
forming any new subsidiary or consolidating or merging with or into any other
entity, except for certain intra-company consolidations or mergers where we are the
surviving entity; |
|
|
|
|
becoming liable in respect of any indebtedness, or guaranteeing or otherwise in any
manner becoming liable for indebtedness or obligations of any other person, except for
(a) indebtedness incurred in connection with our revolving credit facility; (b) taxes,
assessments and government charges; (c) obligations arising out of interest rate
management transactions permitted under our revolving credit facility; (d) indebtedness
evidenced by our 101/4% senior notes due 2014 not to exceed the aggregate principal
amount of $150.0 million; (e) indebtedness incurred in the ordinary course of business
that is not more than 60 days past due; or (f) other indebtedness not exceeding
$1,000,000 in the aggregate; |
|
|
|
|
declaring, paying or making any loans, advances, distributions or dividends to our
equity owners, or acquiring, redeeming or retiring any stock or other security issued
by us, except for certain purchases of the notes and certain intra-company dividends or
distributions from our subsidiaries to us; |
(46)
|
|
|
making or permitting to remain outstanding any loans or advances to any person or
entity, except (a) advances made in the ordinary course of our business; (b) other
loans or advances to a third party not to exceed $1.0 million in the aggregate; or (c)
intra-company loans; |
|
|
|
|
discounting, or selling with recourse, or selling for less than market value, any of
our notes receivable or accounts receivable; |
|
|
|
|
permitting any material change in the character of our business; |
|
|
|
|
entering into transactions with our affiliates, except transactions upon terms that
are no less favorable than could be obtained in a transaction negotiated at arms
length with an unrelated third party; |
|
|
|
|
entering into commodity hedging or interest rate management transactions, except
transactions required by our revolving credit facility, consented to by our lenders, or
transactions designed to hedge, provide a floor price for, or swap crude oil or natural
gas, provided certain conditions are satisfied; |
|
|
|
|
making any investments in any entity, except (a) investments with maturities of not
more than 180 days in direct obligations of the United States of America or any agency
thereof; (b) investments in certain certificates of deposits; (c) our existing
investments at December 23, 2005; (d) other investments not to exceed $10.0 million in
the aggregate when aggregated with loans and advances permitted to be made or remain
outstanding under our revolving credit facility during 2007 and $1.0 million in the
aggregate when aggregated with other permitted loans and advances for calendar years
after 2007; (e) investments in certain certificates of deposit not to exceed $50,000;
or (f) investments in any subsidiary; |
|
|
|
|
permitting any material amendment to our organizational or governing documents; |
|
|
|
|
permitting any plan subject to ERISA to (a) engage in any prohibited transaction
as such term is defined in Section 4975 of the Internal Revenue Code of 1986, as
amended; (b) incur any accumulated funding deficiency as such term is defined in
Section 302 of ERISA; or (c) terminate in a manner which could result in the imposition
of a lien on its property pursuant to Section 4068 of ERISA; |
|
|
|
|
permitting any change in accounting method or fiscal year; |
|
|
|
|
allowing our subsidiaries to issue or sell to any third party any equity interest in
them, or any option, warrant or other right to acquire any such equity interest; |
|
|
|
|
making any amendment or entering into any agreement to amend or otherwise change the
Indenture governing our 101/4% senior notes due 2014, failing to comply with the terms of
the Indenture, or, except as specifically required by the Indenture, making any
prepayment of amounts owing under such notes; or |
|
|
|
|
permitting or incurring any lease obligations which would cause the aggregate amount
of all payments pursuant to all such leases to exceed $1,000,000 in any twelve month
period during the life of such leases, except for oil and gas related leases. |
As of December 31, 2007 we were in compliance with all of the covenants in our Revolving
Credit Agreement.
Second Lien Term Loan Facility
Until July 31, 2007, we also had a $50.0 million term loan available to us under our Second
Lien Term Loan Agreement, or the Second Lien Agreement. Similar to our Revolving Credit
Agreement, interest on loans made to us under this credit facility were, at our election, either an
alternate base rate or a rate designated in the Second Lien Agreement as the LIBO rate. The
alternate base rate was the greater of (a) the prime rate in effect on any day and (b) the Federal
Funds Effective Rate in effect on such day plus -1/2 of 1%, plus a margin of 3.50% per annum.
(47)
The LIBO rate was generally equal to the sum of (a) a rate appearing in the Dow Jones Market
Service for the applicable interest periods offered in one, two, three or six month periods and (b)
an applicable margin rate per annum equal to 4.50%.
Our producing oil and natural gas properties were also pledged to secure payment of our
indebtedness under this facility, but the liens granted to the lenders under the Second Lien
Agreement were second and junior to the rights of the lienholders under the Revolving Credit
Agreement.
In the case of alternate base rate loans, interest was payable the last day of each March,
June, September and December. In the case of LIBO loans, interest was payable the last day of the
interest period applicable to each tranche, but not to exceed intervals of three months.
Upon completion of our senior notes offering, described below, we paid off and terminated this
facility with $50.2 million of the net proceeds from the offering. As a result we charged to
earnings $760,000 of previously capitalized debt issuance cost.
Senior Notes
Purchase Agreement. On July 26, 2007, we entered into a Purchase Agreement among us
and Jefferies & Company, Inc., Merrill, Lynch Pierce Fenner and Smith Incorporated and BNP Paribas
Securities Corp., or the Initial Purchasers, relating to the sale and issuance of $150.0 million
principal amount of 10 1/4% Senior Notes due 2014, or the senior notes. The Purchase Agreement
contains customary representations and warranties of the parties and indemnification and
contribution provisions. The Initial Purchasers or their respective affiliates have provided, and
may in the future from time to time provide, financial advisory, investment banking or commercial
banking services to us or our affiliates, for which they have received, and we expect will receive,
customary fees. In particular, an affiliate of BNP Paribas Securities Corp. acts as agent and
lender under our revolving credit facility and, prior to its termination, our second lien term loan
facility, and has received and will continue to receive fees for their services.
On July 31, 2007, we completed the private offering of the senior notes in the principal
amount of $150.0 million. The senior notes were recorded at the principal amount net of
underwriters discount and related expenses of $4.8 million.
Indenture. On July 31, 2007, we issued the senior notes pursuant to an Indenture
dated July 31, 2007 between us and Wells Fargo Bank, National Association, as Trustee in a
transaction exempt from the registration requirements under the Securities Act of 1933, or the
Securities Act. The senior notes were sold within the United States only to qualified
institutional buyers in reliance on Rule 144A under the Securities Act and to Institutional
Accredited Investors pursuant to Rule 501(a)(1), (2), (3) or (7) under the Securities Act.
We used the net proceeds from the issuance to repay outstanding indebtedness under our
existing Revolving Credit Agreement and Second Lien Agreement.
Interest on the senior notes of 10 1/4% per annum on the principal amount of the senior notes is
payable semi-annually on February 1 and August 1 of each year to holders of record at the close of
business on the preceding January 15 and July 15, respectively, commencing on February 1, 2008.
Considering the discount on the senior notes, the effective interest rate is 10.92%. The senior
notes will mature on August 1, 2014. The senior notes are our unsecured senior obligations and
rank equally in right of payment with all of our existing and future senior indebtedness and are
effectively subordinated in right of payment to all of our existing and future secured
indebtedness, including debt of our senior credit agreement.
On or after August 1, 2011, we may redeem all or a part of the senior notes at any time or
from time to time at the following redemption prices (expressed as percentages of the principal
amount) plus accrued and unpaid interest on the senior notes, if any, to the applicable redemption
date, if redeemed during the 12-month period beginning August 1 of the years indicated:
|
|
|
|
|
Year |
|
Redemption Price |
|
|
|
|
|
2011 |
|
|
105.125 |
% |
|
|
|
|
|
2012 |
|
|
102.563 |
% |
|
|
|
|
|
2013 |
|
|
100.000 |
% |
(48)
Prior to August 1, 2010, we may on one or more occasions redeem up to an aggregate amount
equal to 35% of the aggregate principal amount of the senior notes, at a redemption price of
110.25% of the principal amount of the senior notes, plus accrued and unpaid interest, if any, to
the redemption date, with the net cash proceeds of one
or more equity offerings; provided, that (i) at least 65% in aggregate principal amount of
the senior notes originally issued remains outstanding immediately after the occurrence of such
redemption (excluding senior notes held by us or any of our subsidiaries) and (ii) each such
redemption occurs within 90 days of the date of the closing of the related equity offering.
In addition, at any time prior to August 1, 2011, we may redeem all or part of the senior
notes at a redemption price equal to:
(i) 100% of the principal amount thereof, plus
(ii) a make-whole premium, and accrued and unpaid interest, if any, to, the
redemption date. Generally, the make-whole premium is an amount equal to the greater of
(a) 1% of the principal amount of the senior notes being redeemed and (b) the excess of the
present value of the redemption price of such notes as of August 1, 2011 plus all required
interest payments due through August 1, 2011 (computed at a discount rate equal to a
specified U.S. Treasury Rate plus 50 basis points), over the principal amount of the
senior notes being redeemed.
If we experience a change of control, we will be required to make an offer to repurchase the
senior notes at a price equal to 101% of the principal amount thereof, plus accrued and unpaid
interest to the date of repurchase. Generally, a change of control means:
|
|
|
the sale or other disposition of all or substantially all of our assets; |
|
|
|
|
the adoption by the Board of Directors of a plan of liquidation or dissolution; |
|
|
|
|
any person becomes the owner of more than 50% of our voting stock; |
|
|
|
|
the first day on which a majority of the members of the Board of Directors of
Parallel are not continuing directors; or |
|
|
|
|
certain mergers and consolidations with or into any other person. |
Upon an event of default, the Trustee or the holders of at least 25% in principal amount of
the outstanding senior notes may declare the entire principal of, premium, if any, accrued and
unpaid interest, if any, and liquidated damages, if any, on all the senior notes to be due and
payable immediately. Subject to certain qualifications, an event of default includes, generally:
|
|
|
default for 30 days in the payment when due of interest on the senior notes; |
|
|
|
|
default in the payment when due of the principal of the senior notes; |
|
|
|
|
our failure to comply with the covenants or agreements in the Indenture; |
|
|
|
|
defaults on indebtedness under other mortgages, indentures or instruments which
results from our failure to pay the principal or interest on such indebtedness or which
results in the acceleration of such indebtedness prior to its maturity and the
principal amount of any such indebtedness aggregates $10.0 million or more; |
|
|
|
|
our failure to pay final judgments in excess of $10.0 million; |
|
|
|
|
any subsidiary guarantee is held in any judicial proceeding to be unenforceable or
invalid; and |
|
|
|
|
certain events of bankruptcy or insolvency with respect to us or certain of our
subsidiaries. |
(49)
Subject to certain exceptions and qualifications, the Indenture restricts our ability and any
future subsidiaries to:
|
|
|
transfer or sell assets; |
|
|
|
|
make investments; |
|
|
|
|
pay dividends, redeem subordinated indebtedness or make other restricted payments; |
|
|
|
|
incur or guarantee additional indebtedness or issue disqualified capital stock; |
|
|
|
|
create or incur liens; |
|
|
|
|
incur dividend or other payment restrictions affecting certain subsidiaries; |
|
|
|
|
consummate a merger, consolidation or sale of all or substantially all of our
assets; |
|
|
|
|
enter into transactions with affiliates; and |
|
|
|
|
engage in businesses other than the oil and gas business. |
Registration Rights Agreement. On July 31, 2007, we also entered into a Registration
Rights Agreement with the Initial Purchasers relating to the senior notes. We agreed to use our
commercially reasonable efforts to prepare and, not later than 180 days after the date of original
issue of the senior notes, file an exchange offer registration statement with the Securities and
Exchange Commission with respect to an offer to exchange the senior notes for substantially
identical notes that are registered under the Securities Act. We filed an exchange offer
registration statement with the SEC on January 4, 2008. We also agreed to use our reasonable best
efforts to have such registration statement declared effective by the SEC within 210 days after
July 31, 2007. The registration statement became effective on January 29, 2008. Additionally, we
further agreed to promptly commence the exchange offer after such registration statement is
declared effective by the SEC and to keep such exchange offer open for at least 20 business days
after notice is mailed to the holders of the senior notes. We also agreed to use our reasonable
best efforts to keep the exchange offer registration statement effective and to amend and
supplement the prospectus contained therein.
If we fail to meet certain specified registration obligations applicable to the senior notes,
then additional interest will accrue over and above the interest set forth in the senior notes from
and including the date on which any such registration default occurs but excluding the date on
which all such registration defaults have been cured. The rate of the additional interest will be
0.25% per year for the first 90-day period immediately following the occurrence of a registration
default, and such rate will increase by an additional 0.25% per year with respect to each
subsequent 90-day period until all registration defaults have been cured, up to a maximum
additional interest rate of 1.0% per year.
Preferred Stock
At January 1, 2005 we had 950,000 shares of 6% convertible preferred stock outstanding. The
preferred stock:
|
|
|
required us to pay dividends of $.60 per annum, semi-annually on June 15 and
December 15 of each year; |
|
|
|
|
was convertible into common stock at any time, at the option of the holder, into
2.8751 shares of common stock at an initial conversion price of $3.50 per share,
subject to adjustment in certain events; |
|
|
|
|
was redeemable at our option, in whole or in part, for $10 per share, plus accrued
dividends; |
|
|
|
|
had no voting rights, except as required by applicable law; |
|
|
|
|
was senior to the common stock with respect to dividends and on liquidation,
dissolution or winding up of Parallel; and |
|
|
|
|
had a liquidation value of $10 per share, plus accrued and unpaid dividends. |
(50)
As of June 6, 2005, all 950,000 outstanding shares of 6% convertible preferred stock had been
converted into 2,714,280 shares of common stock.
Commodity Price Risk Management Transactions and Effects of Derivative Instruments
The purpose of our derivative transactions is to provide a measure of stability in our cash
flows. The derivative trade arrangements we have employed include collars, costless collars, floors
or purchased puts, and oil, natural gas and interest rate swaps. In 2003, we designated our
derivative trades as cash flow hedges under the provisions of SFAS 133, as amended. Although our
purpose for entering into derivative trades has remained the same, contracts entered into after
June 30, 2004 have not been designated as cash flow hedges.
At December 31, 2006, we had no derivatives in place that were designated as cash flow hedges.
All commodity derivative contracts at December 31, 2007 are accounted for by mark-to-market
accounting whereby changes in fair value are charged to earnings. Changes in the fair values of
derivatives are recorded in our Consolidated Statements of Operations as these changes occur in the
Other income (expense), net. To the extent these trades relate to production in 2008 and beyond,
and oil prices increase, we will report a loss currently, but if there is no further change in
prices, our revenue will be correspondingly higher (than if there had been no price increase) when
the production is sold.
All interest rate swaps that we have entered into for 2007 and beyond are accounted for by
mark-to-market accounting as prescribed in SFAS 133.
We are exposed to credit risk in the event of nonperformance by the counterparties to our
derivative trade instruments. However, we periodically assess the creditworthiness of the
counterparties to mitigate this credit risk.
For additional information about our price risk management transactions, see Item. 7A of this
Annual Report on Form 10-K, beginning on page 54.
Future Capital Requirements
Our capital expenditure budget for 2008 is approximately $127.2 million and is highly
dependent on future oil and natural gas prices and the availability of funding. The timing of most
of our capital expenditures is discretionary because we have not made any significant long-term
capital expenditure commitments. Consequently, we have a significant degree of flexibility to
adjust the level of such expenditures according to market conditions. In addition to the impact
that oil and natural gas prices will have on our budget, these expenditures will also be subject
to:
|
|
|
our internally generated cash flows; |
|
|
|
|
the availability of additional borrowings under our revolving credit facility or
from other sources; |
|
|
|
|
the availability of supplies and services; |
|
|
|
|
additional sources of funding; and |
|
|
|
|
our future drilling successes. |
(51)
Contractual Obligations, Commitments and Off-Balance Sheet Arrangements
We have contractual obligations and commitments that may affect our financial condition. The
following table is a summary of our significant contractual obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Obligation Due in Period |
|
|
|
|
Contractual Cash Obligations |
|
2008 |
|
|
2009 |
|
|
2010 |
|
|
2011 |
|
|
2012 |
|
|
After 5 years |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Revolving Credit Facility (secured) |
|
$ |
4,117 |
|
|
$ |
4,106 |
|
|
$ |
63,419 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
71,642 |
|
Senior Notes (unsecured) |
|
|
15,418 |
|
|
|
15,375 |
|
|
|
15,375 |
|
|
|
15,375 |
|
|
|
15,375 |
|
|
|
180,750 |
|
|
|
257,668 |
|
Office Lease (Dinero Plaza) |
|
|
200 |
|
|
|
200 |
|
|
|
33 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
433 |
|
Snyder Field Offices (1) |
|
|
14 |
|
|
|
14 |
|
|
|
14 |
|
|
|
14 |
|
|
|
14 |
|
|
|
521 |
|
|
|
591 |
|
Asset Retirement Obligations(2) |
|
|
598 |
|
|
|
92 |
|
|
|
127 |
|
|
|
85 |
|
|
|
17 |
|
|
|
4,018 |
|
|
|
4,937 |
|
Derivative Obligations |
|
|
30,424 |
|
|
|
7,600 |
|
|
|
5,594 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
43,618 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
50,771 |
|
|
$ |
27,387 |
|
|
$ |
84,562 |
|
|
$ |
15,474 |
|
|
$ |
15,406 |
|
|
$ |
185,289 |
|
|
$ |
378,889 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The Snyder office lease expires upon the cessation of production from the Diamond M
area wells. The lease cost for the office facility is billed to nonaffiliated third
party working interest owners under our joint operating agreements with these third
parties. |
|
(2) |
|
Asset retirement obligations of oil and natural gas assets, excluding salvage value and
accretion. |
Deferred taxes are not included in the table above. The utilization of net operating loss
carryforwards combined with our plans for development and acquisitions may offset any major cash
outflows. However, the ultimate timing of the settlements cannot be precisely determined.
The amounts above include principal payment obligations under the revolving credit facility
and senior notes noted in the table above, and interest payments on such indebtedness. See Note 8
to the Consolidated Financial Statements.
We have no off-balance sheet financing arrangements or any unconsolidated special purpose
entities.
Outlook
The oil and natural gas industry is capital intensive. We make, and anticipate that we will
continue to make, substantial capital expenditures in the exploration for, development and
acquisition of oil and natural gas reserves. Historically, our capital expenditures have been
financed primarily with:
|
|
|
internally generated cash from operations; |
|
|
|
|
proceeds from bank borrowings; and |
|
|
|
|
proceeds from sales of equity securities. |
The continued availability of these capital sources depends upon a number of variables,
including:
|
|
|
our proved reserves; |
|
|
|
|
the volumes of oil and natural gas we produce from existing wells; |
|
|
|
|
the prices at which we sell oil and natural gas; and |
|
|
|
|
our ability to acquire, locate and produce new reserves. |
(52)
Each of these variables materially affects our borrowing capacity. We may from time to time
seek additional financing in the form of:
|
|
|
increased bank borrowings; |
|
|
|
|
sales of our debt and equity securities; |
|
|
|
|
sales of non-core properties; and |
|
|
|
|
other forms of financing. |
Except for our existing revolving credit facility, we do not have any agreements for future
financing and there can be no assurance as to the availability or terms of any such financing.
Inflation
Our drilling costs have escalated and we would expect this trend to continue. However, over
the past several years our commodity prices have increased to offset the effects of cost inflation.
Recent Accounting Pronouncements
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair
Value Measurements (FAS 157). FAS 157 defines fair value as used in numerous accounting
pronouncements, establishes a framework for measuring fair value in accordance with generally
accepted accounting principles and expands disclosure requirements related to the use of fair value
measures in financial statements. FAS 157 will be effective for our financial statements for the
fiscal year beginning January 1, 2008; however, earlier application is encouraged. We are currently
evaluating the impact that adoption might have on our financial position or results of operations,
although we do not expect any impact to be significant.
In February 2007, the FASB issued SFAS 159, The Fair Value Option for Financial Assets and
Financial Liabilities, Including an Amendment of FASB Statement No. 115, (FAS 159) which will
become effective on January 1, 2008. FAS 159 permits entities to measure eligible financial assets,
financial liabilities and firm commitments at fair value, on an instrument-by-instrument basis,
that are otherwise not permitted to be accounted for at fair value under other generally accepted
accounting principles. The fair value measurement election is irrevocable and subsequent changes in
fair value must be recorded in earnings. We will adopt this statement in the first quarter of 2008
and we do not expect to elect the fair value option for any eligible financial instruments and
other items.
In April 2007, the FASB issued FASB Staff Position FIN 39-1, Amendment of FASB Interpretation
No. 39 (FSP FIN 39-1). FSP FIN 39-1 clarifies that a reporting entity that is party to a master
netting arrangement can offset fair value amounts recognized for the right to reclaim cash
collateral (a receivable) or the obligation to return cash collateral (a payable) against fair
value amounts recognized for derivative instruments that have been offset under the same master
netting arrangement. FSP FIN 39-1 is effective for financial statements issued for fiscal years
beginning after November 15, 2007. Adoption of FSP FIN 39-1 is not expected to have a material
impact on our consolidated financial statements.
In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (SFAS
141(R)), which replaces FASB Statement No. 141. SFAS 141(R) establishes principles and
requirements for how an acquirer recognizes and measures in its financial statements the
identifiable assets acquired, the liabilities assumed, any non- controlling interest in the
acquiree and the goodwill acquired. The Statement also establishes disclosure requirements that
will enable users to evaluate the nature and financial effects of the business combination. SFAS
141(R) is effective for acquisitions that occur in an entitys fiscal year that begins after
December 15, 2008, which will be the companys fiscal year 2009. The impact, if any, will depend on
the nature and size of business combinations that Parallel consummates after the effective date.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated
Financial Statementsan amendment of ARB No. 51 (SFAS 160). SFAS 160 requires that accounting
and reporting for minority interests will be recharacterized as noncontrolling interests and
classified as a component of equity. SFAS 160 also establishes reporting requirements that provide
sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS 160
applies to all entities that prepare consolidated financial statements, except not-for-profit
organizations, but will affect only those entities
(53)
that have an outstanding noncontrolling interest
in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective as of
the beginning of an entitys first fiscal year beginning after December 15, 2008, which will be our
fiscal year 2009. Based upon the December 31, 2007 balance sheet, the statement would have no
impact.
Critical Accounting Policies
Our
critical accounting policies are included and discussed in Note 1
to our Consolidated
Financial Statements as of December 31, 2007 and 2006 and for the three years ended December 31,
2007 included elsewhere herein. These critical accounting policies should be read in conjunction
with the Consolidated Financial Statements and the accompanying Notes.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The following quantitative and qualitative information is provided about market risks and our
derivative instruments at December 31, 2007 from which we may incur future earnings, gains or
losses from changes in market interest rates and oil and natural gas prices.
Interest Rate Sensitivity as of December 31, 2007
Our only Financial instruments sensitive to changes in interest rates are our senior notes,
bank debt and interest rate swaps. The table below shows principal cash flows and related interest
rates by expected maturity dates. Interest rates were determined using our interest rate at
December 31, 2007. You should read Note 8 to the Consolidated Financial Statements for further
discussion of our debt that is sensitive to interest rates.
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011 and |
|
|
|
|
2007 |
|
2008 |
|
2009 |
|
2010 |
|
after |
|
Total |
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
Revolving Credit Facility (secured) |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
60,000 |
|
|
$ |
|
|
|
$ |
60,000 |
|
Interest rate |
|
|
6.84 |
% |
|
|
6.84 |
% |
|
|
6.84 |
% |
|
|
6.84 |
% |
|
|
|
|
|
|
|
|
|
Senior notes |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
150,000 |
|
|
$ |
150,000 |
|
Interest rate |
|
|
10.25 |
% |
|
|
10.25 |
% |
|
|
10.25 |
% |
|
|
10.25 |
% |
|
|
10.25 |
% |
|
|
|
|
At December 31, 2007, we had outstanding bank loans in the aggregate principal amount of $60.0
million at an interest rate of 6.84%. Under our revolving credit facility, we may elect an interest
rate based upon the agent banks base lending rate or the LIBOR rate, plus a margin ranging from
2.00% to 2.50% per annum, depending on our borrowing base usage. The interest rate we are required
to pay, including the applicable margin, may never be less than 5.00%. As the interest rate is
variable and reflects current market conditions, the carrying value of our bank debt approximates
the fair value.
At December 31, 2007, we had outstanding senior notes in the aggregate principal amount of
$150.0 million bearing interest at a rate of 10.25% per annum. The carrying value of our 10.25%
senior notes at December 31, 2007 is approximately $145.4 million and their estimated fair value is
approximately $150.0 million. Fair value is estimated based on market trades at or near December
31, 2007. Interest on our senior notes and their carrying value are not affected by changes in
interest rates. However, the fair value of the senior notes increases as interest rates decrease
and their fair value decreases as interest rates increase. Because we have no present plan or
intent to redeem the senior notes, changes in their fair value are not expected to have any effect
on our cash flow in the foreseeable future.
As of December 31, 2007, we employed fixed interest rate swap contracts with BNP Paribas and
Citibank, NA based on the 90-day LIBOR rates at the time of the contracts. These contracts are
accounted for by mark to market accounting as prescribed in SFAS 133. We receive interest based on a 90-day LIBOR rate
and pay the fixed rates shown below. We view these contracts as protection against future interest
rate volatility.
(54)
Below is a table describing the nature of these interest rate swaps and the fair market value
of these contracts as of December 31, 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
Notional |
|
|
Weighted Average |
|
|
Fair Market Value |
|
Period of Time |
|
Amounts |
|
|
Fixed Interest Rates |
|
|
at December 31, 2007 |
|
|
|
($ in millions) |
|
|
|
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1, 2008 thru December 31, 2008 |
|
$ |
100 |
|
|
|
4.86 |
% |
|
$ |
(800 |
) |
January 1, 2009 thru December 31, 2009 |
|
$ |
50 |
|
|
|
5.06 |
% |
|
|
(754 |
) |
January 1, 2010 thru October 31, 2010 |
|
$ |
50 |
|
|
|
5.15 |
% |
|
|
(441 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
$ |
(1,995 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Price Sensitivity as of December 31, 2007
Our major market risk exposure is in the pricing applicable to our oil and natural gas
production. Market risk refers to the risk of loss from adverse changes in oil and natural gas
prices. Realized pricing is primarily driven by the prevailing domestic price for crude oil and
spot prices applicable to the region in which we produce natural gas. Historically, prices received
for oil and natural gas production have been volatile and unpredictable. We expect pricing
volatility to continue. Oil prices we received during 2007 ranged from a low of $47.62 per barrel
to a high of $95.93 per barrel. Natural gas prices we received during 2007 ranged from a low of
$1.37 per Mcf to a high of $16.09 per Mcf. A significant decline in the prices of oil or natural
gas could have a material adverse effect on our financial condition and results of operations.
We use various derivative instruments to minimize our exposure to the volatility of commodity
prices. As of December 31, 2007, we had employed commodity collars and swaps in order to protect
against this price volatility. Although all of the contracts that we have entered into are viewed
as protection against this price volatility, all contracts are accounted for by the mark to
market accounting method as prescribed in SFAS 133.
Below is a description of our active commodity contracts as of December 31, 2007.
Collars. Collars are contracts which combine both a put option, or floor, and a call
option, or ceiling. These contracts may not involve payment or receipt of cash at inception,
depending upon ceiling and floor strike prices.
A summary of our collar positions at December 31, 2007 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
Barrles of |
|
NYMEX Oil Prices |
|
Fair Market |
Period of Time |
|
Oil |
|
Floor |
|
Cap |
|
Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1, 2008 thru December 31, 2008 |
|
|
347,700 |
|
|
$ |
63.42 |
|
|
$ |
83.86 |
|
|
$ |
(4,003 |
) |
January 1, 2009 thru December 31, 2009 |
|
|
620,500 |
|
|
$ |
63.53 |
|
|
$ |
80.21 |
|
|
|
(6,846 |
) |
January 1, 2010 thru October 31, 2010 |
|
|
486,400 |
|
|
$ |
63.44 |
|
|
$ |
78.26 |
|
|
|
(5,153 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MMBtu of |
|
|
WAHA Gas Prices |
|
|
|
|
|
|
|
Natural Gas |
|
|
Floor |
|
|
Cap |
|
|
|
|
|
|
January 1, 2008 thru March 31, 2008 |
|
|
546,000 |
|
|
$ |
6.50 |
|
|
$ |
9.50 |
|
|
|
87 |
|
April 1, 2008 thru December 31, 2008 |
|
|
1,375,000 |
|
|
$ |
6.75 |
|
|
$ |
8.40 |
|
|
|
63 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(15,852 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(55)
Commodity Swaps. Generally, swaps are an agreement to buy or sell a specified
commodity for delivery in the future, but at an agreed fixed price. Swap transactions convert a
floating or market price into a fixed price. For any particular swap transaction, the counterparty
is required to make a payment to us if the reference price for any settlement period is less than
the swap or fixed price for the applicable derivative contract, and we are required to make a
payment to the counterparty if the reference price for any settlement period is greater than the
swap or fixed price for the applicable derivative contract.
We have entered into oil swap contracts with BNP Paribas. A recap for the period of time,
number of Bbls, and weighted average swap prices are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
Barrels of |
|
|
NYMEX Oil |
|
|
Fair Market |
|
Period of Time |
|
Oil |
|
|
Swap Price |
|
|
Value |
|
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1, 2008 thru December 31, 2008 |
|
|
439,200 |
|
|
$ |
33.37 |
|
|
$ |
(25,621 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Our Consolidated Financial Statements and supplementary financial data are included in this
Annual Report on Form 10-K beginning on page F-1.
We have prepared these financial statements in conformity with generally accepted accounting
principles. We are responsible for the fairness and reliability of the financial statements and
other financial data included in this report. In the preparation of the financial statements, it is
necessary for us to make informed estimates and judgments based on currently available information
on the effects of certain events and transactions.
Our independent public accountants, BDO Seidman, LLP, are engaged to audit our financial
statements and to express an opinion thereon. Their audit is conducted in accordance with auditing
standards generally accepted in the United States to enable them to report whether the financial
statements present fairly, in all material respects, our financial position and results of
operations in accordance with accounting principles generally accepted in the United States.
The Audit Committee of our Board of Directors is composed of four Directors who are not our
employees. This committee meets periodically with our independent public accountants and
management. Our independent public accountants have full and free access to the Audit Committee to
meet, with and without management being present, to discuss the results of their audits and the
quality of our financial reporting.
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ITEM 9. |
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CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. |
None.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
We use disclosure controls and procedures to help ensure that information we are required to
disclose in reports that we file with the Securities and Exchange Commission is accumulated and
communicated to our management and recorded, processed, summarized and reported within the time
periods specified by the SEC. As of the end of the period covered by this Annual Report on Form 10-K, the effectiveness of our disclosure
controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as
amended) was evaluated by our management, with the participation of Larry C. Oldham, our President
and Chief Executive Officer (principal executive officer), and Steven D. Foster, our Chief
Financial Officer (principal financial officer). Our Chief Executive Officer and Chief Financial
Officer have concluded that, as of the end of the period covered by this Annual Report on Form
10-K, our disclosure controls and procedures are effective for their intended purposes.
(56)
Managements Annual Report on Internal Control Over Financial Reporting
Management of Parallel is responsible for establishing and maintaining adequate internal
control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act of
1934, as amended.
Our internal control over financial reporting is a process designed by, or under the
supervision of, our principal executive and financial officers, and effected by our Board of
Directors, management and other personnel, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with accounting principles generally accepted in the United States of
America. Our internal control over financial reporting includes those policies and procedures
that:
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pertain to the maintenance of records that, in reasonable detail, accurately and
fairly reflect the transactions and dispositions of our assets; |
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provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with accounting principles generally
accepted in the United States of America, and that our receipts and expenditures are
being made only in accordance with authorizations of management and our Board of
Directors; and, |
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provide reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use or disposition of our assets that could have a material
effect on the financial statements. |
Because of its inherent limitations, internal control over financial reporting may not prevent
or detect misstatements. Therefore, even those systems determined to be effective can provide only
reasonable assurance with respect to financial statement preparation and presentation. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the degree of compliance
with the policies and procedures may deteriorate.
Management assessed the effectiveness of Parallels internal control over financial reporting
as of December 31, 2007. In making this assessment, management used the criteria set forth in
Internal Control Integrated Framework, issued by the Committee of Sponsoring Organizations
(COSO) of the Treadway Commission. As a result of this assessment, management determined that
Parallels internal control over financial reporting, as of December 31, 2007, was effective based
on those criteria.
BDO Seidman, LLP, the independent registered public accounting firm who also audited our
Consolidated Financial Statements included in this Annual Report on Form 10-K, has issued an
attestation report on our internal control over financial reporting as of December 31, 2007, which
is set forth below under Attestation Report.
Changes in Internal Controls
During the fourth quarter of fiscal 2007, there were no changes in our internal control over
financial reporting that materially affected, or are reasonably likely to materially affect, our
internal control over financial reporting.
Attestation Report
Report of Independent Registered Public Accounting Firm
on Internal Control over Financial Reporting
Board of Directors and Shareholders
Parallel Petroleum
Midland, Texas
We have audited Parallel Petroleum Corporations internal control over financial reporting as of
December 31, 2007, based on criteria established in Internal Control Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria).
Parallel Petroleum Corporations management is responsible for maintaining effective internal
control over financial reporting and for its assessment of the effectiveness of internal control
over financial reporting, included in the accompanying Item 9A, Managements Annual
(57)
Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion
on the Companys internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, and testing
and evaluating the design and operating effectiveness of internal control based on the assessed
risk. Our audit also included performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles. A
companys internal control over financial reporting includes those policies and procedures that (1)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of management and directors of the company;
and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Parallel Petroleum Corporation maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2007, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the consolidated balance sheets of Parallel Petroleum Corporation as of
December 31, 2007 and 2006, and the related consolidated statements of operations, comprehensive
income (loss), stockholders equity, and cash flows for each of the three years in the period ended
December 31, 2007 and our report dated February 20, 2008 expressed an unqualified opinion thereon.
BDO Seidman, LLP
Houston, Texas
February 20, 2008
ITEM 9B. OTHER INFORMATION
None.
(58)
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Our Directors and executive officers at February 1, 2008 are as follows:
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Director |
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Name |
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Age |
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Since |
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Position with Company |
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Jeffrey G. Shrader(1)(2)(3)(4)
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57 |
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2001 |
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Director and Chairman of the Board of Directors |
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Larry C. Oldham(1)
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54 |
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1979 |
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Director, President and Chief Executive Officer |
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Donald E. Tiffin
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50 |
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Chief Operating Officer |
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Eric A. Bayley
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59 |
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Vice President of Corporate Engineering |
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John S. Rutherford
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47 |
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Vice President of Land and Administration |
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Steven D. Foster
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52 |
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Chief Financial Officer |
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Edward A. Nash(1)(2)(3)(4)
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59 |
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2007 |
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Director |
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Martin B. Oring(1)(2)(3)(4)
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62 |
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2001 |
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Director |
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Ray M. Poage(1)(2)(3)(4)
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60 |
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2003 |
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Director |
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Member of Hedging and Acquisitions
Committee |
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Member of Compensation Committee |
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Member of Audit Committee |
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Member of Corporate Governance and Nominating Committee |
Mr. Shrader has been a shareholder in the law firm of Sprouse Shrader Smith, Amarillo, Texas,
since January 1993. He has also served as a director of Hastings Entertainment, Inc. since 1992. At
February 1, 2008, Mr. Shrader was Chairman of the Corporate Governance and Nominating Committee of
the Board of Directors.
Mr. Oldham is a founder of Parallel and has served as an officer and Director since its
formation in 1979. Mr. Oldham became President of Parallel in October 1994, and served as Executive
Vice President before becoming President. Effective January 1, 2004, Mr. Oldham became Chief
Executive Officer. Mr. Oldham received a Bachelor of Business Administration degree from West Texas
State University in 1975.
Mr. Tiffin served as Vice President of Business Development from June 2002 until January 1,
2004 when he became Chief Operating Officer. From August 1999 until May 2002, Mr. Tiffin served as
General Manager of First Permian, L.P. and from July 1993 to July 1999, Mr. Tiffin was the Drilling
and Production Manager in the Midland, Texas office of Fina Oil and Chemical Company. Mr. Tiffin
graduated from the University of Oklahoma in 1979 with a Bachelor of Science degree in Petroleum
Engineering.
Mr. Bayley has been Vice President of Corporate Engineering since July 2001. From October 1993
until July 2001, Mr. Bayley was employed by Parallel as Manager of Engineering. From December 1990
to October 1993, Mr. Bayley was an independent consulting engineer and devoted substantially all of
his time to Parallel. Mr. Bayley graduated from Texas A&M University in 1978 with a Bachelor of
Science degree in Petroleum Engineering. He graduated from the University of Texas of the Permian
Basin in 1984 with a Masters of Business Administration degree.
Mr. Rutherford has been Vice President of Land and Administration of Parallel since July 2001.
From October 1993 until July 2001, Mr. Rutherford was employed as Manager of Land/Administration.
From May 1991 to October 1993, Mr. Rutherford served as a consultant to Parallel, devoting
substantially all of his time to Parallels
(59)
business. Mr. Rutherford graduated from Oral Roberts
University in 1982 with a degree in Education, and in 1986 he graduated from Baylor University with
a Masters degree in Business Administration.
Mr. Foster has been the Chief Financial Officer of Parallel since June 2002. From November
2000 to May 2002, Mr. Foster was the Controller and Assistant Secretary of First Permian, L.P. and
from September 1997 to November 2000, he was employed by Pioneer Natural Resources, USA in the
capacities of Director of Revenue Accounting and Manager of Joint Interest Accounting. Mr. Foster
graduated from Texas Tech University in 1977 with a Bachelor of Business Administration degree in
Accounting. He is a certified public accountant.
Mr. Nash served as a consultant to TOTAL Petrochemicals, Inc. from February 2004 until
December 2006, providing advisory services primarily in the areas of corporate relocation,
construction, safety and communications. He also served as a consultant to Clayton Williams
Energy, Inc. from September 2003 to September 2004, primarily in the area of acquisitions. From
2000 to March 2003, Mr. Nash was employed by TOTAL as a Senior Vice President of Special Projects
and as Senior Vice President of its U.S. onshore division. From 1974 to 2000, Mr. Nash was
employed by Fina, Inc. in various capacities, including serving as Vice President of Human
Resources, Vice President Exploration and Production from April 1998 to 2000 and as President of
Fina Natural Gas Company from 1999 to 2000. Mr. Nash graduated from Texas A&M University in 1970
with a Bachelors of Science degree in Mechanical Engineering. He is a registered professional
engineer in Petroleum and Mechanical Engineering. At February 1, 2008, Mr. Nash was Chairman of the
Compensation Committee.
Mr. Oring is an owner and managing member of Wealth Preservation, LLC, a financial counseling
firm founded by Mr. Oring in January 2001. From 1998 to December 2000, Mr. Oring was Managing
Director Executive Services of Prudential Securities Incorporated, and from 1996 to 1998, Mr. Oring
was Managing Director Capital Markets of Prudential Securities Incorporated. From 1989 to 1996, Mr.
Oring was Manager of Capital Planning for The Chase Manhattan Corporation. Mr. Oring is also a
director of PetroHunter Energy Corporation. At February 1, 2008, Mr. Oring was Chairman of the
Hedging and Acquisitions Committee of the Board of Directors.
Mr. Poage was a partner in KPMG LLP from 1980 to June 2002 when he retired. Mr. Poages
responsibilities included supervising and managing both audit and tax professionals and providing
services, primarily in the area of taxation, to private and publicly held companies engaged in the
oil and natural gas industry. At February 1, 2008, Mr. Poage was Chairman of the Audit Committee of
the Board of Directors.
Directors hold office until the annual meeting of stockholders following their election or
appointment and until their respective successors have been dully elected or appointed.
Officers are appointed annually by the Board of Directors to serve at the Boards discretion
and until their respective successors in office are duly appointed.
There are no family relationships between any of Parallels Directors or officers.
Consulting Arrangements
As part of our overall business strategy, we continually monitor our general and
administrative expenses. Decisions regarding our general and administrative expenses are made
within parameters we believe to be compatible with our size, the level of our activities and
projected future activities. Our goal is to keep general and administrative expenses at acceptable
levels, without impairing the quality of services and organizational structure necessary for
conducting our business. In this regard, we retain outside advisors and consultants from time to
time to provide technical and administrative support services in the operation of our business.
Corporate Governance
Under the Delaware General Corporation Law and Parallels bylaws, our business, property and
affairs are managed by or under the direction of the Board of Directors. Members of the Board are
kept informed of Parallels business through discussions with the Chairman of the Board, the Chief
Executive Officer and other officers, by reviewing materials provided to them and by participating
in meetings of the Board and its committees. We currently have five members of the Board, including
Edward A. Nash, Larry C. Oldham, Martin B. Oring, Ray M. Poage and Jeffrey G. Shrader. The Board
has determined that all of our Directors, other than Mr. Oldham, are independent for the purposes of NASD Rule 4200(a) (15). The Board based these determinations
primarily on responses of the Directors and executive officers to questions regarding employment
and compensation history, affiliations and family and other relationships and on discussions among
the Directors.
(60)
The Board has four standing committees:
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the Audit Committee; |
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the Corporate Governance and Nominating Committee; |
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the Compensation Committee; and |
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the Hedging and Acquisitions Committee. |
Audit Committee
The Audit Committee of the Board of Directors reviews the results of the annual audit of our
Consolidated Financial Statements and recommendations of the independent auditors with respect to
our accounting practices, policies and procedures. As prescribed by our Audit Committee charter,
the Audit Committee also assists the Board of Directors in fulfilling its oversight
responsibilities, reviewing our systems of internal accounting and financial controls, and the
independent audit of our Consolidated Financial Statements.
The Audit Committee of the Board of Directors consists of four Directors, all of whom have no
financial or personal ties to Parallel (other than director compensation and equity ownership as
described in this Annual Report on Form 10-K) and meet the Nasdaq standards for independence. The
Board of Directors has determined that at least one member of the Audit Committee, Ray M. Poage,
meets the criteria of an audit committee financial expert as that term is defined in Item
407(d)(5) of Regulation S-K, and is independent for purposes of Nasdaq listing standards and Rule
10A-3(b)(1) under the Securities Exchange Act of 1934, as amended. Mr. Poages background and
experience includes service as a partner of KPMG LLP where Mr. Poage participated extensively in
accounting, auditing and tax matters related to the oil and natural gas business. The Audit
Committee operates under a charter which can be viewed in our website on www.plll.com.
The current members of the Audit Committee are Edward A. Nash, Martin B. Oring, Ray M. Poage
(Chairman) and Jeffrey G. Shrader.
Corporate Governance and Nominating Committee
The Boards Corporate Governance and Nominating Committee operates under a charter outlining
the functions and responsibilities of the committee, including recommending to the full Board of
Directors nominees for election as directors of Parallel, and making recommendations to the Board
of Directors from time to time as to matters of corporate governance. The current members of this
committee are Edward A. Nash, Martin B. Oring, Ray M. Poage and Jeffrey G. Shrader A copy of the
charter can be viewed in our website at www.plll.com.
The committee will consider candidates for Director suggested by stockholders. Stockholders
wishing to suggest a candidate for Director should write to any one of the members of the committee
at his address shown under Item 12 of this Annual Report on Form 10-K. Suggestions should include:
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a statement that the writer is a stockholder and is proposing a candidate for
consideration by the committee; |
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the name of and contact information for the candidate; |
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a statement of the candidates age, business and educational experience; |
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information sufficient to enable the committee to evaluate the candidate; |
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a statement detailing any relationship between the candidate and any joint interest
owners, customer, supplier or competitor of Parallel; |
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detailed information about any relationship or understanding between the proposing
stockholder and the candidate; and |
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a statement that the candidate is willing to be considered and willing to serve as a
Director if nominated and elected. |
(61)
Compensation Committee
The current members of the Compensation Committee are Edward A. Nash, Martin B. Oring, Ray M.
Poage and Jeffrey G. Shrader. Mr. Nash was appointed to serve on the committee on August 29, 2007
and presently acts as the Chairman of the Compensation Committee. The Compensation Committee of the
Board of Directors administers and approves all elements of compensation and awards for our
executive officers. The Committee has the responsibility to review and approve the corporate goals
and objectives relevant to each executive officers compensation, evaluates individual performance
of each executive in light of those goals and objectives, and determines and approves each
executives compensation based on this evaluation.
Members of the Committee are non-management directors who, in the opinion of the Board,
satisfy the independence standards of the Nasdaq Global Market. The Committee has the sole
authority to retain consultants and advisors as it may deem appropriate in its discretion, and sole
authority to approve related fees and retention terms for these advisors.
Generally, on its own initiative the Compensation Committee reviews the performance and
compensation of all of our executives and then reviews and discusses its conclusions and
recommendations with management.
Hedging and Acquisitions Committee
The Hedging and Acquisitions Committee presently consists of all five of our Directors,
including Messrs. Nash, Oldham, Oring, Poage and Shrader. Mr. Oring presently serves as Chairman of
this committee. With respect to derivative contracts, the committee reviews, assists, and advises
management on overall risk management strategies and techniques with a view to implementing prudent
commodity and interest rate derivative arrangements. The Hedging and Acquisitions Committee also
reviews with management plans and strategies for pursuing acquisitions.
Code of Ethics
The Board has adopted a code of ethics which applies to all of our Directors, officers and
employees, including our chief executive officer, chief financial officer and all other financial
officers and executives. You may review the code of ethics on our website at www.plll.com.
A copy of our code of ethics has also been filed with the Securities and Exchange Commission and is
incorporated by reference as an exhibit to this Annual Report on Form 10-K. We will provide without
charge to each person, upon written or oral request, a copy of our code of ethics. Requests should
be directed to:
Manager of Investor Relations
Parallel Petroleum Corporation
1004 N. Big Spring, Suite 400
Midland, Texas 79701
Telephone: (432) 684-3727
Stockholder Communications with Directors
Parallel stockholders who want to communicate with any individual Director can write to that
Director at his address shown under Item 12 of this Annual Report on Form 10-K.
Your letter should indicate that you are a Parallel stockholder. Depending on the subject
matter, the Director will:
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if you request, forward the communication to the other Directors; |
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request that management handle the inquiry directly, for example where it is a
request for information about the company or it is a stock-related matter; or |
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not forward the communication to the other Directors or management if it is
primarily commercial in nature or if it relates to an improper or irrelevant topic. |
(62)
Director Attendance at Annual Meetings
We typically schedule a Board meeting in conjunction with our annual meeting of stockholders
and expect that our Directors will attend, absent a valid reason, such as illness or a schedule
conflict. Last year, all of the individuals then serving as Directors attended our annual meeting
of stockholders.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires our Directors and officers to
file periodic reports with the Securities and Exchange Commission. These reports show the
Directors and officers ownership, and the changes in ownership, of our common stock and other
equity securities. To our knowledge, all Section 16(a) filing requirements were complied with
during 2007.
ITEM 11. EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
Introduction and Overview
The Compensation Committee of the Board of Directors is responsible for determining the types
and amounts of compensation we pay to our executives. Our Committee operates under a written
charter that you can view on our website at www.plll.com. The Board of Directors has
affirmatively determined that each Director who is a member of the Committee meets the independence
requirements of the Nasdaq Global Market. The Board determines, in its business judgment, whether a
particular Director satisfies the requirements for membership on the Committee set forth in the
Committees charter. None of the members of the Compensation Committee are current or former
employees of Parallel or any of its subsidiaries.
Our Compensation Committee is responsible for formulating and administering the overall
compensation principles and plans for Parallel. This includes establishing the compensation paid
to our officers, administering our compensation plans and, generally, reviewing our compensation
programs at least annually.
The Committee periodically meets in executive session without members of management or
management directors present and reports to the Board of Directors on its actions and
recommendations.
We discuss below the philosophy, objectives and principles we followed last year for
compensating our executive officers.
Compensation Philosophy and Objectives
The Committees compensation philosophy is to provide an executive compensation program that:
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is competitive with compensation programs offered by comparable companies engaged in
businesses similar to ours; |
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rewards performance, skills and talents necessary to advance our company objectives
and further the interests of stockholders; |
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is balanced between a fair and reasonable cash compensation and incentives linked to
Parallels overall operating performance; and |
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is fair to our executives, but within reasonable limits. |
The Companys practice is and has been to link compensation with performance, measured at the
company level, and to emphasize the importance of each executives contribution to the overall
success of the Company. The overall objectives of our compensation philosophy are to:
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provide a reasonable and competitive level of current annual income; |
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provide incentives that encourage our executives to continue their employment with
us; |
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motivate executives to accomplish our company goals and reward performance; |
(63)
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create an environment conducive to company-oriented success rather than individual
success; |
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align compensation and benefits with business strategy and competitive market data; |
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encourage the application of prudent decision making processes in an industry marked
by volatility and high risk; and |
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provide for overall compensation arrangements that are fair and reasonable pay for
achievements beneficial to Parallel and its stockholders. |
Our Committee supports these objectives by emphasizing compensation arrangements that we
believe will attract and retain qualified executives and reward them for creating a solid platform
for the long-term growth and success of Parallel. At the same time, we are mindful of, and try to
balance our executive compensation arrangements with, the interests and concerns of stockholders.
To more fully understand our current compensation philosophies and practices, it is important
to keep in mind some historical milestones that have influenced the shaping of our compensation
practices. For instance, it was not until May 2002 that we had more than seven employees, as
compared to 43 employees that we currently have; our total market capitalization (including shares
held by our officers and directors) at December 31, 2002 was approximately $58.0 million, as
compared to a total market capitalization (including shares held by our officers and directors) of
approximately $727.0 million at December 31, 2007; and it was not until the latter part of 2004
that the market price of our stock consistently exceeded $5.00 per share. Given our small size,
limited staff and limited resources in earlier years, the compensation of our executives consisted
primarily of salaries, cash bonuses and stock options, with an emphasis on the use of stock
options. Since November 2002, however, we have limited the use of stock option awards to our
executives and we relied more heavily on our Incentive and Retention Plan as a long-term incentive.
For 2007, we chose, as we have in the past, to continue a relatively simple compensation framework
for our executives. We believe the benefits of this approach include maintaining a higher degree of
understanding and certainty for our executives as well as the investing public, and avoiding
complex benefit packages and agreements that are less transparent than our compensation program and
that require significant time and cost to properly administer. However, as we describe below under
Analysis and Outlook, we anticipate adopting a long-term equity based incentive plan, in part due
to the oil and natural gas exploration and production industry continuing to experience increased
competition for qualified personnel at all levels.
Compensation Components
Our judgments regarding executive compensation are primarily based upon our assessment of
company performance, and each executive officers leadership, performance and individual
contributions to Parallels business. The accounting and tax treatment of different elements of
compensation has not had a significant impact on our use of any particular form of compensation. In
reviewing the overall compensation of our officers, we have historically considered and used a mix
of the following components or elements of executive compensation:
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base salaries; |
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stock option grants; |
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annual cash bonuses; |
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health and life insurance plans which are generally available to all of our
employees; |
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contributions by Parallel to our 401(k) retirement plan; |
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an equity based cash incentive plan; |
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change of control arrangements; and |
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limited perquisites and personal benefits provided by Parallel to our executive
officers. |
(64)
To help give you a better understanding of the overall compensation picture of our executives,
we have included the following table showing the elements of executive compensation we have used in
the past and certain types of executive compensation that we have not used:
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Used by |
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Parallel |
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Used by |
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Not Used by |
Elements of Compensation |
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Parallel in 2007 |
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Parallel |
Base salaries |
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ü |
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ü |
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Employment agreements |
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Cash bonuses |
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ü |
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ü |
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Stock awards |
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ü |
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Change of control/severence arrangements |
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ü |
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ü |
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Defined benefit pension plan |
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ü |
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Defined contribution plan |
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ü |
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ü |
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Stock options |
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ü |
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Tax gross-ups |
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ü |
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Employee stock purchase/
ownership plan |
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ü |
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Supplemental executive retirement
plans/benefits |
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ü |
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Deferred compensation plan |
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ü |
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Incentive and retention plan |
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ü |
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ü |
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Limited perquisites and personal benefits |
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ü |
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ü |
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Evaluation Factors
In addition to comparing the compensation packages of our officers with the compensation
packages of officers of other companies similar to Parallel, we also relied, as we have in the
past, on our general knowledge and experience in the oil and natural gas industry, focusing on a
subjective analysis of each of our executives contributions to Parallels overall performance.
Except for comparing the salaries and bonuses of our executives with the salaries and bonuses of
executives in our peer group of companies, other specific performance levels or benchmarks were not
used in 2007 to establish salaries, cash bonuses or grant stock options. We do take into account
historic comparisons of Parallels financial and operational performance. The link between pay and
company performance is based primarily on the Compensation Committees evaluation of periodic
results of certain elements of company performance. Generally, our evaluations are influenced
equally by operational metrics and financial metrics.
We have not adopted specific target or performance levels with respect to quantitative or
qualitative performance-related factors which would automatically result in increases or decreases
in compensation. Instead, we make subjective determinations based upon a consideration of many
factors, including those we have described below. We have not assigned relative weights or rankings
to these factors. Specific elements of company performance and individual performance that we
consider in setting compensation policies and making compensation decisions include the following
factors, several of which we consider in the context of Parallel alone and by comparison with peer
companies:
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growth in the quantity and value of our proved oil and natural gas reserves; |
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volumes of oil and natural gas produced by Parallel and our executives ability to
replace oil and natural gas produced with new oil and natural gas reserves; |
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cash flows from operations; |
(65)
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revenues; |
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earnings per share; |
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the market value of our common stock; |
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the extent to which the officers have been successful in finding and creating
opportunities for Parallel to participate in acquisition, exploitation and drilling
ventures having quality prospects; |
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the ability of our officers to formulate and maintain sound budgets for our business
activities; |
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the overall financial condition of Parallel; |
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the achievement by management of specific tasks and goals set by the Board of
Directors from time to time; |
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the effectiveness of our compensation packages in motivating officers to remain in
Parallels employment; |
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oil and gas finding costs and operating costs; and |
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the ability of our executives to effectively implement risk management practices,
including oil and natural gas and interest rate hedging activities. |
In addition to considering the elements of performance described above, other factors that we
consider in determining compensation include:
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longevity of service; and |
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the individual performance, leadership, business knowledge and level of
responsibility of our officers. |
Although we believe the key components of our executive compensation program, base salary,
cash bonuses and the potential for awards under our Incentive and Retention Plan, have provided an
adequate mix of different types of compensation that reflect the outcome of our analysis of the
evaluation factors described above, after further review and evaluation of the adequacy and
effectiveness of our long-term incentive compensation arrangements we also believe that the
implementation of a long-term incentive plan could provide a platform for more definitive long-term
incentives for our executives while at the same time creating a more performance based award
program. For instance, while we believe that potential payments under our Incentive and Retention
Plan are reflective of longer-term operational metrics such as reserve growth, increased production
and increased cash flows from operations, the plan (a) does not contain provision for any
compensation payments for Company or individual performance, whether short-term or long-term, (b)
does not provide for any payments unless and until a triggering event occurs, and (c) does not
provide certainty of awards for any individual since awards will not be made until a triggering
event does occur. More information about the Incentive and Retention Plan and the implementation of
a long-term incentive plan is set forth below under the caption Incentive and Retention Plan and
Analysis and Outlook. Base salaries and cash bonuses are more closely linked to the short-term
objectives of providing reasonable and competitive levels of current annual increases. Since the
elements of compensation we use are fairly limited, the results of our evaluation of the Companys
performance and each executives individual performance are reflected more by the amounts of
compensation we award, rather than by type of award.
With our compensation philosophy and objectives in mind, we discuss below in more detail the
key elements of executive compensation and the factors underlying our decisions for 2007.
Base Salaries
Salary levels are based on factors including individual and company performance, level and
scope of responsibility and competitive salary levels within the industry. We do not give specific
weights to these factors. The Committee determines base salary levels by reviewing comparative
salary data gathered by our CEO and CFO and
(66)
by the Committees consultant, and by reviewing publicly available information such as proxy
statements filed by other exploration and production companies with similar market capitalizations.
As the beginning point for determining base salaries, we reviewed an initial list of 57
publicly-traded companies in our industry. This initial list was then narrowed to 18 companies
following our review and after making certain changes to the proposed peer group that had been
suggested by management. This peer group was selected based primarily on the similarity of total
revenues and business models of Parallel and the companies in the peer group. Using this peer
group, we targeted the median percentile range of salaries and cash bonuses for executive officers of the eighteen
company peer group. The peer group consisted of the following:
Abraxas Petroleum Corporation
Arena Resources, Inc.
Bill Barrett Corporation
Carrizo Oil & Gas, Inc.
Concho Resources, Inc.
Delta Petroleum Corporation
Edge Petroleum Corporation
GMX Resources, Inc.
Goodrich Petroleum Corporation
Gulfport Energy Corporation
Legacy Reserves, LP
Petroleum Development Corporation
PetroQuest Energy, Inc.
Rex Energy Corporation
Rosetta Resources, Inc.
The Exploration Company of Delaware, Inc.
Venoco, Inc.
Warren Resources, Inc.
Base salaries for each executive are reviewed individually on an annual basis. Salary
adjustments are based on the individuals experience, background
and responsibilities, the individuals performance
during the prior year, the general movement of salaries in the
marketplace, and our financial position. As a result of these factors, an
executives base salary may be above or below the base salaries of executives in other oil and gas
exploration and production companies at any point in time. Upon completion of the Committees
review and evaluation, and based on the financial and operations results and the criteria for the
salary determinations, our named executive officers received the following increases in their
annual base salaries:
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Mr. Oldham |
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from |
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$ |
330,000 |
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to |
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$ |
350,000 |
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Mr. Tiffin |
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from |
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$ |
275,000 |
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to |
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$ |
300,000 |
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Mr. Rutherford |
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from |
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$ |
175,000 |
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to |
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$ |
190,000 |
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Mr. Foster |
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from |
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$ |
190,000 |
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to |
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$ |
210,000 |
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Mr. Bayley |
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from |
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$ |
175,000 |
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to |
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$ |
190,000 |
|
Cash Bonuses
Historically, we have used, and continue to use, short-term incentives in the form of annual
cash bonuses to compensate executive officers. Annual cash bonuses are viewed by the Committee as
supplemental short-term incentives in recognition of Parallels overall performance and the efforts
made by our executives during a particular year. Cash bonuses are based on a subjective
determination of amounts we deem sufficient to reward our executives and remain competitive within
our geographic environment. As with base salaries, we also targeted the median percentile rankings
of our eighteen-company peer group. We did not use specific performance targets when determining cash bonuses. The Committee considers Parallels overall performance, the individual
performance of each executive, and the level of responsibility and experience of each executive to
determine the final bonus amounts. Bonuses are paid at the discretion of the Committee based on the
overall accomplishments of Parallel and individual performance.
(67)
After completing our review in December 2007, the Committee awarded cash bonuses as follows:
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Amount of |
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Bonus |
Mr. Oldham |
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$ |
200,000 |
|
Mr. Tiffin |
|
$ |
175,000 |
|
Mr. Rutherford |
|
$ |
70,000 |
|
Mr. Foster |
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$ |
70,000 |
|
Mr. Bayley |
|
$ |
70,000 |
|
There
were no material differences in the decision making process we used in determining
the salaries and cash bonuses of our respective officers.
Stock Options
Prior to 2003, we relied heavily on the use of stock options as a form of compensation because
of our size and limited cash resources. The Committee did not make any option grants to any
officers during the period from 2003 to 2007, and the last time we granted stock options to our
Chief Executive Officer, Mr. Oldham, was on June 20, 2001 when he was granted a stock option to
purchase 200,000 shares of common stock at an exercise price of $4.97 per share, the fair market
value of the common stock on the date of grant. In May 2003, Mr. Oldham voluntarily relinquished
100,000 shares of common stock underlying this option in order to restore and make available shares
of stock for option grants to non-officer employees. The last time we granted stock options to any
of our other executives was on November 14, 2002 when we granted stock options to Mr. Tiffin, our
Chief Operating Officer, and to Mr. Foster, our Chief Financial Officer. Mr. Tiffin was granted a
stock option to purchase 50,000 shares of common stock and Mr. Foster was granted a stock option to
purchase 35,000 shares of stock. The exercise price of both stock options was $2.18 per share, the
fair market value of the common stock on the date of grant.
We do not have a specific program or plan with regard to the timing or dating of option
grants. Our stock options have not been granted at regular intervals or on pre-determined dates.
The Committees practice as to when options are granted has historically been made at the
discretion of the Committee. Generally, no distinctions have been made in the timing of option
grants to executives as compared to employees. Since October 1993, stock options have been granted
to our officers and employees on thirteen different occasions. On eight occasions, options were
awarded to employees only; on four occasions options were awarded to officers and employees; and on
one occasion an option was awarded to one officer.
We do not grant discounted options and exercise prices are not based on a formula. All of our
options are granted at-the-money. In other words, the exercise price of the option equals the
fair market value of the underlying stock on the actual date of grant. As part of our 2006
compensation review, we conducted an internal review of all of our stock option grants going back
to August 1996 and did not find any instances of option backdating, nor did we backdate any
options in 2007. In addition, we have not repriced any of our stock options and do not intend to
do so.
Historically, the granting of options has not been purposefully timed around the public
announcement of material non-public information. Our Committees practice has been to meet whenever
one or more of the Committee members expresses a desire to discuss in executive session any
particular aspect of executive compensation, and the proximity of any stock option grant to
earnings or other material announcements is coincidental. We have not and do not plan to
purposefully time the release of material non-public information for the purpose of affecting the
value of executive compensation.
Other Compensation
Our executive officers participate in a 401(k) retirement and savings plan on the same basis
as other employees. Parallel matches certain employee contributions to its 401(k) retirement plan
with cash contributions. Company matching amounts for the named executive officers are included under the caption All
Other Compensation in the Summary Compensation Table on page 73.
(68)
We do not have a written policy or formula regarding the adjustment, reduction or recovery of
awards of payments if company performance is not optimal. However, the Committee does take into
account compensation realized or potentially realizable from prior compensation awards in setting
new types and amounts of compensation. Although we have never decreased the compensation of any of
our executive officers, the percentage increases in annual salaries and cash bonuses vary from year
to year, with some increases being smaller than previous years.
Allocation of Amounts and Types of Compensation
Other than our 401(k) retirement plan and outstanding stock options that were granted to our
executive officers prior to 2003, and although we believe that our Incentive and Retention Plan
does have some long-term incentive characteristics, we do not presently have in place what we would
consider to be a traditional type of long-term incentive program. Since we have not had a
traditional form of long-term incentive program, the method of allocating different forms of
long-term compensation has not been a significant consideration for us. The Committee has not
adopted a specific policy for allocating between long-term and currently paid out compensation, nor
have we adopted a specific policy for allocating between cash and non-cash compensation. However,
since December 2002, the compensation we have paid to our executives has emphasized the use of cash
rather than non-cash compensation. We have chosen to do this in order to maintain and continue our
practice of having a simplified, but effective and competitive, compensation package. In
determining the amount and mix of compensation elements for each executive officer, the Committee
relies on judgment, not upon fixed guidelines or formulas, or short term changes in our stock
price. Specific allocation policies have not been applied by the Committee largely because company
performance in the oil and natural gas industry is often volatile and cyclical and Parallels
performance in any given year, whether favorable or unfavorable, may not necessarily be
representative of immediate past results or future performance. The Committee also recognizes that
company performance is often the result of factors beyond the control of Parallel or its
executives, especially oil and natural gas prices. For instance, even when we believe our
executives have demonstrated superior individual performance during any particular year, the
year-end value and quantities of our proved reserves, which are based on oil and gas prices at
December 31 of each year, may reflect a level of company performance, whether good or bad, that is
not necessarily reflective of actual company and individual performance. Consequently, the
Compensation Committee examines and recommends executive compensation levels based on the
evaluation factors described above compared over a period of time, rather than applying these
factors on an isolated or snapshot basis at the time compensation levels are established by the
Committee. In this regard, and partly due to the peculiarities of financial accounting requirements
for exploration and production companies, the Committee emphasizes a subjective approach to
allocating the amounts and types of compensation for our executives.
By choosing to pay the elements of compensation discussed above, we try to maintain a simple
and competitive position for our total compensation package.
Internal and External Assistance
Our Committee has the authority to retain, at Parallels expense, compensation consultants.
Utilizing this authority, our Committee engaged the services of an independent compensation
consultant, Mercer Human Resources Consultants, Inc., to assist us in our review of executive
compensation for 2007. The consultant reports directly to the Committee. We specifically instructed
our consultant to use its data base to prepare a peer group of companies based on similarity of
revenues and business models and to provide the Committee with information regarding this peer
group with respect to base salaries, bonuses, long-term incentives and other types of compensation,
as well overall current compensation trends and practices. In the course of our evaluation of
executive compensation last year, we compared the data provided to us
by our consultant to components and levels of compensation paid to
our executives. We also compared the companies suggested by our
consultant and by management for inclusion in the peer
group. This year, our use of data provided by management was much more limited. Although management
provided the Committee with a proposed peer group, we selected the peer group suggested by Mercer,
after taking into account changes suggested by management. Our final selection was based primarily
on the similarity of revenue and business models of Parallel and the peer companies. Our review
included comparisons of pay data for comparable executive positions and compensation components
used by the peer group. Our independent consultant also provided the Committee with statistical
information and advice on current competitive compensation practices and trends in the marketplace.
When
our Committee meets in formal session, we do so outside the presence of management,
including Mr. Oldham, our Chief Executive Officer. However, the Compensation Committee did seek
informal input and insight of Mr. Oldham and Mr. Tiffin concerning broad, general topics such as
the overall design and levels of our
(69)
existing compensation program, the morale of our executive
officers, and any specific factors that they believed to be appropriate for the Committees
consideration and which the Committee may not be aware of, such as
individual performance, and extraordinary day-to-day efforts
or accomplishments of any of our executives.
Change of Control Arrangements
Our stock option plans and our Incentive and Retention Plan contain change of control
provisions. We use these provisions in an effort to provide some assurance to the Board of
Directors that the Board will be able to rely upon our executives continuing in their positions
with Parallel, and that Parallel will be able to rely upon each executives services and advice as
to the best interests of Parallel and its stockholders without concern that the executive might be
distracted by the personal uncertainties and risks created by any proposed or threatened change of
control. More information about these change of control provisions can
be found under the caption Potential Payments Upon Change of
Control on page 77.
Stock Option Plans
As described in more detail under the caption Potential Payments Upon Change of Control on
page 77, the Compensation Committee may adjust the stock options currently outstanding and held by
our executives upon the occurrence of a change of control. With this authority, the Compensation
Committee may in its discretion elect to accelerate the vesting of any stock options that were not
fully vested at the time of a change of control. In addition, under some of our stock option plans,
acceleration of vesting schedules will automatically occur. In the Outstanding Equity Awards at
Fiscal Year-End table on page 76, you can see the stock options currently held by our executives
and the exercise prices for each of these options. Mr. Oldham, our Chief Executive Officer, is the
only executive officer that has a stock option that had not fully vested as of December 31, 2007.
As described in that table, Mr. Oldham holds a stock option to purchase a total of 37,500 shares of
common stock which remained unvested to the extent of 30,000 shares at December 31, 2007. If a
change of control had occurred on December 31, 2007, a total of 30,000 shares would have
automatically vested on that date. Under the terms of Mr. Oldhams stock option, he would have to
pay an aggregate of $186,375 to purchase all 37,500 shares. The value of the portion of the option
subject to accelerated vesting would have been $379,800 ($17.63 per share closing price on December
31, 2007, multiplied by 30,000 shares subject to accelerated vesting minus $149,100, the aggregate
exercise price for the unvested portion of the option).
Incentive and Retention Plan
In 2002 and before, long-term incentives were made up of stock options. In 2004, upon
recommendation of the Committee, we adopted the Incentive and Retention Plan described in more
detail on page 78. Generally, this plan authorizes the Committee to grant executive officers awards
in the form of base shares, with one base share being equated to one share of our common stock.
The value of base shares fluctuates directly with changes in the price of Parallels stock which we
believe more closely ties the interests of our executives directly to those of stockholders. The
base shares are paid out only upon a corporate transaction or a change of control. These
triggering events are further described below and on page 77. Payouts, when triggered, are to be
paid in cash. The Committee will determine the total number of base shares to grant each executive
officer by using individual performance, level of responsibility, experience and the extent to
which each executive officer may have contributed to the occurrence of a triggering event under the
plan, as well as the outcome of the event. All of our other employees and consultants are also
eligible to participate in this plan.
The Incentive and Retention Plan was designed to align the interests of executives with
stockholders and to provide each executive with a significant incentive to manage the Company from
the perspective of an owner with an equity stake in the business. When we were in the initial
stages of formulating this plan, we began with the concept of a more traditional long-term
incentive plan which would provide our executives with potential cash awards based on year-to-year
comparisons of the growth in our proved oil and gas reserves or related exploration and production
criteria, with these annual cash awards being predicated on various performance factors, such as a
predetermined percentage increase in our proved oil and natural gas reserves or other related
criteria. However, we realized that under this approach annual cash payments could result simply as
a result of increases in the prices of oil and natural gas which would not necessarily equate to
actual growth in our reserves or any specific achievements by our executives and under
circumstances that might not result in additional value to our stockholders. After further consideration, we decided to tie any potential rewards under this plan to the market price of our
stock. Although not linked to any specific performance measures, the Committee believed that
linking potential rewards to the market
(70)
price of our stock would reflect a bundling of company
performance measures that are of importance to investors in smaller exploration and production
companies like Parallel, and which would be reflected in the market price of our stock. In
addition, and instead of providing for automatic annual bonuses, we believed it important to
reward our executives under circumstances that were more likely to coincide with events that could
also result in our stockholders realizing value. Thus, one prong of the Incentive and Retention
Plan provides for payments only when there is a corporate transaction, such as a merger or sale
of Parallel. The second prong of the plan provides for payments upon the occurrence of a change on
control. We structured the Incentive and Retention Plan in this fashion primarily to satisfy our
objective of retaining management, and to more closely connect potential payments to our executives
to an event in which all of our stockholders would be more likely to realize value from their
investments in Parallel. Further, the Committee remains of the belief that the Incentive and
Retention Plan should eliminate, or at least reduce, any reluctance management might have to pursue
potential corporate transactions that may be in the best interests of stockholders. The cash
benefits are payable in one lump-sum.
The oil and natural gas industry in our specific areas of operation continues to experience
increases in leasing, acquisitions, drilling and development activities. This activity has resulted
in significant management turnover within the areas we operate, largely because of greater
compensation packages and incentives being offered by our competitors. At the time we implemented
the plan, the Committee believed that the potential rewards to our executives under the Incentive
and Retention Plan would provide the necessary incentive for our executives to remain employed by,
and diligently pursue the goals of, Parallel. Since adopting the plan, none of our officers have
left our employment. However, recognizing that the plan has not resulted in any compensation to our
executives over the last four years, the Committee is presently re-evaluating this area of our
compensation program.
Under the Incentive and Retention Plan, our officers, employees and consultants are eligible
to receive a one-time performance payment upon the occurrence of a corporate transaction or a
one-time retention payment upon the occurrence of a change of control. Generally, a corporate
transaction means an acquisition of Parallel, a sale of substantially all of Parallels assets or
the dissolution of Parallel. A change of control generally means the acquisition of 60% or more of
our outstanding common stock or an event that results in our current Directors ceasing to
constitute a majority of the Board of Directors.
In the case of a corporate transaction, the total aggregate potential payments would be equal
to the sum of (a) the per share price received by all stockholders minus a base price of $3.73 per
share, multiplied by 1,080,362 base shares, plus (b) the per share price received by all
stockholders minus an additional base price of $8.62 per share, multiplied by 400,000 additional
base shares. If a change of control occurs, the aggregate potential payments to all plan
participants would be equal to the sum of (a) the per share closing price of Parallels common
stock on the day immediately preceding the change of control, minus the base price of $3.73 per
share, multiplied by 1,080,362, plus (b) the per share closing price of Parallels common stock on
the day immediately preceding the change of control, minus an additional base price of $8.62 per
share, multiplied by 400,000 additional base shares.
If a corporate transaction or change of control occurs, the Compensation Committee has the
discretion to allocate for payment to each of our executives, employees or consultants a portion of
the total performance bonus or retention payment as the Committee determines in its sole
discretion. Although the Committee has not made any awards under our Incentive and Retention Plan,
for illustration purposes, assuming a corporate transaction or change of control occurred on
December 31, 2007, and that the applicable price of our common stock was $17.63 per share, the
closing price of our common stock as of December 31, 2007, the total aggregate potential payments
to all eligible participants would have been approximately $18.6 million.
The change of control provisions in our stock option plans and in the Incentive and Retention
Plan utilize single triggers. As compared to double triggers, we believe that single triggers
provide a more definitive outcome for our executives if a triggering event does occur and are more
likely to prevent an executive from becoming entangled in various interpretive issues concerning
the applicability of a second or double trigger to any particular triggering event. For these
reasons, coupled with the fact that none of our executives have deferred compensation arrangements
or employment or other post-termination compensation agreements with Parallel, we believe the use of single triggers is
not inconsistent with the best interests of Parallel or our stockholders.
(71)
Stock Ownership/Retention Guidelines
We do not have formal written guidelines or policy statements requiring specified levels of
stock ownership or holding practices. Under our policy covering insider trading procedures, our
executives, their spouses and other immediate family members sharing the executives household are
prohibited from selling any securities of Parallel that are not owned at the time of the sale, a
short sale. Also, no such person may buy or sell puts, calls or exchange-traded options in
Parallels securities. These transactions are speculative in nature and may involve a bet against
the company which we believe is inappropriate for our insiders.
Perquisites and Personal Benefits
We have provided limited perquisites and personal benefits to our executives, including club
memberships and allowing our executives a choice of receiving a car allowance or personal use of a
company provided vehicle. We encourage our executives to belong to a social club so that they have
an appropriate entertainment forum for customers and appropriate interaction with their
communities.
Our executives also participate in Parallels other benefit plans on the same terms as other
employees. These plans include medical and dental insurance, and life insurance. All employees,
including our executives, age fifty or over are also eligible to participate in an extended health
care coverage plan that we maintain. We do not have charitable gift matching or discounts on
products.
The types and amounts of perquisites we provide to our executives are included in the All
Other Compensation column of the Summary Compensation Table on page 73.
Analysis and Outlook
During our review of 2007 compensation, we determined that the compensation paid to our
executives was below that of the peer group selected by the Committee. The actions of the
Compensation Committee in increasing our executives salaries and awarding cash bonuses were based
mostly on the Committees decision to bring our executives salaries and bonuses up to the median
percentile range of the salaries and bonuses of executives of our peer companies. In addition to
performance at the Company level, the Committee also compared the individual efforts, talents and
performance of Parallels executives with the individuals performing similar functions for the peer
companies, some of whom are known by one or more members of the Committee. The Committees
decisions were also influenced by the individual efforts of each of our executives in response to
specific requests made by our Board of Directors. Going forward, the Committee intends to use, more
so than it has in the past, objective performance criteria to support certain components of
executive compensation rather than the more subjective approach that we have historically used.
Based on discussions the Committee has had with our consultant, management and our own
deliberations, the Committee further determined that the Incentive and Retention Plan may not be
providing the types of incentives anticipated when the plan was originally implemented. In
particular, the Committee believes the Incentive and Retention Plan may not continue to provide the
necessary incentives to attract and retain qualified oil and gas industry personnel at a time of
increased competition for such personnel at all levels and that the absence of an equity based
long-term incentive plan could make it more difficult to recruit and retain qualified personnel.
Towards this end, and subject to applicable regulatory and stockholder approval requirements, the
Committee intends to adopt a long-term incentive plan that would authorize awards of stock options,
restricted stock, performance awards or other equity based awards, although no such plan had been
adopted by the Compensation Committee at the time our Annual Report on Form 10-K, which includes
this Compensation Discussion and Analysis, was filed with the SEC.
Limit on Deductibility of Certain Compensation
Provisions of the Internal Revenue Code that restrict the deductibility of certain
compensation over one million dollars per year were not a factor in our considerations or
recommendations for our 2007 compensation review. Section 162(m) of the Code currently imposes a $1
million limitation on the deductibility of certain compensation paid to our executives. Excluded
from the limitation is compensation that is performance based. For compensation to be performance
based, it must meet certain criteria, including being based on predetermined objective standards
approved by stockholders. Compensation to our executives does not currently qualify as performance
based compensation and thus is not deductible by us for federal income tax purposes.
(72)
Compensation Committee Report
The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis
with management.
Based on its review and discussions, the Committee recommended to the Board of Directors that
the Compensation Discussion and Analysis be included in our Annual Report on Form 10-K for the year
ended December 31, 2007 and in our Proxy Statement for this
years Annual Meeting of Stockholders.
Members of the Compensation Committee
Edward A. Nash (Chairman)
Martin B. Oring
Ray M. Poage
Jeffrey G. Shrader
Summary of Annual Compensation
The table below shows a summary of the types and amounts of compensation paid for 2006 and
2007 to Larry C. Oldham, our President and Chief Executive Officer, and to our other four executive
officers for the years ended December 31, 2007 and 2006. Also included is the compensation we paid
to Thomas R. Cambridge, our former Chairman of the Board of Directors, for the same years. Mr.
Cambridge retired from the Board of Directors on June 26, 2007.
Summary Compensation Table
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Change in |
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Pension Value |
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and |
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Non-Equity |
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Nonqualified |
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All |
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Incentive |
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Deferred |
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Other |
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Name and |
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Stock |
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Option |
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Plan Com- |
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Compensation |
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Com- |
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|
Principal Position |
|
Year |
|
Salary |
|
Bonus |
|
Awards |
|
Awards |
|
pensation |
|
Earnings |
|
pensation(1) |
|
Total |
|
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|
|
|
|
|
|
|
|
|
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|
|
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L. C. Oldham |
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|
2007 |
|
|
$ |
330,000 |
|
|
$ |
200,000 |
|
|
|
0 |
|
|
|
12,303 |
(2) |
|
|
0 |
|
|
|
0 |
|
|
$ |
59,415 |
(3) |
|
$ |
601,718 |
|
President, Chief Executive
Officer and Director |
|
|
2006 |
|
|
$ |
300,000 |
|
|
$ |
185,000 |
|
|
|
0 |
|
|
|
16,683 |
(2) |
|
|
0 |
|
|
|
0 |
|
|
$ |
51,090 |
(3) |
|
$ |
552,773 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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|
|
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|
|
|
|
|
|
|
|
D. E. Tiffin |
|
|
2007 |
|
|
$ |
275,000 |
|
|
$ |
175,000 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
$ |
47,730 |
(4) |
|
$ |
497,730 |
|
Chief Operating Officer |
|
|
2006 |
|
|
$ |
250,000 |
|
|
$ |
147,500 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
$ |
43,247 |
(4) |
|
$ |
440,747 |
|
|
|
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|
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E. A. Bayley |
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|
2007 |
|
|
$ |
175,000 |
|
|
$ |
70,000 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
$ |
41,640 |
(5) |
|
$ |
286,640 |
|
Vice President
of Corporate Engineering |
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|
2006 |
|
|
$ |
160,000 |
|
|
$ |
60,000 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
$ |
39,321 |
(5) |
|
$ |
259,321 |
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J. S. Rutherford |
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|
2007 |
|
|
$ |
175,000 |
|
|
$ |
70,000 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
$ |
39,560 |
(6) |
|
$ |
284,560 |
|
Vice President
of Land and Administration |
|
|
2006 |
|
|
$ |
160,000 |
|
|
$ |
60,000 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
$ |
38,174 |
(6) |
|
$ |
258,174 |
|
|
|
|
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S. D. Foster |
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|
2007 |
|
|
$ |
190,000 |
|
|
$ |
70,000 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
$ |
44,493 |
(7) |
|
$ |
304,493 |
|
Chief Financial Officer |
|
|
2006 |
|
|
$ |
175,000 |
|
|
$ |
60,000 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
$ |
45,547 |
(7) |
|
$ |
280,547 |
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|
|
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T. R.
Cambridge(8) |
|
|
2007 |
|
|
$ |
70,889 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
$ |
70,889 |
|
Former
Chairman of the Board of Directors |
|
|
2006 |
|
|
$ |
135,000 |
|
|
$ |
60,000 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
$ |
5,152 |
|
|
$ |
200,152 |
|
|
|
|
(1) |
|
Included in this column is (a) all other compensation received by the named executive officer
but not reported under any other column of this table, and (b) the incremental cost of all
perquisites and personal benefits for each named executive officer, in each case as identified
in the following table: |
(73)
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|
Mr. |
|
Mr. |
|
Mr. |
|
Mr. |
|
Mr. |
|
Mr. |
|
|
|
|
|
|
Oldham |
|
Tiffin |
|
Rutherford |
|
Foster |
|
Bayley |
|
Cambridge |
Personal use of club
memberships(a) |
|
|
2007 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
1,547 |
|
|
$ |
1,670 |
|
|
$ |
2,085 |
|
|
$ |
0 |
|
|
|
|
2006 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
3,376 |
|
|
$ |
3,652 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
Personal use
of comp any car(b) |
|
|
2007 |
|
|
$ |
4,625 |
|
|
$ |
0 |
|
|
$ |
5,644 |
|
|
$ |
0 |
|
|
$ |
10,291 |
|
|
$ |
0 |
|
|
|
|
2006 |
|
|
$ |
1,723 |
|
|
$ |
0 |
|
|
$ |
1,179 |
|
|
$ |
0 |
|
|
$ |
8,401 |
|
|
$ |
0 |
|
|
Car allowance |
|
|
2007 |
|
|
$ |
0 |
|
|
$ |
8,050 |
|
|
$ |
0 |
|
|
$ |
8,050 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
|
|
2006 |
|
|
$ |
0 |
|
|
$ |
6,000 |
|
|
$ |
0 |
|
|
$ |
6,000 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
Personal use
of office
space(c) |
|
|
2007 |
|
|
$ |
1,809 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
|
|
2006 |
|
|
$ |
2,366 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
CEO life
insurance(d) |
|
|
2007 |
|
|
$ |
4,063 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
|
|
2006 |
|
|
$ |
3,793 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
Personal use of charter aircraft |
|
|
2007 |
|
|
|
(e) |
|
|
$ |
0 |
|
|
|
(e) |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
|
|
2006 |
|
|
|
(e) |
|
|
|
(e) |
|
|
|
(e) |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
Tax
gross
up(f) |
|
|
2007 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
|
|
2006 |
|
|
$ |
3,629 |
|
|
$ |
1,687 |
|
|
$ |
3,697 |
|
|
$ |
3,559 |
|
|
$ |
3,836 |
|
|
$ |
5,152 |
|
|
Other(g) |
|
|
2007 |
|
|
$ |
5,935 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
|
|
|
(a) |
The value of personal use of club memberships represents that portion of annual
club dues determined by multiplying the total annual club dues by a fraction equal
to expenses for personal use divided by total business and personal expenses. All
employees pay or reimburse us for their personal expenses. |
|
|
(b) |
Personal use of a company car is based on the sum of the fair lease value of the
car, maintenance expense and gas expense, multiplied by a fraction, the numerator of
which is the number of miles driven for personal use and the denominator of which is
the total number of miles driven. |
|
|
(c) |
Includes personal use of office space by Mr. Oldhams wife for charitable, civic
and personal activities. The value has been determined by multiplying the number of
square feet in the office by the cost per square foot paid by Parallel under its
lease agreement covering its executive offices, and as adjusted for a proportionate
share of common area maintenance expenses. |
|
|
(d) |
We provide a $100,000 whole life insurance policy for Mr. Oldham and pay the
premiums for maintaining the policy in force. |
|
|
(e) |
From time to time, the executives spouse will accompany the executive on
business trips when there is an unoccupied seat on the aircraft. However, there is
no aggregate incremental cost to us. |
|
|
(f) |
The tax gross up payments for each named executive officer were made in
connection with cash bonuses in the amount of $10,000 that were awarded to each
named executive officer on December 6, 2006. |
|
|
(g) |
Includes the cost of commercial airfare for Mr. Oldhams wife when she
accompanied him on seven separate business trips. |
|
|
|
|
(2) |
|
The amounts shown in this column represent the dollar amount we recognized for
financial statement reporting purposes, computed in accordance with FAS 123(R), of an
option award made to Mr. Oldham prior to 2006. For a discussion of valuation
assumptions, see Note 11 to our Consolidated Financial Statements included in this
Annual Report on Form 10-K. |
|
(3) |
|
For 2007, such amount includes Parallels contribution in the amount of $19,800 to
Mr. Oldhams individual retirement account maintained under Parallels 401(k) plan;
insurance premiums in the amount of $23,183 for nondiscriminatory group life, medical,
disability, long-term care and dental insurance; and $16,432 representing the total
value of all other compensation and perquisites and personal benefits provided to Mr.
Oldham as described in
|
(74)
footnote 1. For 2006, such amount includes Parallels 2006
contribution in the amount of $18,000 to Mr. Oldhams individual retirement account
maintained under Parallels 401(k) plan; insurance premiums in the amount of $21,579
for nondiscriminatory group life, medical, disability, long-term care and dental
insurance; and $11,511 representing the total value of all other compensation and
perquisites and personal benefits provided to Mr. Oldham as described in footnote 1.
(4) |
|
For 2007, such amount includes Parallels contribution in the amount of $16,500 to
Mr. Tiffins individual retirement account maintained under Parallels 401(k) plan;
insurance premiums in the amount of $23,180 for nondiscriminatory group life, medical,
disability, long-term care and dental insurance; and $8,050 representing the total
value of all other compensation and perquisites and personal benefits provided to Mr.
Tiffin as described in footnote 1. For 2006, such amount includes Parallels 2006
contribution in the amount of $15,000 to Mr. Tiffins individual retirement account
maintained under Parallels 401(k) plan; insurance premiums in the amount of $20,560
for nondiscriminatory group life, medical, disability, long-term care and dental
insurance; and $7,687 representing the total value of all other compensation and
perquisites and personal benefits provided to Mr. Tiffin as described in footnote 1. |
(5) |
|
For 2007, such amount includes Parallels contribution in the amount of $10,500 to
Mr. Bayleys individual retirement account maintained under Parallels 401(k) plan;
insurance premiums in the amount of $18,764 for nondiscriminatory group life, medical,
disability, long-term care and dental insurance; and $12,376 representing the total
value of all other compensation and perquisites and personal benefits provided to Mr.
Bayley as described in footnote 1. For 2006, such amount includes Parallels 2006
contribution in the amount of $9,600 to Mr. Bayleys individual retirement account
maintained under Parallels 401(k) plan; insurance premiums in the amount of $17,484
for nondiscriminatory group life, medical, disability, long-term care and dental
insurance; and $12,237 representing the total value of all other compensation and
perquisites and personal benefits provided to Mr. Bayley as described in footnote 1. |
(6) |
|
For 2007, such amount includes Parallels contribution in the amount of $10,500 to
Mr. Rutherfords individual retirement account maintained under the 401(k) plan;
insurance premiums in the amount of $21,869 for nondiscriminatory group life, medical,
disability and dental insurance; and $7,191 representing the total value of all other
compensation and perquisites and personal benefits provided to Mr. Rutherford as
described in footnote 1. For 2006, such amount includes Parallels 2006 contribution
in the amount of $9,600 to Mr. Rutherfords individual retirement account maintained
under the 401(k) plan; insurance premiums in the amount of $20,322 for
nondiscriminatory group life, medical, disability and dental insurance; and $8,252
representing the total value of all other compensation and perquisites and personal
benefits provided to Mr. Rutherford as described in footnote 1. |
(7) |
|
For 2007, such amount includes Parallels contribution in the amount of $11,400 to
Mr. Fosters individual retirement account maintained under Parallels 401(k) plan;
insurance premiums in the amount of $23,373 for nondiscriminatory group life, medical,
disability, long-term care and dental insurance; and $9,720 representing the total
value of all other compensation and perquisites and personal benefits provided to Mr.
Foster as described in footnote 1. For 2006, such amount includes Parallels 2006
contribution in the amount of $10,500 to Mr. Fosters individual retirement account
maintained under Parallels 401(k) plan; insurance premiums in the amount of $21,836
for nondiscriminatory group life, medical, disability, long-term care and dental
insurance; and $13,211 representing the total value of all other compensation and
perquisites and personal benefits provided to Mr. Foster as described in footnote 1. |
(8) |
|
The 2007 information shown in this table for Mr. Cambridge is for the period from
January 1, 2007 to June 26, 2007, the date of his retirement. Except as described
under Item 13. Certain Relationships and Related Transactions, and Director
Independence on page 90, no other payments were made to Mr. Cambridge or his
affiliated entities for the fiscal year ended December 31, 2007. |
Outstanding Equity Awards at Fiscal Year-End
Historically, we have used stock options as part of the overall compensation of Directors,
officers and employees. However, we did not grant any stock options in 2007 to any of the executive
officers named in the Summary Compensation Table. Summary descriptions of our stock option plans are included in this
Annual Report on Form 10-K, beginning on page 84 so you can review the types of options we have
granted in the past and the significant features of our stock options.
(75)
In the table below, we show certain information about the outstanding equity awards held by
the named executive officers at December 31, 2007.
Outstanding Equity Awards at 2007 Fiscal Year-End
|
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|
Option Awards |
|
Stock Awards |
|
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Equity |
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Equity |
|
Incentive |
|
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Incentive |
|
Plan |
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Plan |
|
Awards: |
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|
Equity |
|
|
|
|
|
|
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Awards: |
|
Market or |
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|
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Incentive |
|
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Number |
|
Payout |
|
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Plan |
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|
|
|
|
|
|
|
|
|
|
Market |
|
of |
|
Value of |
|
|
Number |
|
Number |
|
Awards: |
|
|
|
|
|
|
|
|
|
Number |
|
Value |
|
Unearned |
|
Unearned |
|
|
of |
|
of |
|
Number |
|
|
|
|
|
|
|
|
|
of Shares |
|
of Shares |
|
Shares, |
|
Shares, |
|
|
Securities |
|
Securities |
|
of |
|
|
|
|
|
|
|
|
|
or |
|
or Units |
|
Units or |
|
Units or |
|
|
Underlying |
|
Underlying |
|
Securities |
|
|
|
|
|
|
|
|
|
Units of |
|
of |
|
Other |
|
Other |
|
|
Unexercised |
|
Unexercised |
|
Underlying |
|
|
|
|
|
|
|
|
|
Stock |
|
Stock |
|
Rights |
|
Rights |
|
|
Options |
|
Options |
|
Unexercised |
|
Option |
|
Option |
|
That Have |
|
That Have |
|
That Have |
|
That Have |
|
|
(#) |
|
(#) |
|
Unearned |
|
Exercise |
|
Expiration |
|
Not |
|
Not |
|
Not |
|
Not |
Name |
|
Exercisable |
|
Unexercisable |
|
Options |
|
Price |
|
Date |
|
Vested |
|
Vested |
|
Vested |
|
Vested |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
L. C. Oldham |
|
|
7,500 |
(1) |
|
|
30,000 |
(1) |
|
|
0 |
|
|
$ |
4.97 |
|
|
|
06-20-11 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
E. A. Bayley |
|
|
25,000 |
|
|
|
0 |
|
|
|
0 |
|
|
$ |
3.60 |
|
|
|
08-04-08 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
50,000 |
|
|
|
0 |
|
|
|
0 |
|
|
$ |
4.97 |
|
|
|
06-20-11 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
J. S. Rutherford |
|
|
44,000 |
|
|
|
0 |
|
|
|
0 |
|
|
$ |
4.97 |
|
|
|
06-20-11 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
D. E. Tiffin |
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
S. D. Foster |
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
T. R. Cambridge |
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
(1) |
|
This stock option is exercisable with respect to 7,500 shares on the first day of January
in each of the years 2007, 2008, 2009, 2010 and 2011. |
(76)
Option Exercises and Stock Vested in 2007
In the table below, we show certain information about (i) the number of shares of common stock
acquired upon exercise of stock options by each of the named executive officers in 2007 and the
value realized on exercise of the stock options and (ii) stock awards.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Option Awards |
|
Stock Awards |
|
|
Number of |
|
|
|
|
|
Number of |
|
|
|
|
Shares |
|
Value |
|
Shares |
|
Value |
|
|
Acquired |
|
Realized |
|
Acquired |
|
Realized |
|
|
on |
|
on |
|
on |
|
on |
Name |
|
Exercise |
|
Exercise(1) |
|
Vesting |
|
Vesting |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Larry C. Oldham |
|
|
46,000 |
|
|
$ |
661,020 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Donald E. Tiffin |
|
|
0 |
|
|
$ |
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Eric A. Bayley |
|
|
25,000 |
|
|
$ |
464,000 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
John S. Rutherford |
|
|
2,000 |
|
|
$ |
31,980 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
2,000 |
|
|
$ |
31,980 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
2,000 |
|
|
$ |
29,780 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Steven D. Foster |
|
|
0 |
|
|
$ |
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Thomas R. Cambridge |
|
|
100,000 |
|
|
$ |
1,890,000 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
1,707 |
(2) |
|
$ |
26,015 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
25,000 |
(2) |
|
$ |
384,500 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
26,707 |
(2) |
|
$ |
361,079 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
23,293 |
(2) |
|
$ |
356,383 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
23,293 |
(2) |
|
$ |
312,592 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
1,707 |
(2) |
|
$ |
20,569 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
50,000 |
(2) |
|
$ |
636,000 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
25,000 |
(2) |
|
$ |
325,000 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
23,293 |
(2) |
|
$ |
283,010 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
(1) |
|
The value realized on exercise is equal to the closing price of our common stock on the date
of exercise, less the exercise price of the stock option exercised, multiplied by the number
of shares acquired on exercise. |
|
(2) |
|
These shares were acquired by Mr. Cambridge during the period from August 23, 2007 to
September 11, 2007 upon exercise of stock options following his retirement on June 26, 2007.
All of the stock options exercised by Mr. Cambridge after his retirement would have expired by
their own terms on September 26, 2007 had they not been exercised. |
Potential Payments Upon Change of Control
Stock Option Plans
Our outstanding stock options and stock option plans contain certain change of control
provisions which are applicable to our outstanding stock options, including the options held by our
officers and Directors. For purposes of our options, a change of control occurs if:
|
|
|
we are not the surviving entity in a merger or consolidation (or survive only as a
subsidiary of another entity); |
|
|
|
|
we sell, lease or exchange all or substantially all of our assets; |
|
|
|
|
we dissolve and liquidate; |
(77)
|
|
|
any person or group acquires beneficial ownership of more than 50% of our common
stock; or |
|
|
|
|
in connection with a contested election of Directors, the persons who were Directors
of Parallel before the election cease to constitute a majority of the Board of
Directors. |
Under our 1992 Stock Option Plan and 2001 Employee Stock Option Plan, if a change of control
occurs, the Compensation Committee of the Board of Directors can:
|
|
|
accelerate the time at which options may be exercised; |
|
|
|
|
require optionees to surrender some or all of their options and pay to each optionee
the change of control value; |
|
|
|
|
make adjustments to the options to reflect the change of control; or |
|
|
|
|
permit the holder of the option to purchase, instead of the shares of common stock
as to which the option is then exercisable, the number and class of shares of stock or
other securities or property which the optionee would acquire under the terms of the
merger, consolidation or sale of assets and dissolution if, immediately before the
merger, consolidation or sale of assets or dissolution, the optionee had been the
holder of record of the shares of common stock as to which the option is then
exercisable. |
The change of control value is an amount equal to, whichever is applicable:
|
|
|
the per share price offered to our stockholders in a merger, consolidation, sale of
assets or dissolution transaction; |
|
|
|
the price per share offered to our stockholders in a tender offer or exchange offer
where a change of control takes place; or |
|
|
|
if a change of control occurs other than from a tender or exchange offer, the fair
market value per share of the shares into which the options being surrendered are
exercisable, as determined by the Committee. |
In the case of our 1997 Nonemployee Directors Stock Option Plan, 1998 Stock Option Plan and
2001 Nonemployee Director Stock Option Plan, upon the occurrence of a change of control, any
outstanding options under these plans become fully exercisable and upon exercise of the option, the
option holder will be entitled to purchase, instead of the numbers of shares of stock for which the
option is then exercisable, the number and class of shares of stock or other securities or property
to which the option holder would have been entitled under the terms of the change of control if,
immediately before the change of control, the option holder had been the holder of record of the
number of shares of stock for which the option is then exercisable.
Incentive and Retention Plan
On September 22, 2004, the Compensation Committee of the Board of Directors approved and
adopted an incentive and retention plan for our officers and employees. On September 24, 2004, the
Board of Directors adopted the plan upon recommendation by the Compensation Committee.
The purpose of the plan is to advance the interests of Parallel and its stockholders by
providing officers and employees with incentive bonus compensation which is linked to a corporate
transaction. As defined in the plan, a corporate transaction means:
|
|
|
an acquisition of us by way of purchase, merger, consolidation, reorganization or
other business combination, whether by way of tender offer or negotiated transaction,
as a result of which our outstanding securities are exchanged or converted into cash,
property and/or securities not issued by us; |
|
|
|
a sale, lease, exchange or other disposition by us of all or substantially all of
our assets; |
|
|
|
our stockholders approve a plan or proposal for our liquidation or dissolution; or |
|
|
|
any combination of any of the foregoing. |
(78)
The plan recognizes the possibility of a proposed or threatened transaction and the need to be
able to rely upon officers and employees continuing their employment, and that Parallel be able to
receive and rely upon their advice as to the best interests of Parallel and its stockholders
without concern that they might be distracted by the personal uncertainties and risks created by
any such transaction. In this regard, the plan provides for a retention payment upon the occurrence
of a change of control, as defined below.
All members of Parallels executive group are participants in the plan. For purposes of the
plan, the executive group includes Messrs. Oldham, Tiffin, Foster, Rutherford and Bayley and any
other officer employee of Parallel selected by the Compensation Committee in its sole discretion.
In addition, the Committee may designate other non-officer employees of Parallel and consultants to
Parallel as participants in the plan who will also be eligible to receive a performance bonus upon
the occurrence of a corporate transaction or a retention payment upon the occurrence of a change of
control.
Generally, the plan provides for:
|
|
|
the payment of a one-time performance bonus to eligible officers and employees upon
the occurrence of a corporate transaction; or |
|
|
|
a one time retention payment upon a change of control of Parallel. A change of
control is generally defined as the acquisition of beneficial ownership of 60% or more
of the voting power of Parallels outstanding voting securities by any person or group
of persons, or a change in the composition of the Board of Directors of Parallel such
that the individuals who, at the effective date of the plan, constitute the Board of
Directors cease for any reason to constitute at least a majority of the Board of
Directors. |
On August 23, 2005, the Compensation Committee of the Board of Directors of Parallel approved
and adopted amendments to the incentive and retention plan, and on that same date, the Board of
Directors approved the amendments upon recommendation by the Compensation Committee. Generally, the
plan was amended to provide for 400,000 additional base shares with an associated additional
base price of $8.62 per share. The plan was further amended on February 27, 2007 to expand the
class of eligible participants to include consultants to Parallel.
The amount of these payments depends on future prices of Parallels common stock, which is
undeterminable until a triggering event occurs. In the case of a corporate transaction, the total
cash obligation for performance bonuses is equal to the sum of (a) per share price received by all
stockholders minus a base price of $3.73 per share, multiplied by 1,080,362 shares, plus (b) the
per share price received by all stockholders minus an additional base price of $8.62 per share,
multiplied by 400,000 additional base shares. As an example, if the stockholders of Parallel
received the December 31, 2007 per share closing price of $17.63 in a merger, tender offer or other
corporate transaction, the total aggregate potential payments to all plan participants would be
[($17.63 $3.73) x 1,080,362], plus [$17.63 $8.62) x 400,000], or $18.6 million. If a change of
control occurs, the total amount of cash retention payments to all plan participants would be equal
to the sum of (a) per share closing price of Parallels common stock on the day immediately
preceding the change of control minus the base price of $3.73 per share, multiplied by 1,080,362,
plus (b) the per share closing price of Parallels common stock on the day immediately preceding
the change of control minus an additional base price of $8.62 per share, multiplied by 400,000.
If a corporate transaction or change of control occurs, the Compensation Committee will
allocate for payment to each member of the executive group such portion of the total performance
bonus or retention payment as the Compensation Committee determines in its sole discretion. After
making these allocations, if any part of the total performance bonus or retention payment amount
remains unallocated, the Compensation Committee may allocate any remaining portion of the
performance bonus or retention payment among all other participants in the plan. After all
allocations of the performance bonus have been made, each participants proportionate share of the
performance bonus or retention payment will be paid in a cash lump sum.
There is no certainty with respect to whether or when payments under this plan might be
triggered, or the amount of any potential payment to any member of the executive group or other
participants if a triggering event did occur.
Our ultimate liability under the plan is not readily determinable because of the inability to
predict the occurrence of a corporate transaction or change of control, or our stock price on the
future date of any such corporate transaction or change of control. No liability will be recorded
until such time as a corporate transaction or change of control becomes probable and the amount of
the liability becomes determinable. The occurrence of a change of con-
(79)
trol or a corporate transaction could have a negative impact on our financial condition and
results of operations, depending upon the price of our common stock at the time of a change of
control or corporate transaction.
The plan is entirely unfunded and the plan makes no provision for segregating any of our
assets for payment of any amounts under the plan.
A participants rights under the plan are not transferable.
The plan is administrated by the Compensation Committee of the Board of Directors of Parallel.
The Compensation Committee has the power, in its sole discretion, to take such actions as may be
necessary to carry out the provisions and purposes of the plan. The Compensation Committee has the
authority to control and manage the operation and administration of the plan and has the power to:
|
|
|
designate the officers and employees of, and consultants to, Parallel and its
subsidiaries who participate in the plan, in addition to the executive group; |
|
|
|
|
maintain records and data necessary for proper administration of the plan; |
|
|
|
|
adopt rules of procedure and regulations necessary for the proper and efficient
administration of the plan; |
|
|
|
|
enforce the terms of the plan and the rules and regulations it adopts; |
|
|
|
|
employ agents, attorneys, accountants or other persons; and |
|
|
|
|
perform any other acts necessary or appropriate for the proper management and
administration of the plan. |
The plan automatically terminates and expires on the date participants receive a performance
bonus or retention payment.
Non-Officer Severance Plan
In January 2006, a Non-Officer Employee Severance Plan was implemented for the purpose of
providing our non-officer employees with an incentive to remain employed by us. This plan provides
for a one-time severance payment to non-officer employees equal to one year of their then current
base salary upon the occurrence of a change of control within the meaning of the plan. Based on the
aggregate non-officer base salaries in effect as of December 31, 2007, if a change of control had
occurred at December 31, 2007, the total severance amount payable under this plan would have been
approximately $3.8 million.
Compensation of Directors
In addition to reviewing the compensation of our executive officers, the Compensation
Committee also periodically reviews the compensation program for our four non-employee Directors,
all of whom are members of the Compensation Committee. The last time Director compensation was
modified was in June 2004. At its meeting held on February 12, 2008, the Committee authorized and
approved the payment of an annual cash retainer fee in the amount of $50,000 for each non-employee
Director, which will be paid in lieu of all other cash fees. The per meeting fees that we have
been paying to our non-employee Directors for attendance at Board and Board committee meetings, and
the fees paid for serving as Chairman of Board committees, were terminated effective January 1,
2008. The Committee is also currently reviewing and evaluating the equity component of Director
compensation.
Mr. Oldham, our only Director who is also an officer of Parallel, does not receive any
compensation for his services as a member of the Board or the Boards Hedging and Acquisitions
Committee.
(80)
In the table below, we show certain information about the compensation paid to our
non-employee Directors during 2007.
2007 Director Compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in |
|
|
|
|
|
|
Fees |
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension |
|
|
|
|
|
|
Earned |
|
|
|
|
|
|
|
|
|
|
|
|
|
Value and |
|
|
|
|
|
|
or |
|
|
|
|
|
|
|
|
|
Non-Equity |
|
Nonqualified |
|
|
|
|
|
|
Paid in |
|
Stock |
|
Option |
|
Incentive Plan |
|
Deferred |
|
All Other |
|
|
Name |
|
Cash |
|
Awards(1) |
|
Awards(2) |
|
Compensation |
|
Compensation |
|
Compensation |
|
Total |
D. E. Chitwood(3) |
|
$ |
1,500 |
|
|
$ |
0 |
|
|
$ |
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
$ |
1,500 |
|
E. A. Nash |
|
$ |
11,375 |
|
|
$ |
23,964 |
|
|
$ |
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
$ |
35,339 |
|
M .B. Oring |
|
$ |
33,000 |
|
|
$ |
23,964 |
|
|
$ |
77,872 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
$ |
134,836 |
|
R.M . Poage |
|
$ |
32,250 |
|
|
$ |
23,964 |
|
|
$ |
203,238 |
(4) |
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
$ |
259,452 |
|
J.G. Shrader |
|
$ |
41,750 |
(5) |
|
$ |
23,964 |
|
|
$ |
77,872 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
$ |
143,586 |
|
|
|
|
(1) |
|
On the first day of July of each year, beginning July 1, 2004, our non-employee directors are
automatically granted shares of common stock having a value of $25,000. The actual number of
shares granted is determined by dividing $25,000 by the average daily closing price of the
common stock for ten consecutive trading days commencing fifteen trading days before the first
day of July of each year. Under this plan, a total of 1,100 shares of common stock have been
granted to Mr. Nash and each of Messrs. Oring, Poage and Shrader have been granted a total of
10,395 shares of common stock since inception of the plan, which includes 1,100 shares granted
to each of them on the July 1, 2007 grant date. For the July 1, 2007 grant, the 1,100 shares
were calculated by dividing $25,000 by $22.723, the ten trading day average closing price of
the stock, beginning on June 18, 2007. Since July 1, 2007 was not a business day, the amount
set forth in this column is based on the closing price of our common stock on July 2, 2007,
the first business day following the grant date. The amounts shown in this column represent
the dollar amount we recognized for financial statement reporting purposes with respect to the
fiscal year ended December 31, 2007, computed in accordance with FAS 123R and also represents
the aggregate grant date fair value computed in accordance with FAS 123R. Due to an
inadvertent error in calculating the number of shares granted to each of our non-employee
directors in 2007, each non-employee director received 39 more shares than the total of 1,061
shares that each non-employee director should have received. Our non-employee directors have
agreed to offset against future cash fees the economic equivalent (approximately $919) of the
additional 39 shares. |
|
(2) |
|
The amounts shown in this column represent the dollar amount we recognized for financial
statement reporting purposes with respect to the fiscal year ended December 31, 2007, computed
in accordance with FAS 123(R) of option awards made to the non-employee Directors prior to
2007 and the option award made to Mr. Poage in 2007 as further described in footnote (4)
below. The amounts shown exclude the impact of estimated forfeitures. For a discussion of
valuation assumptions, see Note 11 to our Consolidated Financial Statements included in this
Annual Report on Form 10-K. For information about the aggregate number of stock options held
by each of our nonemployee Directors, you should read the table below under the heading
Outstanding Equity Awards at 2007 Fiscal Year-End. |
|
(3) |
|
Mr. Chitwood resigned from the Board of Directors on January 23, 2007. |
|
(4) |
|
On March 27, 2007, a stock option to purchase 17,500 shares of common stock was granted to
Mr. Poage under the Parallel Petroleum Corporation 1997 Nonemployee Directors Stock Option
Plan. The option becomes exercisable with respect to 8,750 shares on March 27, 2008 and the
remaining 8,750 shares become exercisable on March 27, 2009. The grant date fair value of the
option award, computed in accordance with FAS 123(R), was $217,898. |
|
(5) |
|
This amount includes $7,500 for Mr. Shraders service as Chairman of the Corporate Governance
and Nominating Committee for 2004, 2005 and 2006 but paid in 2007. |
Narrative descriptions of the components of our Director compensation are included below under
the captions Cash; Stock Options; Other; 2004 Non-Employee Director
Stock Grant Plan; Stock Option Plans 1997 Nonemployee Directors Stock Option Plan and
2001 Nonemployee Directors Stock Option Plan.
(81)
In the table below, we show certain information about the outstanding equity awards held by
our non-employee Directors at December 31, 2007.
Outstanding Equity Awards at 2007 Fiscal Year-End
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Option Awards |
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Stock Awards |
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Equity |
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Equity |
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Incentive |
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Incentive |
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Plan |
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Plan |
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Awards: |
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Equity |
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Awards: |
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Market or |
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Incentive |
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Number |
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Payout |
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Plan |
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Market |
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of |
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Value of |
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Number |
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Number |
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Awards: |
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Number |
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Value |
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Unearned |
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Unearned |
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of |
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of |
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Number |
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of Shares |
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of Shares |
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Shares, |
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Shares, |
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Securities |
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Securities |
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of |
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or |
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or Units |
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Units or |
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Units or |
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Underlying |
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Underlying |
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Securities |
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Units of |
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of |
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Other |
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Other |
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Unexercised |
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Unexercised |
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Underlying |
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Stock |
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Stock |
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Rights |
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Rights |
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Options |
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Options |
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Unexercised |
|
Option |
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Option |
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That Have |
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That Have |
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That Have |
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That Have |
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(#) |
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(#) |
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Unearned |
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Exercise |
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Expiration |
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Not |
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Not |
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Not |
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Not |
Name |
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Exercisable |
|
Unexercisable |
|
Options |
|
Price |
|
Date |
|
Vested |
|
Vested |
|
Vested |
|
Vested |
E. A. Nash |
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
M.B. Oring |
|
|
5,000 |
|
|
|
0 |
|
|
|
0 |
|
|
$ |
4.58 |
|
|
|
05-02-11 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
25,000 |
|
|
|
0 |
|
|
|
0 |
|
|
$ |
4.97 |
|
|
|
06-21-11 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
34,500 |
|
|
|
0 |
|
|
|
0 |
|
|
$ |
2.80 |
|
|
|
12-18-12 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
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0 |
|
|
|
|
20,000 |
|
|
|
0 |
|
|
|
0 |
|
|
$ |
4.61 |
|
|
|
05-07-11 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
10,000 |
|
|
|
15,000 |
(1) |
|
|
0 |
|
|
$ |
12.27 |
|
|
|
08-23-15 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
10,000 |
|
|
|
15,000 |
(1) |
|
|
0 |
|
|
$ |
12.27 |
|
|
|
08-23-15 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
R.M. Poage |
|
|
50,000 |
|
|
|
0 |
|
|
|
0 |
|
|
$ |
2.61 |
|
|
|
04-28-13 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
20,000 |
|
|
|
30,000 |
(2) |
|
|
0 |
|
|
$ |
12.27 |
|
|
|
08-23-15 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
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0 |
|
|
|
17,500 |
(3) |
|
|
0 |
|
|
$ |
22.89 |
|
|
|
03-27-17 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
J.G. Shrader |
|
|
20,000 |
|
|
|
30,000 |
(2) |
|
|
0 |
|
|
$ |
12.27 |
|
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|
08-23-15 |
|
|
|
0 |
|
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0 |
|
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0 |
|
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|
0 |
|
|
|
|
(1) |
|
These stock options become exercisable with respect to 5,000 shares on the twenty-third day
of August in each of the years 2008 through 2010. |
|
(2) |
|
These stock options become exercisable with respect to 10,000 shares on August 23, 2008 and
on the twenty-third day of August in each of the years 2009 and 2010. |
|
(3) |
|
This stock option becomes exercisable with respect to 8,750 shares on March 27, 2008, and an
additional 8,750 shares become exercisable on March 27, 2009. |
Cash
Following stockholder approval of the 2004 Non-Employee Director Stock Grant Plan in June
2004, we reduced by one-half the per meeting and annual cash fees we had been paying to our
non-employee Directors. For 2007, we paid each non-employee Director a cash fee of $750 for
attendance at each meeting of the Board of Directors and each non-employee Director who is a member
of a Board committee also received:
|
|
$375 per meeting for service on the Compensation Committee, with the Chairman of the
Compensation Committee being entitled to receive an additional fee of $2,500 per year; |
(82)
|
|
$375 per meeting for service on the Audit Committee, with the Chairman of the Audit
Committee being entitled to receive an additional fee of $5,000 per year and each other
Audit Committee member receiving $2,500 per year; |
|
|
$375 per meeting for service on the Corporate Governance and Nominating Committee,
with the Chairman of the Corporate Governance and Nominating Committee being entitled
to receive an additional fee of $2,500 per year; and |
|
|
$375 per meeting for service on the Hedging and Acquisitions Committee, with the
Chairman of the Hedging and Acquisitions Committee being entitled to receive an
additional fee of $2,500 per year. |
Stock Options
Directors who are not employees of Parallel are also eligible to participate in Parallels
1997 Nonemployee Directors Stock Option Plan and the 2001 Nonemployee Directors Stock Option Plan.
You can find more information about these stock option plans under the caption Stock Option Plans
below.
Other
All Directors are reimbursed for expenses incurred in connection with attending meetings.
Parallel provides liability insurance for its Directors and officers. The cost of this
coverage for 2007 was approximately $524,000.
We do not offer non-employee Directors travel accident insurance, life insurance or a pension
or retirement plan.
2004 Non-Employee Director Stock Grant Plan
In April 2004, upon recommendation of the Boards Compensation Committee, our Directors
approved the 2004 Non-Employee Director Stock Grant Plan. The plan was later approved by our
stockholders at our annual meeting held on June 22, 2004. Directors of Parallel who are not
employees of Parallel or any of its subsidiaries are eligible to participate in the Plan. Under
this Plan, each non-employee Director is entitled to receive an annual retainer fee consisting of
shares of common stock that will be automatically granted on the first day of July in each year.
The actual number of shares received is determined by dividing $25,000 by the average daily closing
price of the common stock on the Nasdaq Global Market for the ten consecutive trading days
commencing fifteen trading days before the first day of July of each year. Historically, Directors
fees had been paid solely in cash. However, in accordance with this plan and following approval by
our stockholders, we commenced paying an annual retainer fee in July 2004 to each non-employee
Director in the form of common stock having a value of $25,000.
This plan is administrated by the Compensation Committee. Although the Compensation Committee
has authority to adopt such rules and regulations for carrying out the plan as it may deem proper
and in the best interests of Parallel, the Committees administrative functions are largely
ministerial in view of the plans explicit provisions described below, including those related to
eligibility and predetermination of the timing, pricing and amount of grants. The interpretation by
the Compensation Committee of any provision of the plan is final.
The total number of shares of common stock initially available for grant under the plan was
116,000 shares, subject to adjustment as described below. If there is a change in the common stock
by reason of a merger, consolidation, reorganization, recapitalization, stock dividend, stock
split, combination of shares, exchange of shares, change in corporate structure or otherwise, the
aggregate number of shares available under the plan will be appropriately adjusted in order to
avoid dilution or enlargement of the rights intended to be made available under the plan.
The Board may suspend, terminate or amend the plan at any time or from time to time in any
manner that the Board may deem appropriate; provided that, without approval of the stockholders, no
revision or amendment shall change the eligibility of Directors to receive stock grants, the number
of shares of common stock subject to any grants, or materially increase the benefits accruing to
participants under the plan, and plan provisions relating to the amount, price and timing of grants
of stock may not be amended.
Shares acquired under the plan are non-assignable and non-transferable other than by will or
the laws of descent and distribution and may not be sold, pledged, hypothecated, assigned or
transferred until the non-employee
(83)
Director holding such stock ceases to be a Director, except that the Compensation Committee
may permit a transfer of stock subject to the condition that the Compensation Committee receive
evidence satisfactory to it that the transfer is being made for essentially estate and/or tax
planning purposes or a gratuitous or donative purpose and without consideration.
The plan will remain in effect until terminated by the Board, although no additional shares of
common stock may be issued after the 116,000 shares subject to the plan have been issued.
At February 8, 2008, 74,420 shares of common stock were available for issuance under this
plan.
Stock Option Plans
1992 Stock Option Plan. In May 1992, our stockholders approved and adopted the 1992
Stock Option Plan. The 1992 Plan expired by its own terms on March 1, 2002, but remains effective
only for purposes of outstanding options. The 1992 Plan provided for granting to key employees,
including officers and Directors who were also key employees of Parallel, and Directors who were
not employees, options to purchase up to an aggregate of 750,000 shares of common stock. Options
granted under the 1992 Plan to employees are either incentive stock options or options which do not
constitute incentive stock options. Options granted to non-employee Directors are not incentive
stock options.
The 1992 Plan is administered by the Boards Compensation Committee, none of whom were
eligible to participate in the 1992 Plan, except to receive a one-time option to purchase 25,000
shares at the time he or she became a Director. The Compensation Committee selected the employees
who were granted options and established the number of shares issuable under each option and other
terms and conditions approved by the Compensation Committee. The purchase price of common stock
issued under each option is the fair market value of the common stock at the time of grant.
The 1992 Plan provided for the granting of an option to purchase 25,000 shares of common stock
to each individual who was a non-employee Director of Parallel on March 1, 1992 and to each
individual who became a nonemployee Director following March 1, 1992. Members of the Compensation
Committee were not eligible to participate in the 1992 Plan other than to receive a nonqualified
stock option to purchase 25,000 shares of common stock as described above.
When the 1992 Plan expired on March 1, 2002, 65,000 shares of common stock remained authorized
for issuance under the 1992 Plan. However, the 1992 Plan prohibited the grant of options after
March 1, 2002. Consequently, no additional options are available for grant under the 1992 Plan.
At February 8, 2008, options to purchase a total of 20,000 shares of common stock were
outstanding under the 1992 Plan.
1997 Nonemployee Directors Stock Option Plan. The 1997 Nonemployee Directors Stock
Option Plan was approved by our stockholders at the annual meeting of stockholders held in May
1997. This plan provides for granting to Directors who are not employees of Parallel options to
purchase up to an aggregate of 500,000 shares of common stock. Options granted under this plan are
not incentive stock options within the meaning of the Internal Revenue Code.
This plan is administered by the Compensation Committee of the Board of Directors. The
Compensation Committee has sole authority to select the non-employee Directors who are to be
granted options; to establish the number of shares which may be issued to non-employee Directors
under each option; and to prescribe the terms and conditions of the options in accordance with the
plan. Under provisions of the plan, the option exercise price must be the fair market value of the
stock subject to the option on the grant due. Options are not transferable other than by will or
the laws of descent and distribution and are not exercisable after ten years from the date of
grant.
The purchase price of shares as to which an option is exercised must be paid in full at the
time of exercise in cash, by delivering to Parallel shares of stock having a fair market value
equal to the purchase price, or a combination of cash and stock, as established by the Compensation
Committee.
Options may not be granted under this plan after March 27, 2007 and at December 31, 2007,
there were no shares of common stock available for future option grants under this plan.
(84)
At February 8, 2008, options to purchase a total of 97,500 shares of common stock were
outstanding under this plan.
1998 Stock Option Plan. In June 1998, our stockholders adopted the 1998 Stock Option
Plan. The 1998 Plan provides for the granting of options to purchase up to 850,000 shares of common
stock. Stock options granted under the 1998 Plan may be either incentive stock options or stock
options which do not constitute incentive stock options.
The 1998 Plan is administered by the Compensation Committee of the Board of Directors. Members
of the Compensation Committee are not eligible to participate in the 1998 Plan. Only employees are
eligible to receive options under the 1998 Plan and the Compensation Committee selects the
employees who are granted options and establishes the number of shares issuable under each option.
Options granted to employees contain terms and conditions that are approved by the
Compensation Committee. The Compensation Committee is empowered and authorized, but is not
required, to provide for the exercise of options by payment in cash or by delivering to Parallel
shares of common stock having a fair market value equal to the purchase price, or any combination
of cash and common stock. The purchase price of common stock issued under each option must not be
less than the fair market value of the common stock at the time of grant. Options granted under the
1998 Plan are not transferable other than by will or the laws of descent and distribution and are
not exercisable after ten years from the date of grant.
Options may not be granted under the 1998 Plan after March 11, 2008. However, at December 31,
2007, there were no shares of common stock available for future option grants under the 1998 Stock
Option Plan.
At February 8, 2008, options to purchase a total of 72,500 shares of common stock were
outstanding under this plan.
2001 Nonemployee Directors Stock Option Plan. The 2001 Nonemployee Directors Stock
Option Plan was approved by our stockholders at the annual meeting of stockholders held in June
2001. This plan provides for granting to Directors who are not employees of Parallel options to
purchase up to an aggregate of 500,000 shares of common stock. Options granted under the plan will
not be incentive stock options within the meaning of the Internal Revenue Code.
This plan is administered by the Compensation Committee of the Board of Directors. The
Compensation Committee has sole authority to select the non-employee Directors who are to be
granted options; to establish the number of shares which may be issued to non-employee Directors
under each option; and to prescribe such terms and conditions as the Committee prescribes from time
to time in accordance with the plan. Under provisions of the plan, the option exercise price must
be the fair market value of the stock subject to the option on the grant date. Options are not
transferable other than by will or the laws of descent and distribution and are not exercisable
after ten years from the date of grant.
The purchase price of shares as to which an option is exercised must be paid in full at the
time of exercise in cash, by delivering to Parallel shares of stock having a fair market value
equal to the purchase price, or a combination of cash and stock, as established by the Compensation
Committee.
Options may not be granted under this plan after May 2, 2011. However, at December 31, 2007,
no shares of common stock were available for future option grants under this plan.
At February 8, 2008, options to purchase 184,500 shares of common stock were outstanding under
this plan.
2001 Employee Stock Option Plan. In June 2001, our Board of Directors adopted the2001
Employee Stock Option Plan. This plan authorized the grant of options to purchase up to 200,000
shares of common stock, or less than 1.00% of our outstanding shares of common stock. Directors and
officers are not eligible to receive options under this plan. Only employees are eligible to
receive options. Stock options granted under this plan are not incentive stock options.
This plan was implemented without stockholder approval.
(85)
The 2001 Employee Stock Option Plan is administrated by the Compensation Committee of the
Board of Directors. The Compensation Committee selects the employees who are granted options and
establishes the number of shares issuable under each option.
Options granted to employees contain terms and conditions that are approved by the
Compensation Committee. The Compensation Committee is empowered and authorized, but is not
required, to provide for the exercise of options by payment in cash or by delivering to Parallel
shares of common stock having a fair market value equal to the purchase price, or any combination
of cash and common stock. The purchase price of common stock issued under each option must not be
less than the fair market value of the common stock at the time of grant. Options granted under
this plan are not transferable other than by will or the laws of descent and distribution.
The Employee Stock Option Plan will expire on June 20, 2011. However, at December 31, 2007, no
shares of common stock were available for future option grants under this plan.
At February 8, 2008, options to purchase 183,000 shares of common stock were outstanding under
this plan.
Section 401(k) Retirement Plan
Effective January 1, 2005, we adopted a retirement plan qualifying under Section 401(k) of the
Internal Revenue Code. This plan is designed to provide eligible employees with an opportunity to
save for retirement on a tax-deferred basis. A third party acts as the plans administrator and is
responsible for the day-to-day administration and operation of the plan. This plan is maintained on
a yearly basis beginning on January 1 and ending on December 31 of each year.
Each employee is eligible to participate in the plan as of the date of his or her employment.
An employee may elect to have his or her compensation reduced by a specific percentage or dollar
amount and have that amount contributed to the plan as a salary deferred contribution. A plan
participants aggregate salary deferred contributions for a plan year may not exceed certain
statutory dollar limits, which for 2007 was $15,500. In addition to the annual salary deferral
limit, employees who reach age 50 or older during a calendar year can elect to take advantage of a
catch-up salary deferral contribution which, for 2007, was $5,000.The amount deferred by a plan
participant, and any earnings on that amount, are not subject to income tax until actually
distributed to the participant.
Each year, in addition to salary deferrals made by a participant, Parallel may contribute to
the plan safe harbor contributions and discretionary matching contributions. Matching
contributions, if made, will equal a uniform percentage of a participants salary deferrals. The
Compensation Committee established a safe harbor profit sharing contribution of 3% and a
discretionary matching contribution in an amount not to exceed 3% of a participants annual salary.
Each participant will share in discretionary profit sharing contributions, if any, regardless of
the amount of service completed by the participant during the applicable plan year.
Each participant may direct the investment of his or her interest in the plan under
established investment direction procedures setting forth the investment choices available to the
participants. Each participant will be entitled to all of the participants account under the plan
upon retirement after age 65. Each participant is at all times 100% vested in amounts attributed to
the participants salary deferrals and to matching contributions and discretionary profit sharing
contributions made by Parallel. The plan contains special provisions relating to disability and
death benefits.
Participants may borrow from their respective plan accounts, subject to the plan
administrators determination that the participant submitting an application for a loan meets the
rules and requirements set forth in the written loan program established by Parallel. Parallel has
the right to amend the plan at any time. However, no amendment may authorize or permit any part of
the plan assets to be used for purposes other than the exclusive benefit of participants or their
beneficiaries.
We make matching contributions to employee accounts in an amount equal to the contribution
made by each employee, subject to a maximum of 6% of each employees salary during any calendar
year. During 2007, we contributed an aggregate of $274,335 to the accounts of 45 employee
participants. Of this amount, $19,800 was allocated to Mr. Oldhams account; $10,500 was allocated
to Mr. Bayleys account; $10,500 was allocated to Mr. Rutherfords account; $16,500 to Mr. Tiffins
account; and $11,400 to Mr. Fosters account.
(86)
|
|
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS |
The
table below shows information as of February 14, 2008 about the beneficial ownership of
common stock by: (1) each person known by us to own beneficially more than five percent of our
outstanding common stock; (2) our five current executive officers named in the Summary Compensation
Table on page 73; (3) each Director of Parallel; and (4) all of our executive officers and
Directors as a group.
|
|
|
|
|
|
|
|
|
Name and Address |
|
Amount and Nature |
|
Percent |
of |
|
of |
|
of |
Beneficial Owner |
|
Beneficial Ownership (1) |
|
Class(2) |
|
|
|
|
|
|
|
|
|
Larry C. Oldham
1004 N. Big Sp ring, Suite 400
Midland, Texas 79701
|
|
|
733,590 |
(3) |
|
|
1.78 |
% |
|
|
|
|
|
|
|
|
|
Donald E. Tiffin
1004 N. Big Sp ring, Suite 400
Midland, Texas 79701
|
|
|
24,350 |
(4) |
|
|
* |
|
|
|
|
|
|
|
|
|
|
Eric A. Bay ley
1004 N. Big Sp ring, Suite 400
Midland, Texas 79701
|
|
|
153,490 |
(5) |
|
|
* |
|
|
|
|
|
|
|
|
|
|
Steven D. Foster
1004 N. Big Sp ring, Suite 400
Midland, Texas 79701
|
|
|
16,000 |
(6) |
|
|
* |
|
|
|
|
|
|
|
|
|
|
John S. Rutherford
1004 N. Big Sp ring, Suite 400
Midland, Texas 79701
|
|
|
89,800 |
(7) |
|
|
* |
|
|
|
|
|
|
|
|
|
|
Edward A. Nash
16214 Lafone
Spring, Texas 77379
|
|
|
1,100 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
Martin B. Oring
10817 Grande Blvd.
West Palm Beach, Florida 33417
|
|
|
208,414 |
(8) |
|
|
* |
|
|
|
|
|
|
|
|
|
|
Ray M. Poage
4711 Meandering Way
Colleyville, Texas 76034
|
|
|
109,213 |
(9) |
|
|
* |
|
|
|
|
|
|
|
|
|
|
Jeffrey G. Shrader
801 S. Filmore, Suite 600
Amarillo, Texas 79105
|
|
|
55,395 |
(10) |
|
|
* |
|
|
|
|
|
|
|
|
|
|
Dreman
Value Management, L.L.C.
520 East Cooper Ave., Suite 230-4
Aspen, Colorado 81611
|
|
|
2,203,250 |
(11) |
|
|
5.34 |
% |
|
|
|
|
|
|
|
|
|
Neuberger Berman, Inc.
605 Third Avenue
New York, New York 10158
|
|
|
4,115,645 |
(12) |
|
|
9.98 |
% |
|
|
|
|
|
|
|
|
|
Next Century Growth Investors, LLC
5500 Wayzata Blvd., Suite 1275
Minneapolis, Minnesota 55416
|
|
|
2,947,394 |
(13) |
|
|
7.14 |
% |
|
|
|
|
|
|
|
|
|
All Executive
Officers and
Directors
as a Group(9 persons)
|
|
|
1,391,352 |
(14) |
|
|
3.35 |
% |
(87)
|
|
|
* |
|
Less than one percent. |
|
(1) |
|
Unless otherwise indicated, all shares of common stock
are held directly with sole voting and investment powers. |
|
|
|
(2) |
|
Securities not outstanding, but included in the
beneficial ownership of each such person, are deemed to be outstanding for
the purpose of computing the percentage of outstanding securities of the
class owned by such person, but are not deemed to be outstanding for the
purpose of computing the percentage of the class owned by any other person.
Shares of common stock that may be acquired within sixty days of February 8,
2008 upon exercise of outstanding stock options are deemed to be
outstanding. |
|
(3) |
|
Includes 400,000 shares of common stock held indirectly
through Oldham Properties, Ltd., a limited partnership, and as to which Mr.
Oldham disclaims beneficial ownership. Also included are 15,000 shares of
common stock underlying a presently exercisable stock option held by Mr.
Oldham. At February 8, 2008, a total of 50,000 shares of common stock were
pledged as collateral to secure repayment of loans. |
|
(4) |
|
Of the total number of shares shown, 9,350 shares are
held indirectly through Mr. Tiffins individual retirement account. |
|
(5) |
|
Includes 75,000 shares of common stock underlying
presently exercisable stock options. A total of 6,790 shares of common
stock are held indirectly by Mr. Bayley through an Individual Retirement
Account and 408(k) Plan. At February 8, 2008, a total of 40,000 shares of
common stock were pledged as collateral to secure repayment of loans. The
total number of shares shown excludes a warrant to purchase 200 shares of
common stock. |
|
(6) |
|
Includes 400 shares of common stock held by Mr. Fosters
wife and 9,000 shares held in his 408(k) Plan. |
|
(7) |
|
Includes 44,000 shares of common stock underlying a
presently exercisable stock option. At February 8, 2008, a total of 45,800
shares of common stock were pledged as collateral to secure repayment of
loans. |
|
(8) |
|
Of the total number of shares shown, 15,500 shares are
held directly by Mr. Orings wife; 82,019 shares are held by Wealth
Preservation, LLC, a limited liability company owned and controlled by Mr.
Oring and his wife; and 104,500 shares may be acquired by Mr. Oring upon
exercise of stock options that are presently exercisable or that become
exercisable within the next sixty days. |
|
(9) |
|
Includes 20,068 shares of common stock held indirectly by
Mr. Poage through his individual retirement account. Also included are
78,750 shares that may be acquired upon exercise of stock options that are
presently exercisable or that become exercisable within the next sixty days. |
|
(10) |
|
Includes 20,000 shares of common stock that may be
acquired upon exercise of a presently exercisable stock option or that
become exercisable within the next sixty days. At February 8, 2008, a total
of 25,000 shares of common stock were pledged as collateral to secure
repayment of loans. |
|
(11) |
|
As reported in Schedule 13G filed by Dreman Value Management,
L.L.C., an investment advisor, with the Securities and Exchange
Commission on February 14, 2008, Dreman Value Management, L.L.C.,
or “Dreman”, reported beneficial ownership of 2,203,250 shares of
common stock. Of these shares, Dreman reported sole voting power with
respect to 624,950 shares; shared voting power with respect to 22,900
shares and shared dispositive power with respect to 2,203,250
shares. |
|
(12) |
|
Based on Amendment No. 1 to Schedule 13G filed by
Neuberger Berman, Inc., Neuberger Berman, LLC, Neuberger Berman
Management, Inc. and Neuberger Berman Equity Funds with the
Securities and Exchange Commission on February 12, 2008,
Neuberger Berman, Inc. or “NBI”, reported beneficial ownership of
4,115,645 shares of common stock. Of these shares, NBI and Neuberger
Berman, LLC each reported sole voting power with respect to 118,204
shares; shared voting power with respect to 3,067,141 shares; and
shared dispositive power with respect to 4,115,645 shares. Neuberger
Berman Management, Inc. reported shared voting and dispositive
powers with respect to 3,067,145 shares and Neuberger Berman Equity
Funds reported shared voting and dispositive powers with respect to
3,032,641 shares. NBI is the parent company of |
(88)
|
|
|
|
|
Neuberger Berman, LLC,
an investment advisor and broker-dealer, and Neuberger Berman
Management Inc., an investment advisor to a series of public mutual
funds. Neuberger Berman, LLC is deemed to be a beneficial owner of
such shares since it has shared dispositive power, and in some cases
the sole power to vote such shares. Neuberger Berman Management Inc.
is deemed to be a beneficial owner of such shares since it has shared
dispositive and voting power. The
holdings of Lehman Brothers Asset Management LLC, an affiliate of
Neuberger Berman LLC, are also included in the total number of shares
shown. |
|
(13) |
|
Based on Schedule 13G filed by Next Century Growth Investors,
LLC, Thomas L. Press and Donald M. Longlet with the Securities and
Exchange Commission on February 14, 2008, Next Century Growth
Investors, LLC, or “NCGI”, reported beneficial ownership of 2,947,394
shares of common stock. NCGI reported that it may be deemed to be
the beneficial owner of such shares by virtue of its investment
discretion and/or voting power over client securities, which may be
revoked, and that Thomas L. Press and Donald M. Longlet may also be
deemed to have beneficial ownership of such shares as a result of
their positions with and ownership positions in NCGI, which could be
deemed to confer upon each of them voting and/or investment power
over the shares. Each of NCGI, Thomas L. Press and Donald M. Longlet
disclaim beneficial ownership of such shares except to the extent of
each of their respective pecuniary interests therein, if any. |
|
(14) |
|
Includes 337,250 shares of common stock underlying stock
options that are presently exercisable or that become exercisable within the
next sixty days. |
Equity Compensation Plans
At December 31, 2007, a total of 631,920 shares of common stock were authorized for issuance
under our equity compensation plans. In the table below, we describe certain information about
these shares and the equity compensation plans which provide for their authorization and issuance.
You can find additional information about our stock grant and stock option plans beginning on page
84.
Equity Compensation Plan Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(c) |
|
|
|
|
|
|
|
|
|
|
Number of securities |
|
|
|
|
|
|
(b) |
|
remaining available for |
|
|
(a) |
|
Weighted-average |
|
future issuance under |
|
|
Number of securities to be |
|
exercise |
|
equity compensation |
|
|
issued upon exercise of |
|
price of outstanding |
|
plans (excluding |
|
|
outstanding options, |
|
options, warrants and |
|
securities reflected in |
Plan category |
|
warrants and rights |
|
rights |
|
column (a)) |
Equity compensation plans approved by security holders |
|
|
374,500 |
(1) |
|
$ |
8.03 |
|
|
|
74,420 |
(2) |
Equity compensation plans not approved by security holders |
|
|
183,000 |
(3) |
|
$ |
4.97 |
|
|
|
|
|
Total |
|
|
557,500 |
|
|
$ |
7.03 |
|
|
|
74,420 |
|
|
|
|
(1) |
|
Includes shares of common stock issuable upon exercise of stock options granted under our
1992 Stock Option Plan, 1997 Nonemployee Directors Stock Option Plan, 1998 Stock Option Plan,
and 2001 Nonemployee Directors Stock Option Plan. |
|
(2) |
|
These shares of common stock are available for future issuance under our 2004 Non-Employee
Director Stock Grant Plan. |
|
(3) |
|
These shares represent shares of common stock underlying stock options granted on June 20,
2001 to non-officer employees under our 2001 Employee Stock Option Plan. The 2001 Employee
Stock Option Plan is the only equity compensation plan in effect that we have adopted without
approval of our stockholders. Our directors and officers are not eligible to participate in
this plan. A description of the material features of this plan can be found under the caption
2001 Employee Stock Option Plan on page 85. |
(89)
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Certain Transactions
During 2007, Cambridge Production, Inc., a corporation owned by Thomas R. Cambridge, our
former Chairman of the Board of Directors, served as operator of two wells on oil and natural gas
leases in which we acquired a working interest in 1984. Generally, the operator of a well is
responsible for the day to day operations on the lease, overseeing production, employing field
personnel, maintaining production and other records, determining the location and timing of
drilling of wells, administering natural gas contracts, joint interest billings, revenue
distribution, making various regulatory filings, reporting to working interest owners and other
matters. During 2007, Cambridge Production billed us approximately $27,000 for our pro rata share
of lease operating expenses. The largest amount we owed Cambridge Production at any one time during
2007 was approximately $6,400. As of December 31, 2007, approximately $750 was owed by us to
Cambridge Production for these expenses. Our pro rata share of oil and natural gas sales during
2007 from the wells operated by Cambridge Production was approximately $65,000. Cambridge
Productions billings to us are made monthly on the same basis as all other working interest owners
in the wells.
Cambridge Partnership, Ltd., a limited partnership controlled by Mr. Cambridge, acquired an
undivided working interest in 1999 from us in an oil and natural gas prospect located in south
Texas. The interest was acquired on the same terms as all other unaffiliated working interest
owners. Since then, Cambridge Partnership, Ltd. has participated with us in the drilling and
development of this prospect. Cambridge Partnership, Ltd. has participated in these operations
under standard form operating agreements on the same or similar terms afforded by Parallel to
nonaffiliated third parties. Although we are not the operator of this project, we invoiced
Cambridge Partnership, Ltd., on a monthly basis, without interest, for its pro rata share of
operating expenses. During 2007, we billed Cambridge Partnership, Ltd. approximately $1,300 for its
proportionate share of lease operating expenses incurred on
properties we administer, and Cambridge
Partnership, Ltd. paid us approximately $1,600 for its proportionate share of lease operating
expenses, which included approximately $285 attributable to expenses billed to Cambridge
Partnership, Ltd. in 2006. The largest amount owed to us by Cambridge Partnership, Ltd. at any one
time during 2007 for its share of lease operating expenses was approximately $300. At December 31,
2007, no amount was owed us by Cambridge Partnership, Ltd. for these expenses. During 2007, we
disbursed approximately $4,600 to Cambridge
Partnership, Ltd. in payment of revenues attributable to its pro rata share of the proceeds
from sales of oil and natural gas produced from properties in which we and Cambridge Partnership,
Ltd. owned interests. We and Cambridge Partnership, Ltd. sold our interests in this project in
June 2007 to an unaffiliated third party and we distributed approximately $10,000 to Cambridge
Partnership, Ltd., its pro rata share of the sales proceeds.
Cambridge Production, Inc. maintains an office in Amarillo, Texas from which Mr. Cambridge
performed his duties and services as Chairman of the Board and as geological consultant to us until
his retirement on June 26, 2007. Prior to his retirement, we reimbursed Cambridge Production, Inc.
$3,000 per month for office and administrative expenses incurred on our behalf. During 2007 we
reimbursed Cambridge Production, Inc. a total of $18,000.
In December 2001, and prior to his employment by us, Donald E. Tiffin, our Chief Operating
Officer, received from an unaffiliated third party a 3% working interest in our Diamond M project
in Scurry County, Texas for services rendered in connection with assembling the project. In August
2002, shortly after his employment with us, and due to the personal financial exposure in the
Diamond M project and to prevent the interest from being acquired by a third party, Mr. Tiffin
assigned two-thirds of his ownership interest in the project to us at no cost, leaving him with a
1% working interest. We acquired our initial interest in the Diamond M Project from the same third
party in December 2001, but did not become operator of the project until March 1, 2003. As with
other nonaffiliated interest owners, we invoice Mr. Tiffin on a monthly basis, without interest,
for his share of drilling, development and lease operating expenses. During 2007, we billed Mr.
Tiffin a total of approximately $45,000 for his proportionate share of capital expenditures and
lease operating expenses, and Mr. Tiffin paid us approximately $47,000 for these drilling and
development expenses, which included approximately $8,000 attributable to expenses billed to Mr.
Tiffin in 2006. During 2007, we disbursed to Mr. Tiffin approximately $65,000 in oil and natural
gas revenues related to his interest in this project. The largest aggregate amount outstanding and
owed to us by Mr. Tiffin at any one time during 2007 was approximately $11,000. At December 31,
2007, Mr. Tiffin owed us approximately $5,000.
We believe the transactions described above were made on terms no less favorable than if we
had entered into the transactions with an unrelated party.
(90)
Director Independence
Under the Delaware General Corporation Law and our bylaws, Parallels business, property and
affairs are managed by or under the direction of the Board of Directors. Members of the Board are
kept informed of our business through discussions with the Chairman of the Board, the Chief
Executive Officer and other officers, by reviewing materials provided to them and by participating
in meetings of the Board and its committees. In 2007, seven individuals served as a Director of
Parallel for all or a portion of the year. These individuals included Thomas R. Cambridge, Dewayne
E. Chitwood, Edward A. Nash, Larry C. Oldham, Martin B. Oring, Ray M. Poage and Jeffrey G. Shrader.
Mr. Chitwood resigned from the Board on January 23, 2007 and Mr. Cambridge retired from the Board
on June 26, 2007 in accordance with our retirement policy for non-employee Directors. Under this
retirement policy, a non-employee Director may not stand for re-election at the annual meeting of
stockholders following the date on which he or she attains age 72. Mr. Cambridge, a Director of
Parallel since 1985, turned age 72 before the date of the 2007 annual meeting of stockholders and,
consequently, did not stand for re-election at the 2007 annual meeting. Mr. Nash was first elected
as a Director at the 2007 annual meeting of stockholders. Messrs. Nash, Oldham, Oring, Poage and
Shrader continue to serve as Directors.
The Board has determined that Messrs. Nash, Oring, Poage and Shrader meet the definition of an
independent director for the purposes of NASD Rule 4200(a)(15), the independence standards
applicable to us, and that Mr. Chitwood was also an independent director . The Board based these
determinations primarily on responses of the Directors to questions regarding employment and
compensation history, affiliations and family and other relationships, comparisons of the
independence criteria under NASD Rule 4200(a)(15) to the particular circumstances of each Director
and on discussions among the Directors.
Procedures for Reviewing Certain Transactions
We have adopted a written policy for the review, approval or ratification of related party
transactions. All of our officers, directors and employees are subject to this policy. Under this
policy, the Audit Committee reviews all related party transactions for potential conflicts of
interest situations. Generally, our policy defines a related party transaction as a transaction
in which we are a participant and the amount involved exceeds $10,000, and in which a related party
has an interest. A related party is:
|
|
|
a director or officer of Parallel or a nominee to become a director; |
|
|
|
|
an owner of more than 5% of our outstanding common stock; |
|
|
|
|
certain family members of any of the above persons; and |
|
|
|
|
any entity in which any of the above persons is employed or is a partner or
principal or in which such person has a 5% or greater ownership interest. |
Approval Procedures
Before entering into a related party transaction, the related party or the department within
Parallel responsible for the potential transaction must notify the Audit Committee of the facts and
circumstances of the proposed transaction, including:
|
|
|
the related partys relationship to Parallel and interest in the transaction; |
|
|
|
|
the material terms of the proposed transaction; |
|
|
|
|
the benefits to Parallel of the proposed transaction; |
|
|
|
|
the availability of other sources of comparable properties or services; and |
|
|
|
|
whether the proposed transaction is on terms comparable to terms available to an
unrelated third party or to employees generally. |
The Audit Committee will then consider all of the relevant facts and circumstances available
to it, including the matters described above and, if applicable, the impact on a Directors
independence. No member of the Audit Committee is permitted to participate in any review,
consideration or approval of any related party transaction if
(91)
such member or any of his or her
immediate family members is the related party. After review, the Audit Committee may approve,
modify or disapprove the proposed transaction. The Audit Committee will approve only those related
party transactions that are in, or are not inconsistent with, the best interests of Parallel and
its stockholders.
Ratification Procedures
If an officer or Director of Parallel becomes aware of a related party transaction that has
not been previously approved or ratified by the Audit Committee then, if the transaction is pending
or ongoing, the transaction must be submitted to the Audit Committee and the Audit Committee will
consider the matters described above. Based on the conclusions reached, the Audit Committee will
evaluate all options, including ratification, amendment or termination of the related party
transaction. If the transaction is completed, the Audit Committee will evaluate the transaction,
taking into account the same factors as described above, to determine if rescission of the
transaction or any disciplinary action is appropriate, and will request that we evaluate our
controls and procedures to determine the reason the transaction was not submitted to the Audit
Committee for prior approval and whether any changes to the procedures are recommended.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The Audit Committee had not, as of the time of filing this Annual Report on Form 10-K with the
Securities and Exchange Commission, adopted policies and procedures for pre-approving audit or
permissible non-audit services performed by our independent auditors. Instead, the Audit Committee
as a whole pre-approves all such services. In the future, our Audit Committee may approve the
services of our independent auditors pursuant to pre-approval policies and procedures adopted by
the Audit Committee, provided the policies and procedures are detailed
as to the particular service, the Audit Committee is informed of each service, and such
policies and procedures do not include delegation of the Audit Committees responsibilities to our
management.
The aggregate fees for professional services rendered by our principal accountants, BDO
Seidman, LLP, for 2007 and 2006 were:
|
|
|
|
|
|
|
|
|
Types of Fees |
|
2007 |
|
|
2006 |
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
Audit fees(1) |
|
$ |
736 |
|
|
$ |
469 |
|
Audit-related fees |
|
|
13 |
|
|
|
52 |
|
Tax fees |
|
|
|
|
|
|
|
|
All other fees |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
749 |
|
|
$ |
521 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes fees for professional services rendered in connection with
the audit of our internal control over financial reporting under Section 404
of the Sarbanes-Oxley Act of 2002 in the amounts of $175,000 and $160,000 for
2007 and 2006, respectively. |
We retained an independent third party to assist us in our Sarbanes-Oxley 404 readiness and
assessment of internal control over financial reporting. The aggregate fees for services provided
in connection with the internal control over financial reporting for 2007 and 2006 were
approximately $75,000 and $65,000, respectively, including associated expenses.
In the above table, audit fees are fees we paid for professional services for the audit of
our Consolidated Financial Statements included in our Annual Report on Form 10-K and for the review
of our Consolidated Financial Statements included in our Quarterly Reports on Form 10-Q, or for
services that are normally provided by our principal accountants in connection with statutory and
regulatory filings or engagements and fees for Sarbanes-Oxley 404 audit work. Audit-related fees
are fees billed for assurance and related regulatory filings.
(92)
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
The following documents are filed as part of this report:
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules
For a list of Consolidated Financial Statements and Schedules, see Index to the
Consolidated Financial Statements on page F-1, and incorporated herein by reference.
(a)(3) Exhibits
See Item 15(b) below.
(b) Exhibits:
A list of exhibits to this Annual Report on Form 10-K is set forth below.
|
|
|
No. |
|
Description of Exhibit |
|
|
|
3.1
|
|
Certificate of Incorporation of Registrant (Incorporated by reference to Exhibit 3.1 to Form
10-Q of the Registrant for the fiscal quarter ended June 30, 2004) |
|
|
|
3.2
|
|
Bylaws of Registrant (Incorporated by reference to Exhibit 10.1 of the Registrants Current
Report on Form 8-K filed on November 30, 2007) |
|
|
|
3.3
|
|
Certificate of Formation of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.3 of
the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004) |
|
|
|
3.4
|
|
Limited Liability Company Agreement of Parallel, L.L.C. (Incorporated by reference to Exhibit
No. 3.4 of the Registrants Statement on Form S-3, No. 333-119725 filed on October 13, 2004) |
|
|
|
3.5
|
|
Certificate of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit
No. 3.5 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on
October 13, 2004) |
|
|
|
3.6
|
|
Agreement of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No.
3.6 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October
13, 2004) |
|
|
|
4.1
|
|
Certificate of Designations, Preferences and Rights of Serial Preferred Stock 6%
Convertible Preferred Stock (Incorporated by reference to Exhibit 4.1 of Form 10-Q of the
Registrant for the fiscal quarter ended June 30, 2004) |
|
|
|
4.2
|
|
Certificate of Designations, Preferences and Rights of Series A Preferred Stock (Incorporated
by reference to Exhibit 4.2 of Form 10-K of the Registrant for the fiscal year ended December
31, 2000) |
|
|
|
4.3
|
|
Rights Agreement, dated as of October 5, 2000, between the Registrant and Computershare Trust
Company, Inc., as Rights Agent (Incorporated by reference to Exhibit 1 of Form 8-A of the
Registrant filed with the Securities and Exchange Commission on October 10, 2000) |
|
|
|
4.4
|
|
Form of common stock certificate of the Registrant (Incorporated by reference to Exhibit No.
4.6 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October
13, 2004) |
|
|
|
4.5
|
|
Warrant Purchase Agreement, dated November 20, 2001, between the Registrant and Stonington
Corporation (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant for the
fiscal year ended December 31, 2004) |
|
|
|
4.6
|
|
Warrant Purchase Agreement, dated December 23, 2003, between the Registrant and Stonington
Corporation (Incorporated by reference to Exhibit 4.8 of Form 10-K of the Registrant for the
fiscal year ended December 31, 2004) |
|
|
|
(93)
|
|
|
No. |
|
Description of Exhibit |
|
|
|
4.7
|
|
Purchase Warrant Agreement, dated as of October 1, 1980, between the Registrant and American
Stock Transfer, Inc. (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant
for the fiscal year ended December 31, 2006) |
|
|
|
4.8
|
|
First Amendment to Warrant Agreement, dated as of February 22, 2007, among the Registrant,
Computershare Shareholder Services, Inc. and Computershare Trust Company, N.A. (Incorporated
by reference to Exhibit 4.8 of Form 10-K of the Registrant for the fiscal year ended December
31, 2006) |
|
|
|
4.9
|
|
Form of Rule 144A 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.2 to the
Registrants Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
4.10
|
|
Form of IAI 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.3 to the
Registrants Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
4.11
|
|
Form of Regulation S 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.4 to
the Registrants Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
4.12
|
|
Indenture, dated as of July 31, 2007, among the Registrant as Issuer and Wells Fargo Bank,
National Association as Trustee (Incorporated by reference to Exhibit 4.1 to the Registrants
Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
4.13 |
|
Registration Rights Agreement, dated as of July 31, 2007, by and among the Registrant,
Jefferies & Company, Inc., Merrill Lynch, Pierce, Fenner and Smith Incorporated and BNP
Paribas Securities Corp. (Incorporated by reference to Exhibit 10.2 to the Registrants
Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
4.14
|
|
Purchase Agreement, dated as of July 26, 2007, by and among the Registrant, Jefferies &
Company, Inc., Merrill Lynch, Pierce, Fenner and Smith Incorporated and BNP Paribas Securities
Corp. (Incorporated by reference to Exhibit 4.2 to the Registrants Current Report on Form 8-K
filed on August 1, 2007) |
|
|
|
4.15
|
|
Form of 101/4% Unrestricted Senior Note due 2014 (Incorporated by reference to Exhibit 4.13 of
Form S-4 of the Registrant, Registration No. 333-148465) |
|
|
|
|
|
Executive Compensation Plans and Arrangements (Exhibit No.s 10.1 through 10.7): |
|
|
|
10.1
|
|
1992 Stock Option Plan (Incorporated by reference to Exhibit 10.1 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2004) |
|
|
|
10.2
|
|
Merrill Lynch, Pierce, Fenner & Smith Incorporated Prototype Simplified Employee Pension Plan
(Incorporated by reference to Exhibit 10.6 of the Registrants Form 10-K for the fiscal year
ended December 31, 1995) |
|
|
|
10.3
|
|
Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.3 of the
Registrants Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2005) |
|
|
|
10.4
|
|
1998 Stock Option Plan (Incorporated by reference to Exhibit 10.4 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2006) |
|
|
|
10.5
|
|
2001 Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.7 of
the Registrants Form 10-Q Report for the fiscal quarter ended March 31, 2004) |
|
|
|
10.6
|
|
2004 Non-Employee Director Stock Grant Plan (Incorporated by reference to Exhibit 10.1 of the
Registrants Form 8-K Report dated September 22, 2004) |
|
|
|
10.7
|
|
Incentive and Retention Plan (Incorporated by reference to Exhibit 10.7 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2006) |
|
|
|
10.8
|
|
First Amended and Restated Credit Agreement, dated December 20, 2002, by and among Parallel
Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, Western
National Bank and BNP Paribas (Incorporated by reference to Exhibit 10.2 of Form 8-K of the
Registrant, dated December 20, 2002) |
|
|
|
(94)
|
|
|
No. |
|
Description of Exhibit |
|
|
|
10.9
|
|
Guaranty dated December 20, 2002, between Parallel, L.L.C. and First American Bank, SSB, as
Agent (Incorporated by reference to Exhibit 10.3 of Form 8-K of the Registrant, dated December
20, 2002) |
|
|
|
10.10
|
|
First Amendment to First Amended and Restated Credit Agreement, dated as of September 12,
2003, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First
American Bank, SSB, Western National Bank, and BNP Paribas (Incorporated by reference to
Exhibit 10.29 of Form 10-Q of the Registrant for the quarter ended September 30, 2003) |
|
|
|
10.11
|
|
Second Amended and Restated Credit Agreement, dated September 27, 2004, by and among
Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB,
BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit
10.1 of the Registrants Form 8-K Report dated September 27, 2004 and filed with the
Securities and Exchange Commission on October 1, 2004) |
|
|
|
10.12
|
|
Agreement of Limited Partnership of West Fork Pipeline Company LP (Incorporated by reference
to Exhibit 10.21 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004) |
|
|
|
10.13
|
|
First Amendment to Second Amended and Restated Credit Agreement, dated as of December 27,
2004, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First
American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by
reference to Exhibit 10.1 of the Registrants Form 8-K Report dated December 30, 2004 and
filed with the Securities and Exchange Commission on December 30, 2004) |
|
|
|
10.14
|
|
Second Amendment to Second Amended and Restated Credit Agreement, dated as of April 1, 2005,
by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American
Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit
10.1 of the Registrants Form 8-K Report dated April 4, 2005 and filed with the Securities
and Exchange Commission on April 8, 2005) |
|
|
|
10.15
|
|
Third Amendment to Second Amended and Restated Credit Agreement (Incorporated by reference
to Exhibit 10.1 of the Registrants Form 8-K Report dated October 4, 2005 and filed with the
Securities and Exchange Commission on October 20, 2005) |
|
|
|
10.16
|
|
Purchase and Sale Agreement, dated as of October 14, 1005, among Parallel, L.P., Lynx
Production Company, Inc., Elton Resources, Inc., Cascade Energy Corporation, Chelsea Energy,
Inc., William P. Sutter, Trustee, William P. Sutter Trust, J. Leroy Bell, E. L. Brahaney,
Brent Beck, Cavic Interests, LLC and Stanley Talbott (Incorporated by reference to Exhibit
10.2 of the Registrants Form 8-K Report dated October 14, 2005 and filed with the Securities
and Exchange Commission on October 20, 2005) |
|
|
|
10.17
|
|
Ancillary Agreement to Purchase and Sale Agreement, dated October 14, 2005, between
Parallel, L.P. and Lynx Production Company, Inc. (Incorporated by reference to Exhibit 10.3 of
the Registrants Form 8-K Report dated October 14, 2005 and filed with the Securities and
Exchange Commission on October 20, 2005) |
|
|
|
10.18
|
|
Guarantee of Parallel, L.P., dated October 13, 2004 (Incorporated by reference to Exhibit
10.4 of the Registrants Form 8-K Report dated October 14, 2005 and filed with the Securities
and Exchange Commission on October 20, 2005) |
|
|
|
10.19
|
|
ISDA Master Agreement, dated as of October 13, 2005, between Parallel, L.P. and Citibank,
N.A. (Incorporated by reference to Exhibit 10.5 of the Registrants Form 8-K Report dated
October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005) |
|
|
|
10.20
|
|
Third Amended and Restated Credit Agreement, dated as of December 23, 2005, among Parallel
Petroleum Corporation, Parallel, L.P., Parallel, L.L.C. and Citibank Texas, N.A., BNP Paribas,
CitiBank F.S.B., Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland and
Fortis Capital Corp. (Incorporated by reference to Exhibit No. 10.1 of the Registrants Form
8-K Report, dated December 23, 2005, as filed with the Securities and Exchange Commission on
December 30, 2005) |
|
|
|
(95)
|
|
|
No. |
|
Description of Exhibit |
|
|
|
10.21
|
|
Second Lien Term Loan Agreement, dated November 15, 2005, among Parallel Petroleum
Corporation, Parallel, L.P., BNP Paribas and Citibank Texas, N.A. (Incorporated by reference
to Exhibit No. 10.4 of the Registrants Form 8-K Report, dated November 15, 2005, as filed
with the Securities and Exchange Commission on November 21, 2005) |
|
|
|
10.22
|
|
Intercreditor and Subordination Agreement, dated November 15, 2005, among Citibank Texas,
N.A., BNP Paribas, Parallel Petroleum Corporation, Parallel, L.P. and Parallel, L.L.C.
(Incorporated by reference to Exhibit No. 10.5 of the Registrants Form 8-K Report, dated
November 15, 2005, as filed with the Securities and Exchange Commission on November 21, 2005) |
|
|
|
10.23
|
|
Guaranty, dated as of December 23, 2005, made by Parallel, L.L.C. to and in favor of
Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.23 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2006) |
|
|
|
10.24
|
|
Third Amended and Restated Pledge Agreement, dated as of December 23, 2005, between
Parallel, L.L.C. and Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.24 of Form
10-K of the Registrant for the fiscal year ended December 31, 2006) |
|
|
|
10.25
|
|
Second Lien Guarantee and Collateral Agreement, dated as of November 15, 2005, made by
Parallel Petroleum Corporation and Parallel, L.P. to and in favor of BNP Paribas (Incorporated
by reference to Exhibit 10.25 of Form 10-K of the Registrant for the fiscal year ended
December 31, 2006) |
|
|
|
10.26
|
|
Third Amendment to Third Amended and Restated Credit Agreement, dated as of July 31, 2007,
among the Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank,
Comerica Bank, Bank of Scotland, and Fortis Capital Corp. (Incorporated by reference to Exhibit 10.3 of the
Registrants Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
10.27
|
|
Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of November 30,
2007, among the Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank,
Comerica Bank, Bank of Scotland, and Fortis Capital Corp. (Incorporated by reference to
Exhibit 10.27 of Form S-4 of the Registrant, Registration No. 333-148465) |
|
|
|
*10.28
|
|
Hagerman Gas Gathering System Joint Venture Agreement, dated as of January 16, 2007, among
the Registrant, Feagan Gathering Company and Capstone Oil and Gas Company, L.P. |
|
|
|
14
|
|
Code of Ethics (Incorporated by reference to Exhibit No. 14 of the Registrants Form 10-K
Report for the fiscal year ended December 31, 2003 and filed with the Securities and Exchange
Commission on March 22, 2004) |
|
|
|
*23.1
|
|
Consent of BDO Seidman, LLP |
|
|
|
*23.2
|
|
Consent of Cawley Gillespie & Associates Inc. Independent Petroleum Engineers |
|
|
|
*31.1
|
|
Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of
the Sarbanes Oxley Act of 2002. |
|
|
|
*31.2
|
|
Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of
the Sarbanes Oxley Act of 2002. |
|
|
|
*32.1
|
|
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes Oxley Act of 2002. |
|
|
|
*32.2
|
|
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes Oxley Act of 2002. |
(96)
PARALLEL PETROLEUM CORPORATION
Index to the Consolidated Financial Statements
|
|
|
|
|
Page |
|
|
F-2 |
|
|
|
Financial Statements: |
|
|
|
|
|
|
|
F-3 |
|
|
F-4 |
|
|
F-5 |
|
|
F-6 |
|
|
F-7 |
|
|
F-8 |
All schedules are omitted, as the required information is inapplicable or the information is
presented in the Consolidated Financial Statements or related notes.
F-1
Report of Independent Registered Public Accounting Firm
Board of Directors
Parallel Petroleum
Corporation Midland, Texas
We have audited the accompanying consolidated balance sheets of Parallel Petroleum Corporation as
of December 31, 2007 and 2006 and the related consolidated statements of operations, comprehensive
income (loss), stockholders equity, and cash flows for each of the three years in the period ended
December 31, 2007. These financial statements are the responsibility of the Companys management.
Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements, assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all
material respects, the financial position of Parallel Petroleum Corporation at December 31, 2007
and 2006, and the results of its operations and its cash flows for each of the three years in the
period ended December 31, 2007 in conformity with accounting principles generally accepted in the
United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), Parallel Petroleum Corporations internal control over financial reporting
as of December 31, 2007, based on criteria established in Internal Control Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated
February 20, 2008, expressed an unqualified opinion thereon.
BDO Seidman, LLP
Houston, Texas
February 20, 2008
F-2
PARALLEL PETROLEUM CORPORATION
Consolidated Balance Sheets
December 31, 2007 and 2006
(dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
Assets |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
7,816 |
|
|
$ |
5,910 |
|
|
|
|
|
|
|
|
|
|
Accounts receivable: |
|
|
|
|
|
|
|
|
Oil and natural gas sales |
|
|
20,499 |
|
|
|
18,605 |
|
Joint interest owners and other, net of allowance for doubtful account of $50 and $80 |
|
|
2,460 |
|
|
|
7,212 |
|
Affiliates |
|
|
3,970 |
|
|
|
3,335 |
|
|
|
|
|
|
|
|
|
|
|
26,929 |
|
|
|
29,152 |
|
Other current assets |
|
|
600 |
|
|
|
2,863 |
|
Deferred tax asset |
|
|
10,293 |
|
|
|
4,340 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
45,638 |
|
|
|
42,265 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, at cost: |
|
|
|
|
|
|
|
|
Oil and natural gas
properties, full cost method
(including $86,402 and $50,375
not subject to depletion) |
|
|
648,576 |
|
|
|
501,405 |
|
Other |
|
|
2,877 |
|
|
|
2,614 |
|
|
|
|
|
|
|
|
|
|
|
651,453 |
|
|
|
504,019 |
|
Less accumulated depreciation, depletion and amortization |
|
|
(145,482 |
) |
|
|
(115,513 |
) |
|
|
|
|
|
|
|
Net property and equipment |
|
|
505,971 |
|
|
|
388,506 |
|
Restricted cash |
|
|
78 |
|
|
|
325 |
|
Investment in pipelines and gathering system ventures |
|
|
8,638 |
|
|
|
6,454 |
|
Other assets, net of accumulated amortization of $1,425 and $760 |
|
|
2,768 |
|
|
|
5,268 |
|
|
|
|
|
|
|
|
|
|
$ |
563,093 |
|
|
$ |
442,818 |
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable and accrued
liabilities |
|
$ |
47,848 |
|
|
$ |
36,171 |
|
Asset retirement obligations |
|
|
598 |
|
|
|
701 |
|
Derivative obligations |
|
|
30,424 |
|
|
|
14,109 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
78,870 |
|
|
|
50,981 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revolving credit facility |
|
|
60,000 |
|
|
|
115,000 |
|
Term loan |
|
|
|
|
|
|
50,000 |
|
Senior notes (principal amount $150,000 in 2007) |
|
|
145,383 |
|
|
|
|
|
Asset retirement obligations |
|
|
4,339 |
|
|
|
4,362 |
|
Derivative obligations |
|
|
13,194 |
|
|
|
14,386 |
|
Deferred tax liability |
|
|
26,045 |
|
|
|
24,307 |
|
|
|
|
|
|
|
|
Total long-term liabilities |
|
|
248,961 |
|
|
|
208,055 |
|
|
|
|
|
|
|
|
Commitments and contingencies (Note 15) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders equity: |
|
|
|
|
|
|
|
|
Series A preferred stock
par value $0.10 per share,
authorized 50,000 shares |
|
|
|
|
|
|
|
|
Common stock par value $0.01 per share, authorized 60,000,000 shares,
issued and outstanding 41,252,644 and 37,547,010 |
|
|
412 |
|
|
|
375 |
|
Additional paid-in capital |
|
|
196,457 |
|
|
|
140,353 |
|
Retained earnings |
|
|
38,393 |
|
|
|
43,054 |
|
|
|
|
|
|
|
|
Total stockholders equity |
|
|
235,262 |
|
|
|
183,782 |
|
|
|
|
|
|
|
|
|
|
$ |
563,093 |
|
|
$ |
442,818 |
|
|
|
|
|
|
|
|
See accompanying Notes to Consolidated Financial Statements.
F-3
PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Operations
Years ended December 31, 2007, 2006 and 2005
(dollars in thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Oil and natural gas revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales |
|
$ |
116,031 |
|
|
$ |
97,025 |
|
|
$ |
66,150 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
|
|
22,200 |
|
|
|
16,819 |
|
|
|
9,947 |
|
Production taxes |
|
|
5,545 |
|
|
|
5,577 |
|
|
|
4,102 |
|
Production tax refund |
|
|
(1,209 |
) |
|
|
|
|
|
|
|
|
General and administrative |
|
|
10,415 |
|
|
|
9,523 |
|
|
|
6,712 |
|
Depreciation, depletion and amortization |
|
|
30,115 |
|
|
|
24,687 |
|
|
|
12,044 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
67,066 |
|
|
|
56,606 |
|
|
|
32,805 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
48,965 |
|
|
|
40,419 |
|
|
|
33,345 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense), net: |
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives not classified as hedges |
|
|
(36,776 |
) |
|
|
2,802 |
|
|
|
(31,669 |
) |
Gain (loss) on ineffective portion of hedges |
|
|
|
|
|
|
626 |
|
|
|
(137 |
) |
Interest and other income |
|
|
197 |
|
|
|
158 |
|
|
|
167 |
|
Interest expense |
|
|
(19,177 |
) |
|
|
(12,360 |
) |
|
|
(4,780 |
) |
Cost of debt retirement |
|
|
(760 |
) |
|
|
|
|
|
|
|
|
Other expense |
|
|
(118 |
) |
|
|
(189 |
) |
|
|
(102 |
) |
Equity in income (loss) of pipelines and gathering system ventures |
|
|
(311 |
) |
|
|
8,593 |
|
|
|
(89 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense), net |
|
|
(56,945 |
) |
|
|
(370 |
) |
|
|
(36,610 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes |
|
|
(7,980 |
) |
|
|
40,049 |
|
|
|
(3,265 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit (expense) |
|
|
3,319 |
|
|
|
(13,894 |
) |
|
|
1,676 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
|
(4,661 |
) |
|
|
26,155 |
|
|
|
(1,589 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative preferred stock dividend |
|
|
|
|
|
|
|
|
|
|
(271 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders |
|
$ |
(4,661 |
) |
|
$ |
26,155 |
|
|
$ |
(1,860 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(0.12 |
) |
|
$ |
0.73 |
|
|
$ |
(0.06 |
) |
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
(0.12 |
) |
|
$ |
0.71 |
|
|
$ |
(0.06 |
) |
|
|
|
|
|
|
|
|
|
|
See accompanying Notes to Consolidated Financial Statements.
F-4
Consolidated Statements of Stockholders Equity
Years ended December 31, 2007, 2006 and 2005
(amounts in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
Preferred stock |
|
|
Common stock |
|
|
Additional |
|
|
|
|
|
|
Other |
|
|
Total |
|
|
|
Number of |
|
|
|
|
|
|
Number of |
|
|
|
|
|
|
paid-in |
|
|
Retained |
|
|
Comprehensive |
|
|
stockholders |
|
|
|
shares |
|
|
Amount |
|
|
shares |
|
|
Amount |
|
|
capital |
|
|
earnings |
|
|
Loss |
|
|
equity |
|
Balance, January 1, 2005 |
|
|
950 |
|
|
$ |
95 |
|
|
|
25,439 |
|
|
$ |
254 |
|
|
$ |
48,328 |
|
|
$ |
18,759 |
|
|
$ |
(7,442 |
) |
|
|
59,994 |
|
Common stock issued, net of transaction costs |
|
|
|
|
|
|
|
|
|
|
5,750 |
|
|
|
58 |
|
|
|
27,686 |
|
|
|
|
|
|
|
|
|
|
|
27,744 |
|
Common stock issued for services |
|
|
|
|
|
|
|
|
|
|
12 |
|
|
|
|
|
|
|
99 |
|
|
|
|
|
|
|
|
|
|
|
99 |
|
Preferred stock converted |
|
|
(950 |
) |
|
|
(95 |
) |
|
|
2,714 |
|
|
|
27 |
|
|
|
68 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cashless exercise of warrants |
|
|
|
|
|
|
|
|
|
|
120 |
|
|
|
1 |
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Options exercised |
|
|
|
|
|
|
|
|
|
|
714 |
|
|
|
7 |
|
|
|
2,241 |
|
|
|
|
|
|
|
|
|
|
|
2,248 |
|
Stock option expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
278 |
|
|
|
|
|
|
|
|
|
|
|
278 |
|
Changes in fair value of cash flow hedges, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
999 |
|
|
|
999 |
|
Net loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,589 |
) |
|
|
|
|
|
|
(1,589 |
) |
Dividends on preferred stock ($0.60 per share) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(271 |
) |
|
|
|
|
|
|
(271 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, January 1, 2006 |
|
|
|
|
|
$ |
|
|
|
|
34,749 |
|
|
$ |
347 |
|
|
$ |
78,699 |
|
|
$ |
16,899 |
|
|
$ |
(6,443 |
) |
|
$ |
89,502 |
|
Common stock issued, net of transaction costs |
|
|
|
|
|
|
|
|
|
|
2,500 |
|
|
|
25 |
|
|
|
60,242 |
|
|
|
|
|
|
|
|
|
|
|
60,267 |
|
Common stock issued for services |
|
|
|
|
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
118 |
|
|
|
|
|
|
|
|
|
|
|
118 |
|
Cashless exercise of warrants |
|
|
|
|
|
|
|
|
|
|
117 |
|
|
|
1 |
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Options exercised |
|
|
|
|
|
|
|
|
|
|
176 |
|
|
|
2 |
|
|
|
764 |
|
|
|
|
|
|
|
|
|
|
|
766 |
|
Stock option expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
531 |
|
|
|
|
|
|
|
|
|
|
|
531 |
|
Changes in fair value of cash flow hedges, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,443 |
|
|
|
6,443 |
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26,155 |
|
|
|
|
|
|
|
26,155 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, January 1, 2007 |
|
|
|
|
|
$ |
|
|
|
|
37,547 |
|
|
$ |
375 |
|
|
$ |
140,353 |
|
|
$ |
43,054 |
|
|
$ |
|
|
|
$ |
183,782 |
|
Common stock issued, net of transaction costs |
|
|
|
|
|
|
|
|
|
|
3,000 |
|
|
|
30 |
|
|
|
52,492 |
|
|
|
|
|
|
|
|
|
|
|
52,522 |
|
Common stock issued for services |
|
|
|
|
|
|
|
|
|
|
4 |
|
|
|
|
|
|
|
96 |
|
|
|
|
|
|
|
|
|
|
|
96 |
|
Cashless exercise of warrants |
|
|
|
|
|
|
|
|
|
|
83 |
|
|
|
1 |
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Options exercised |
|
|
|
|
|
|
|
|
|
|
619 |
|
|
|
6 |
|
|
|
2,454 |
|
|
|
|
|
|
|
|
|
|
|
2,460 |
|
Stock option expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
247 |
|
|
|
|
|
|
|
|
|
|
|
247 |
|
Tax benefit of stock option exercise
in excess of compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
816 |
|
|
|
|
|
|
|
|
|
|
|
816 |
|
Net loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,661 |
) |
|
|
|
|
|
|
(4,661 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
December 31, 2007 |
|
|
|
|
|
$ |
|
|
|
|
41,253 |
|
|
$ |
412 |
|
|
$ |
196,457 |
|
|
$ |
38,393 |
|
|
$ |
|
|
|
$ |
235,262 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying Notes to Consolidated Financial Statements.
F-5
PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Cash Flows
Years ended December 31, 2007, 2006 and 2005
( dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(4,661 |
) |
|
$ |
26,155 |
|
|
$ |
(1,589 |
) |
Adjustments to reconcile net income (loss) to net cash
provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
30,115 |
|
|
|
24,687 |
|
|
|
12,044 |
|
Gain on sale of automobiles |
|
|
(30 |
) |
|
|
|
|
|
|
|
|
Accretion of asset retirement obligation |
|
|
324 |
|
|
|
248 |
|
|
|
112 |
|
Accretion of senior notes discount |
|
|
197 |
|
|
|
|
|
|
|
|
|
Deferred income tax (benefit) expense |
|
|
(3,319 |
) |
|
|
13,894 |
|
|
|
(1,676 |
) |
(Gain) loss on derivatives not classified as hedges |
|
|
36,776 |
|
|
|
(2,802 |
) |
|
|
31,669 |
|
(Gain) loss on ineffective portion of hedges |
|
|
|
|
|
|
(626 |
) |
|
|
137 |
|
Cost of debt retirement |
|
|
760 |
|
|
|
|
|
|
|
|
|
Common stock issued in lieu of cash for directors fees |
|
|
96 |
|
|
|
118 |
|
|
|
99 |
|
Stock option expense |
|
|
247 |
|
|
|
531 |
|
|
|
278 |
|
Equity (income) loss in pipelines and gathering system ventures |
|
|
311 |
|
|
|
(8,593 |
) |
|
|
89 |
|
Return on investment in pipelines and gathering system ventures |
|
|
287 |
|
|
|
9,000 |
|
|
|
|
|
Bad debt expense |
|
|
(30 |
) |
|
|
71 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Other assets, net |
|
|
379 |
|
|
|
1,567 |
|
|
|
(823 |
) |
Restricted cash |
|
|
247 |
|
|
|
(50 |
) |
|
|
(274 |
) |
Decrease (increase) in accounts receivable |
|
|
2,253 |
|
|
|
(15,151 |
) |
|
|
(7,034 |
) |
Decrease (increase) in other current assets |
|
|
1,070 |
|
|
|
(153 |
) |
|
|
(1,187 |
) |
Increase in accounts payable and accrued liabilities |
|
|
11,597 |
|
|
|
25,330 |
|
|
|
5,273 |
|
Federal tax deposit |
|
|
|
|
|
|
(40 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
76,619 |
|
|
|
74,186 |
|
|
|
37,118 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and natural gas properties |
|
|
(149,298 |
) |
|
|
(195,396 |
) |
|
|
(77,351 |
) |
Use of restricted cash for acquisition of oil and natural gas properties |
|
|
|
|
|
|
2,366 |
|
|
|
(79 |
) |
Proceeds from disposition of oil and natural gas properties and other property and equipment |
|
|
1,677 |
|
|
|
130 |
|
|
|
3,028 |
|
Additions to other property and equipment |
|
|
(379 |
) |
|
|
(210 |
) |
|
|
(342 |
) |
Settlements of derivative instruments |
|
|
(16,615 |
) |
|
|
(3,902 |
) |
|
|
(5,022 |
) |
Purchase of derivative instruments |
|
|
|
|
|
|
|
|
|
|
(2,363 |
) |
Investment in pipelines and gathering system ventures |
|
|
(2,782 |
) |
|
|
(11,260 |
) |
|
|
(2,820 |
) |
Return of investment in pipelines and gathering system ventures |
|
|
|
|
|
|
7,724 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(167,397 |
) |
|
|
(200,548 |
) |
|
|
(84,949 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings from bank line of credit |
|
|
92,000 |
|
|
|
117,000 |
|
|
|
45,714 |
|
Payments on bank line of credit |
|
|
(147,000 |
) |
|
|
(52,000 |
) |
|
|
(74,714 |
) |
Borrowings from term loan |
|
|
|
|
|
|
|
|
|
|
50,000 |
|
Payment on term loan |
|
|
(50,000 |
) |
|
|
|
|
|
|
|
|
Senior notes (principal amount $150,000 in 2007) |
|
|
145,186 |
|
|
|
|
|
|
|
|
|
Deferred financing costs |
|
|
(813 |
) |
|
|
(179 |
) |
|
|
(1,253 |
) |
Deferred debt offering |
|
|
(1,671 |
) |
|
|
|
|
|
|
|
|
Proceeds from exercise of stock options |
|
|
2,460 |
|
|
|
766 |
|
|
|
2,248 |
|
Proceeds (net) from common stock issued |
|
|
52,522 |
|
|
|
60,267 |
|
|
|
27,744 |
|
Payment of preferred stock dividend |
|
|
|
|
|
|
|
|
|
|
(271 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
92,684 |
|
|
|
125,854 |
|
|
|
49,468 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
1,906 |
|
|
|
(508 |
) |
|
|
1,637 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of year |
|
|
5,910 |
|
|
|
6,418 |
|
|
|
4,781 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year |
|
$ |
7,816 |
|
|
$ |
5,910 |
|
|
$ |
6,418 |
|
|
|
|
|
|
|
|
|
|
|
Non-cash financing and investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties asset retirement obligation |
|
$ |
(450 |
) |
|
$ |
2,320 |
|
|
$ |
251 |
|
Non-cash exchange of oil and natural gas properties: |
|
|
|
|
|
|
|
|
|
|
|
|
Properties received in exchange |
|
$ |
6,463 |
|
|
$ |
|
|
|
$ |
|
|
Properties delivered in exchange |
|
$ |
(5,495 |
) |
|
$ |
|
|
|
$ |
|
|
Other transactions: |
|
|
|
|
|
|
|
|
|
|
|
|
Interest paid |
|
$ |
13,096 |
|
|
$ |
12,255 |
|
|
$ |
5,192 |
|
See accompanying Notes to Consolidated Financial Statements.
F-6
PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Comprehensive Income (Loss)
Years ended December 31, 2007, 2006 and 2005
(dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Net income (loss) |
|
$ |
(4,661 |
) |
|
$ |
26,155 |
|
|
$ |
(1,589 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized losses on derivatives |
|
|
|
|
|
|
(1,648 |
) |
|
|
(10,980 |
) |
Reclassification adjustment for losses
on derivatives included in net income (loss) |
|
|
|
|
|
|
11,409 |
|
|
|
12,494 |
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of derivatives |
|
|
|
|
|
|
9,761 |
|
|
|
1,514 |
|
Income tax expense, deferred |
|
|
|
|
|
|
(3,318 |
) |
|
|
(515 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive income |
|
|
|
|
|
|
6,443 |
|
|
|
999 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income (loss) |
|
$ |
(4,661 |
) |
|
$ |
32,598 |
|
|
$ |
(590 |
) |
|
|
|
|
|
|
|
|
|
|
See accompanying Notes to Consolidated Financial Statements.
F-7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) |
|
Organization, Business and Summary of Significant Accounting Policies |
|
(a) |
|
Basis of Consolidation |
|
|
|
|
The accompanying financial statements present the consolidated accounts of Parallel
Petroleum Corporation, a Delaware Corporation, and its wholly owned subsidiaries, Parallel
L.P. and Parallel, L.L.C. (collectively the Company or Parallel) prior to their
dissolution and merger into Parallel on July 2, 2007. All significant inter-company
account balances and transactions have been eliminated. |
|
|
|
|
The Company accounts for its interests in oil and natural gas joint ventures and working
interests using the proportionate consolidation method. Under this method, the Company
records its proportionate share of assets, liabilities, revenues and expenses. |
|
(b) |
|
Nature of Operations |
|
|
|
|
The Companys focus is on the acquisition, development and exploitation of long-lived oil
and natural gas reserves and, to a lesser extent, exploration for new oil and natural gas
reserves. The Companys business activities are currently carried out primarily in Texas
and New Mexico. The Companys activities are focused in the Permian Basin of west Texas
and New Mexico, the Fort Worth Basin of north Texas and the onshore Gulf Coast area of
south Texas. The Company is actively evaluating, drilling and preparing to drill new
projects located in the Cotton Valley Reef trend of east Texas and the Uinta Basin of
Utah. |
|
(c) |
|
Concentration of Credit Risk |
|
|
|
|
Financial instruments that potentially expose the Company to concentrations of credit risk
consist primarily of unsecured accounts receivable from working interest owners and crude
oil and natural gas purchasers. A substantial portion of Parallels oil and natural gas
reserves are located in the Permian Basin and the Company may be disproportionally exposed
to the impact of delays or interruptions of production from these wells due to mechanical
problems, damages to the current producing reservoirs and significant governmental
regulation, including any curtailment of production or interruption of transportation of
oil or natural gas produced from the wells. |
|
(d) |
|
Property and Equipment |
|
|
|
|
Oil and natural gas properties: |
|
|
|
|
The Company uses the full cost method of accounting for its oil and natural gas producing
activities. Accordingly, all costs associated with acquisition, exploration, and
development of oil and natural gas reserves, including directly related overhead costs,
are capitalized. |
|
|
|
|
Management and service fees received under contractual arrangements, if any, are treated
as reimbursement of costs, offsetting the costs incurred to provide those services.
Specifically, the Company serves as operator of certain oil and natural gas properties in
which it owns an interest. Under operating agreements naming the Company as operator, the
Company is reimbursed for certain specified direct charges and overhead charges. Amounts
received in reimbursement for drilling activities are applied as a reduction to Parallels
capital costs, and amounts received in reimbursement for producing activities are applied
to reduce the Companys general and administrative expenses. |
|
|
|
|
Depletion is provided using the unit-of-production method based upon estimates of proved
oil and natural gas reserves with oil and natural gas production being converted to a
common unit of measure based upon their relative energy content. Investments in unproved
properties and major development projects
are not amortized until proved reserves associated with the projects can be determined or
until impairment occurs. If the results of an assessment indicate that the properties are
impaired, the amount of the impairment is added to the capitalized costs to be amortized.
Once the assessment of unproved properties is complete and when major development projects
are evaluated, the costs previously excluded from amortization are transferred to the full
cost pool and amortization begins. The amortizable base includes es-
|
F-8
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
timated future
development costs and where significant, dismantlement, restoration and abandonment costs,
net of estimated salvage value. |
|
|
|
|
In arriving at rates under the unit-of-production method, the quantities of recoverable
oil and natural gas reserves are established based on estimates made
by the Company's geologists and
engineers which require significant judgment as does the projection of future production
volumes and levels of future costs, including future development costs. In addition,
considerable judgment is necessary in determining when unproved properties become impaired
and in determining the existence of proved reserves once a well has been drilled. All of
these judgments may have significant impact on the calculation of depletion expense. There
have been no material changes in the methodology used by the Company in calculating
depletion of oil and gas properties under the full cost method during the three years
ended December 31, 2007. |
|
|
|
|
If the net investment in oil and natural gas properties in a cost center, net of related
deferred taxes, exceeds an amount equal to the sum of (1) the standardized measure of
discounted future net cash flows from proved reserves, as adjusted for estimated future
asset retirement costs (see Note 16) and (2) the lower of cost or fair market value of
properties in process of development and unexplored acreage, the excess is charged to
expense as additional depletion and is separately disclosed during the period to which
this excess occurs. The standardized measure is calculated using a 10% discount rate and
is based on unescalated prices in effect at period-end with effect given to the Companys
cash flow hedge positions. |
|
|
|
|
Sales of proved and unproved properties are accounted for as adjustments of capitalized
costs with no gain or loss recognized, unless such adjustments would significantly alter
the relationship between capitalized costs and proved oil and natural gas reserves, in
which case the gain or loss would be recognized in the statement of operations. |
Other Property and Equipment:
|
|
|
Maintenance and repairs are charged to operations. Renewals and betterments are
capitalized to the appropriate property and equipment accounts. |
|
|
|
|
Upon retirement or disposition of assets other than oil and natural gas properties, the
cost and related accumulated depreciation are removed from the accounts with the resulting
gains or losses, if any, recognized in the statement of operations. Depreciation of other
property and equipment is computed using the straight-line method based on the estimated
useful lives of the property and equipment. |
|
(e) |
|
Income Taxes |
|
|
|
|
The Company accounts for income taxes using the liability method. Under the liability
method, deferred tax assets and liabilities are recognized for the future tax consequences
attributable to differences between financial statement carrying amounts of existing
assets and liabilities and their respective tax bases. Deferred tax assets and liabilities
are measured using enacted tax rates expected to apply to taxable income in the years in
which those temporary differences are expected to be recovered or settled. Under the
liability method, the effect on previously recorded deferred tax assets and liabilities
resulting from a change in tax rates is recognized in earnings in the period in which the
change is enacted. |
|
|
|
|
The Company adopted the provisions of Financial Accounting Standards Board (FASB)
Interpretation No. 48, Accounting for Uncertainty in Income Taxes-an interpretation of
FASB Statement No. 109 (FIN 48), on January 1, 2007. FIN 48 clarifies the accounting
for uncertainty in income taxes recognized in an enterprises financial statements in
accordance with FASB Statement 109, Accounting for Income Taxes, and prescribes a
recognition threshold and measurement process for financial statement recognition and
measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also
provides guidance on derecognition, classification, interest and penalties, accounting in
interim periods, disclosure and transition. |
|
|
|
|
Based on its evaluation, the Company has concluded that there are no significant uncertain
tax positions requiring recognition in its financial statements. The Companys evaluation
was performed for the tax
|
F-9
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
years ended December 31, 2003, 2004, 2005 and 2006, the tax
years which remain subject to examination by major tax jurisdictions as of December 31,
2007. |
|
|
|
|
The Company may from time to time be assessed interest or penalties by major tax
jurisdictions, although any such assessments historically have been minimal and immaterial
to its financial results. In addition, should the Company determine that any of its tax
positions are uncertain it may record related interest and penalties that may be assessed.
Interest recorded, if any, will be charged to interest expense, and penalties recorded
will be charged to other expense in the Companys statement of operations. |
|
(f) |
|
Investments |
|
|
|
|
Investments in affiliated companies with a 20% to 50% ownership interest are accounted for
under the equity method and, accordingly, net income includes the Companys proportionate
share of their income or loss. In addition, the Company has an investment in a joint
venture which is accounted for by the equity method because the Company does not have
effective control or voting interest although the Company owns approximately 76 1/2% of
the joint venture economic interest. |
|
|
(g) |
|
Stock-Based Compensation |
|
|
|
|
Parallel accounts for its stock based compensation using the prospective method under
Statement of Financial Accounting Standards No. 123 (SFAS 123). Under this method, the
fair values of all options granted since 2003 have been reflected as compensation expense
over the periods in which the services are rendered. |
|
|
|
|
Parallel adopted SFAS 123(R) effective January 1, 2006, applying the modified prospective
method, whereby compensation cost associated with the unvested portion of awards granted
during the period of June 2001 to December 2002 were recognized over the remaining vesting
period. Under this method, prior periods were not revised for comparative purposes. No
options that were granted prior to June 2001 remained unvested at January 1, 2006. |
|
|
(h) |
|
Environmental Expenditures |
|
|
|
|
The Company is subject to extensive federal, state and local environmental laws and
regulations. These laws regulate the discharge of materials into the environment and may
require the Company to remove or mitigate the environmental effects of the disposal or
release of petroleum or chemical substances at various sites. Environmental expenditures
are expensed or capitalized depending on their future economic benefit. Expenditures that
relate to an existing condition caused by past operations and that have no future economic
benefits are expensed. |
|
|
|
|
Liabilities for expenditures of a noncapital nature are recorded when environmental
assessment and or remediation is probable, and the costs can be reasonably estimated. Such
liabilities are generally undiscounted unless the timing of cash payments for the
liability or component are fixed or reliably determinable. |
|
|
(i) |
|
Earnings Per Share |
|
|
|
|
Basic earnings per share excludes any dilutive effects of options, warrants and
convertible securities and is computed by dividing income available to common stockholders
by the weighted average number of common shares outstanding for the period. Diluted
earnings per share are computed similar to basic earnings per share; however, diluted
earnings per share reflect the assumed conversion of all potentially dilutive securities. |
F-10
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table provides the computation of basic and diluted earnings per share for
the year ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
($ in thousands, except per share data) |
|
Basic EPS Comp utation: |
|
|
|
|
|
|
|
|
|
|
|
|
Numerator |
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(4,661 |
) |
|
$ |
26,155 |
|
|
$ |
(1,589 |
) |
Preferred stock dividend |
|
|
|
|
|
|
|
|
|
|
(271 |
) |
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders |
|
|
(4,661 |
) |
|
|
26,155 |
|
|
|
(1,860 |
) |
|
|
|
|
|
|
|
|
|
|
Denominator |
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding |
|
|
38,120 |
|
|
|
35,888 |
|
|
|
32,253 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) p er share |
|
$ |
(0.12 |
) |
|
$ |
0.73 |
|
|
$ |
(0.06 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS Comp utation: |
|
|
|
|
|
|
|
|
|
|
|
|
Numerator |
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(4,661 |
) |
|
$ |
26,155 |
|
|
$ |
(1,589 |
) |
Preferred stock dividend |
|
|
|
|
|
|
|
|
|
|
(271 |
) |
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders |
|
$ |
(4,661 |
) |
|
$ |
26,155 |
|
|
$ |
(1,860 |
) |
|
|
|
|
|
|
|
|
|
|
Denominator |
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding |
|
|
38,120 |
|
|
|
35,888 |
|
|
|
32,253 |
|
Employee stock options |
|
|
|
|
|
|
599 |
|
|
|
|
|
Warrants |
|
|
|
|
|
|
269 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares for diluted
earnings per share assuming conversion |
|
|
38,120 |
|
|
|
36,756 |
|
|
|
32,253 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) p er share |
|
$ |
(0.12 |
) |
|
$ |
0.71 |
|
|
$ |
(0.06 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
For the year ended December 31, 2007, the effects of all potentially dilutive securities
(including options and warrants) were excluded from the computation of diluted earnings
per share because the Company had a net loss and, therefore, the effect would have been
anti-dilutive. Approximately 878,000 options and warrants were excluded from the
computation of diluted earnings per share in 2007. For the year ended December 31, 2005,
the effects of all potentially dilutive securities (including options, warrants and the
if converted effects of convertible preferred stock) were excluded from the computation
of diluted earnings per share because the Company had a net loss and, therefore, the
effect would have been antidilutive. Approximately 1.7 million options, warrants and the
if converted effects of convertible preferred stock were excluded from the computation
of diluted earnings per share in 2005. |
|
(j) |
|
Use of Estimates in the Preparation of Consolidated Financial Statements |
|
|
|
|
Preparation of the accompanying Consolidated Financial Statements in conformity with
accounting principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the reported amounts of assets
and liabilities and disclosure of contingent assets and liabilities at the date of the
Consolidated Financial Statements and the reported amounts of revenues and expenses during
the reporting period. The oil and natural gas reserve estimates, and the related future
net cash flows derived from those reserves, are used in the determination of depletion
expense and the full-cost ceiling test and are inherently imprecise. Actual results could
differ from those estimates. |
|
|
(k) |
|
Cash Equivalents |
|
|
|
|
For purposes of the statements of cash flows, the Company considers all demand deposits,
money market accounts and certificates of deposit purchased with an original maturity of
three months or less to be cash equivalents. |
F-11
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
(l) |
|
Restricted Cash |
|
|
|
|
Restricted cash as of December 31, 2007, includes $50,000 placed in a certificate of
deposit for a Letter of Credit with the State of New Mexico and $25,000 placed in a
certificate of deposit to be held as a Statewide Bond provided under the New Mexico
Surface Owners Protection Act for benefit of surface owners affected. Restricted cash as
of December 31, 2006, includes $50,000 placed in a certificate of deposit for a Letter of
Credit with the State of New Mexico and approximately $275,000 placed in a certificate of
deposit for a drilling bond. |
|
|
(m) |
|
Reclassifications |
|
|
|
|
Certain reclassifications have been made to prior years amounts to conform with current
year presentation. |
|
|
(n) |
|
Derivative Financial Instruments |
|
|
|
|
Derivative financial instruments, utilized to manage or reduce commodity price risk
related to the Companys production and interest rate risk related to the Companys
long-term debt, are accounted for under the provisions of SFAS No. 133, Accounting for
Derivative Instruments and for Hedging Activities", and related interpretations and
amendments. Under this Statement, derivatives are carried on the balance sheet at fair
value. If the derivative is designated as a fair value hedge, the changes in the fair
value of the derivative and of the hedged item attributable to the hedged risk are
recognized in earnings. If the derivative is designated as a cash flow hedge, the
effective portions of changes in the fair value of the derivative are recorded in other
comprehensive income (OCI) and are recognized in the statement of operations when the
hedged item affects earnings. Ineffective portions of changes in the fair value of cash
flow hedges are also recognized in other expense. If the derivative is not designated as
a hedge, changes in the fair value are recognized in other expense. |
|
|
(o) |
|
Revenue Recognition |
|
|
|
|
Oil and natural gas revenues are recorded using the sales method, whereby the Company
recognizes oil and natural gas revenue based on the amount of oil and natural gas sold to
purchasers. For the period ended December 31, 2007, 2006 and 2005, the Company did not
have any significant oil or natural gas imbalances. The Company does not recognize
revenues until they are realized or realizable and earned. Revenues are considered
realized or realizable and earned when: (i) persuasive evidence of an arrangement exists;
(ii) delivery has occurred or services have been rendered; (iii) the sellers price to the
buyer is fixed or determinable; and, (iv) collectibility is reasonably assured. |
|
|
|
|
The following summarizes revenue for each of the three years ended December 31 by product
sold. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenue |
|
$ |
69,315 |
|
|
$ |
68,076 |
|
|
$ |
47,800 |
|
Effects of oil hedges |
|
|
|
|
|
|
(11,512 |
) |
|
|
(12,139 |
) |
Natural gas revenue |
|
|
46,716 |
|
|
|
40,461 |
|
|
|
30,690 |
|
Effects of natural gas hedges |
|
|
|
|
|
|
|
|
|
|
(201 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
116,031 |
|
|
$ |
97,025 |
|
|
$ |
66,150 |
|
|
|
|
|
|
|
|
|
|
|
|
(p) |
|
Recent Accounting Pronouncements |
|
|
|
|
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157,
Fair Value Measurements (FAS 157). FAS 157 defines fair value as used in numerous
accounting pronounce-
|
F-12
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
ments, establishes a framework for measuring fair value in accordance
with generally accepted accounting principles and expands disclosure requirements related
to the use of fair value measures in financial statements. FAS 157 will be effective for the Companys financial statements for the
fiscal year beginning January 1, 2008; however, earlier application is encouraged. The
Company is currently evaluating the impact that adoption might have on its financial
position or results of operations, although the Company does not expect any impact to be
significant. |
|
|
|
|
In February 2007, the FASB issued SFAS 159, The Fair Value Option for Financial Assets
and Financial Liabilities, Including an Amendment of FASB Statement No. 115, (FAS 159)
which will become effective on January 1, 2008. FAS 159 permits entities to measure
eligible financial assets, financial liabilities and firm commitments at fair value, on an
instrument-by-instrument basis, that are otherwise not permitted to be accounted for at
fair value under other generally accepted accounting principles. The fair value
measurement election is irrevocable and subsequent changes in fair value must be recorded
in earnings. The Company will adopt this statement in the first quarter of 2008 and the
Company does not expect to elect the fair value option for any eligible financial
instruments and other items. |
|
|
|
|
In April 2007, the FASB issued FASB Staff Position FIN 39-1, Amendment of FASB
Interpretation No. 39 (FSP FIN 39-1). FSP FIN 39-1 clarifies that a reporting entity
that is party to a master netting arrangement can offset fair value amounts recognized for
the right to reclaim cash collateral (a receivable) or the obligation to return cash
collateral (a payable) against fair value amounts recognized for derivative instruments
that have been offset under the same master netting arrangement. FSP FIN 39-1 is effective
for financial statements issued for fiscal years beginning after November 15, 2007.
Adoption of FSP FIN 39-1 is not expected to have a material impact on the Companys
consolidated financial statements. |
|
|
|
|
In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations
(SFAS 141(R)), which replaces FASB Statement No. 141. SFAS 141(R) establishes principles
and requirements for how an acquirer recognizes and measures in its financial statements
the identifiable assets acquired, the liabilities assumed, any non- controlling interest
in the acquiree and the goodwill acquired. The Statement also establishes disclosure
requirements that will enable users to evaluate the nature and financial effects of the
business combination. SFAS 141(R) is effective for acquisitions that occur in an entitys
fiscal year that begins after December 15, 2008, which will be the companys fiscal year
2009. The impact, if any, will depend on the nature and size of business combinations the
Company consummates after the effective date. |
|
|
|
|
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated
Financial Statementsan amendment of ARB No. 51 (SFAS 160). SFAS 160 requires that
accounting and reporting for minority interests will be recharacterized as noncontrolling
interests and classified as a component of equity. SFAS 160 also establishes reporting
requirements that provide sufficient disclosures that clearly identify and distinguish
between the interests of the parent and the interests of the noncontrolling owners. SFAS
160 applies to all entities that prepare consolidated financial statements, except
not-for-profit organizations, but will affect only those entities that have an outstanding
noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary.
This statement is effective as of the beginning of an entitys first fiscal year beginning
after December 15, 2008, which will be the companys fiscal year 2009. Based upon the
December 1, 2007 balance sheet, the statement would have no impact. |
(2) |
|
Fair Value of Financial Instruments |
|
|
|
The carrying amount of cash, accounts receivable, accounts payable, and accrued liabilities
approximates fair value because of the short maturity of these instruments. |
|
|
|
The carrying amount of long-term debt outstanding under the
Company's revolving credit facility in 2007
and 2006 and its term loan in 2006 approximated fair value because the Companys borrowing
rate on these financial instruments is based on a variable market rate of interest.
|
F-13
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
The carrying value of the Companys 10.25% senior notes at December 31, 2007 is approximately $145.4
million and their estimated fair value is approximately $150.0 million. Fair value is
estimated based on market trades at or near December 31, 2007. |
|
|
|
The Company also has derivative instruments which are described in Footnote 6. |
(3) |
|
Oil and Natural Gas Properties |
|
|
|
The following table reflects capitalized costs related to the oil and natural gas properties
as of December 31: |
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
Proved properties |
|
$ |
562,174 |
|
|
$ |
451,030 |
|
Unproved properties, not subject to depletion |
|
|
86,402 |
|
|
|
50,375 |
|
|
|
|
|
|
|
|
|
|
|
648,576 |
|
|
|
501,405 |
|
Accumulated depletion |
|
|
(143,264 |
) |
|
|
(113,467 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
505,312 |
|
|
$ |
387,938 |
|
|
|
|
|
|
|
|
|
|
The following table reflects, by category of cost, amounts excluded from the depletion base as
of December 31, 2007: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prepaid |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and |
|
|
|
|
|
|
Leasehold |
|
|
Geological and |
|
|
Work-in- |
|
|
|
|
Year Incurred |
|
Costs |
|
|
Geophysical |
|
|
Progress |
|
|
Total |
|
| |
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
$ |
34,558 |
|
|
$ |
2,105 |
|
|
$ |
8,942 |
|
|
$ |
45,605 |
|
2006 |
|
|
26,314 |
|
|
|
2,942 |
|
|
|
|
|
|
|
29,256 |
|
2005 |
|
|
6,256 |
|
|
|
675 |
|
|
|
|
|
|
|
6,931 |
|
Prior |
|
|
3,575 |
|
|
|
1,035 |
|
|
|
|
|
|
|
4,610 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
70,703 |
|
|
$ |
6,757 |
|
|
$ |
8,942 |
|
|
$ |
86,402 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2007 and 2006, unevaluated costs of approximately $86.4 million and $50.4
million were excluded from the depletion base. These costs consist primarily of acreage
acquisition, related geological and geophysical costs, prepaid drilling costs and
work-in-progress. The majority of these costs relate to the Companys New Mexico, Utah and
Barnett Shale leasehold positions. The Company transfers these costs to the full cost pool as
wells are drilled or as proven well locations are identified. The timing of these transfers
is highly dependent on the Companys future drilling program. |
|
|
|
Certain directly identifiable internal costs of property acquisition, exploration, and
development activities are capitalized. Such costs capitalized in 2007, 2006 and 2005 totaled
approximately $1.9 million, $2.3 million and $1.5 million, respectively, including $394,000,
$620,000 and $180,000 of capitalized interest for the year ended December 31, 2007, 2006 and
2005, respectively. |
|
|
|
Depletion per equivalent unit of production (BOE) was $13.02, $10.88 and $7.61 for 2007, 2006
and 2005, respectively. |
F-14
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
The following table reflects costs incurred in oil and natural gas property acquisition,
exploration, and development activities for each of the years in the three year period ended
December 31: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved property acquisition costs |
|
$ |
|
|
|
$ |
27,370 |
|
|
$ |
23,763 |
|
Unproved property acquisitions costs |
|
|
36,750 |
|
|
|
30,058 |
|
|
|
11,743 |
|
Exploration costs |
|
|
55,827 |
|
|
|
71,003 |
|
|
|
15,455 |
|
Development costs |
|
|
61,766 |
|
|
|
69,285 |
|
|
|
26,640 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
154,343 |
|
|
$ |
197,716 |
|
|
$ |
77,601 |
|
|
|
|
|
|
|
|
|
|
|
|
|
In November 2005, Parallel purchased producing and undeveloped oil and natural gas properties
in the Harris San Andres Field located in Andrews and Gaines counties, Texas. The net purchase
price was approximately $20.8 million. In January, 2006, Parallel acquired additional interest
in these properties for a net purchase price of approximately $23.4 million, including
adjustments. The 2006 purchase was made utilizing Parallels restricted cash and revolving
credit facility. |
|
|
|
In March 2006, Parallel purchased additional interests in the Barnett Shale Gas Project
located in Tarrant County, Texas. The additional interests were acquired from five
unaffiliated parties for a total cash purchase price of approximately $5.5 million. In April
2006, Parallel acquired an additional interest in the Barnett Shale Gas Project located in
Tarrant County, Texas from one other unaffiliated third party for approximately $570,000. |
|
|
|
The following table presents unaudited, pro forma operating results as if these property
purchases had been made at the beginning of each period shown. The pro forma results have been
prepared for comparative purposes only. They are not intended to represent what actual results
would have been if the acquisitions had been made on those dates and these pro forma amounts
are not indicative of future results. |
|
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended |
|
|
December 31, |
|
|
Pro Forma |
|
Pro Forma |
|
|
2006 |
|
2005 |
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
Oil and gas revenue |
|
$ |
97,500 |
|
|
$ |
74,270 |
|
Operating income |
|
$ |
40,738 |
|
|
$ |
38,800 |
|
Net income available
to common stockholders |
|
$ |
26,291 |
|
|
$ |
(732 |
) |
|
|
|
|
|
|
|
|
|
Net income per common share: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.73 |
|
|
$ |
(0.02 |
) |
Diluted |
|
$ |
0.72 |
|
|
$ |
(0.02 |
) |
F-15
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(4) |
|
Other Assets |
|
|
|
Below are the components of other assets as of December 31, 2007 and 2006: |
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
Bank fees, net of accumulated amortization |
|
$ |
1,185 |
|
|
$ |
1,361 |
|
Prepaid drilling |
|
|
|
|
|
|
54 |
|
Fair value of derivative contracts |
|
|
|
|
|
|
3,845 |
|
Deferred debt offering costs |
|
|
1,575 |
|
|
|
|
|
Other |
|
|
8 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
$ |
2,768 |
|
|
$ |
5,268 |
|
|
|
|
|
|
|
|
(5) |
|
Asset Retirement Obligation |
|
|
|
On January 1, 2003, the Company adopted SFAS 143, Accounting for Asset Retirement
Obligations". SFAS 143 requires companies to recognize a liability for the present value of
all legal obligations associated with the retirement of tangible long-lived assets and to
capitalize an equal amount as part of the cost of the related oil and natural gas properties. |
|
|
|
The following table summarizes the Company's asset retirement obligation transactions for the years
ended December 31: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
($ in thousands) |
|
Beginning asset retirement obligation |
|
$ |
5,063 |
|
|
$ |
2,495 |
|
|
$ |
2,132 |
|
Additions related to new properties |
|
|
257 |
|
|
|
406 |
|
|
|
370 |
|
Revisions in estimated cash flows |
|
|
(342 |
) |
|
|
1,979 |
|
|
|
(3 |
) |
Deletions related to property disposals |
|
|
(365 |
) |
|
|
(65 |
) |
|
|
(116 |
) |
Accretion expense |
|
|
324 |
|
|
|
248 |
|
|
|
112 |
|
|
|
|
|
|
|
|
|
|
|
Ending asset retirement obligation |
|
$ |
4,937 |
|
|
$ |
5,063 |
|
|
$ |
2,495 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion expense is recognized as a component of lease operating expense. |
(6) |
|
Derivative Instruments |
|
|
|
The Company enters into derivative contracts to provide a measure of stability in the cash
flows associated with the Companys oil and natural gas production and interest rate payments
and to manage exposure to commodity price and interest rate risk. The Companys objective is
to lock in a range of oil and natural gas prices and to limit variability in its cash interest
payments. In addition, the Companys revolving credit facility requires the Company to
maintain derivative financial instruments which limit the Companys exposure to fluctuating
commodity prices covering at least 50% of the Companys estimated monthly production of oil
and natural gas extending 24 months into the future. |
|
|
|
The Company designated all of its interest rate swaps, commodity collars and commodity swaps
entered into in 2002 and 2003 as cash flow hedges (hedges). The effective portion of the
unrealized gain or loss on cash flow hedges is recorded in other comprehensive income (loss)
until the forecasted transaction occurs. During the term of a cash flow hedge, the effective
portion of the change in the fair value of the derivatives is recorded in stockholders equity
as other comprehensive income (loss) and then transferred to oil and natural gas revenues when
the production is sold and interest expense as the interest accrues. Ineffective portions of |
F-16
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
hedges (changes in fair value resulting from changes in realized prices that do not match the
changes in the hedge or reference price) are recognized in other expense as they occur. |
|
|
|
As of December 31, 2005, the Company had recorded unrealized losses of $9.8 million,
respectively, related to its derivative instruments designated as hedges, which represented
the estimated aggregate fair values of
the Companys open hedge contracts as of that date. All derivative instruments previously
designated as cash flow hedges had been settled prior to December 31, 2006. |
|
|
|
Derivative contracts not designated as hedges are marked to market at each period end and
the increases or decreases in fair values are recorded to earnings. No derivative instruments
entered into subsequent to June 30, 2004 have been designated as cash flow hedges. |
|
|
|
The Company is exposed to credit risk in the event of nonperformance by the
counterparties to these contracts, BNP Paribas and Citibank, N.A. The Company periodically
assesses their credit worthiness to mitigate this credit risk. |
|
|
|
Interest Rate Sensitivity |
|
|
|
Under the Companys revolving credit facility, the Company may elect an interest rate based
upon the agent banks base lending rate or the LIBOR rate, plus a margin ranging from 2.00% to
2.50% per annum, depending on the Companys borrowing base usage. The interest rate the
Company is required to pay, including the applicable margin, may never be less than 5.00%.
Under the Companys second lien term loan facility, the Company had the option to elect an
interest rate based upon an alternate base rate, or the LIBOR rate, plus a margin of 4.50%. |
|
|
|
Interest Rate Swaps. The Company has entered into interest rate swaps with BNP Paribas
and Citibank, N.A. (the counterparties) which are intended to have the effect of converting
the variable rate interest payments to be made on the Companys revolving credit agreement to
fixed interest rates for the periods covered by the swaps. Under terms of these swap
contracts, in periods during which the fixed interest rate stated in the swap contract exceeds
the variable rate (which is based on the 90 day LIBOR rate), the Company pays to the
counterparties an amount determined by applying this excess fixed rate to the notional amount
of the contract. In periods when the variable rate exceeds the fixed rate stated in the swap
contracts, the counterparties pay an amount to the Company determined by applying the excess
of the variable rate over the stated fixed rate to the notional amount of the contract. |
|
|
|
The Company completed a fixed interest rate swap contract with BNP Paribas, based on the
90-day LIBOR rates at the time of the contract. This interest rate swap was treated as a cash
flow hedge as defined by SFAS 133. This interest rate swap was on
$10.0 million of the Company's
variable rate debt for all of 2006. As of December 31, 2006, this contract had expired. |
|
|
|
The Company has historically employed interest rate swap contracts with BNP Paribas and
Citibank, N.A. exchanging 90-day LIBOR rates for a fixed interest rate. These contracts are
accounted for by mark to market accounting as prescribed
in SFAS 133. The Company has historically
viewed these contracts as additional protection against future interest rate volatility. As a
result of the issuance of senior notes and common stock in 2007, the
Company's indebtedness under the
Revolving Credit Facility has been reduced below the nominal amounts currently covered by
these swap contracts. Under a covenant contained in the Company's Revolving Credit Facility, these swap
contracts for nominal amounts in excess of the Company's outstanding floating rate indebtedness are
considered speculative and are, therefore, not allowed. This covenant
has been waived by the Company's
lenders through the end of 2008. |
F-17
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
The table below recaps the nature of these interest rate swaps and the fair market value of
these contracts as of December 31, 2007. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
Notional |
|
|
Weighted Average |
|
|
Fair Market Value |
|
Period of Time |
|
Amounts |
|
|
Fixed Interest Rates |
|
|
at December 31, 2007 |
|
|
|
($ in millions) |
|
|
|
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1, 2008 thru December 31, 2008 |
|
$ |
100 |
|
|
|
4.86 |
% |
|
$ |
(800 |
) |
January 1, 2009 thru December 31, 2009 |
|
$ |
50 |
|
|
|
5.06 |
% |
|
|
(754 |
) |
January 1, 2010 thru October 31, 2010 |
|
$ |
50 |
|
|
|
5.15 |
% |
|
|
(441 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
$ |
(1,995 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Price Sensitivity |
|
|
Collars. Collars are contracts which combine both a put option or floor and a call
option or ceiling. These contracts may or may not involve payment or receipt of cash at
inception, depending on ceiling and floor pricing. |
|
|
|
A summary of the Companys collar positions at December 31, 2007 is as follows: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
Barrles of |
|
NYMEX Oil Prices |
|
Fair Market |
Period of Time |
|
Oil |
|
Floor |
|
Cap |
|
Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1, 2008 thru December 31, 2008 |
|
|
347,700 |
|
|
$ |
63.42 |
|
|
$ |
83.86 |
|
|
$ |
(4,003 |
) |
January 1, 2009 thru December 31, 2009 |
|
|
620,500 |
|
|
$ |
63.53 |
|
|
$ |
80.21 |
|
|
|
(6,846 |
) |
January 1, 2010 thru October 31, 2010 |
|
|
486,400 |
|
|
$ |
63.44 |
|
|
$ |
78.26 |
|
|
|
(5,153 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
M M Btu of |
|
WAHA Gas Prices |
|
|
|
|
|
|
Natural Gas |
|
Floor |
|
Cap |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1, 2008 thru M arch 31, 2008 |
|
|
546,000 |
|
|
$ |
6.50 |
|
|
$ |
9.50 |
|
|
|
87 |
|
April 1, 2008 thru December 31, 2008 |
|
|
1,375,000 |
|
|
$ |
6.75 |
|
|
$ |
8.40 |
|
|
|
63 |
|
Total Fair M arket Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(15,852 |
) |
|
|
Commodity Swaps. Generally, swaps are an agreement to buy or sell a specified
commodity for delivery in the future, at an agreed fixed price. Swap transactions convert a
floating or market price into a fixed price. For any particular swap transaction, the
counterparty is required to make a payment to the Company if the reference price for any
settlement period is less than the swap or fixed price for such contract, and the Company is
required to make a payment to the counterparty if the reference price for any settlement
period is greater than the swap or fixed price for such contract. |
F-18
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
The Company has entered into oil and natural gas swap contracts with BNP Paribas. A recap for
the period of time, number of barrels, and weighted average swap prices are as follows: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
Barrels of |
|
NYMEX Oil |
|
Fair Market |
Period of Time |
|
Oil |
|
Swap Price |
|
Value |
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1, 2008 thru December 31, 2008
|
|
|
439,200 |
|
|
$ |
33.37 |
|
|
$ |
(25,621 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
(7) |
|
Equity Investment and Property Acquisitions |
|
|
|
Prior to 2006, the Company had three separate partnership investments to construct pipeline
systems which gather natural gas, primarily on its leaseholds in the Barnett Shale area. The
partnership investments included West Fork Pipeline Company I, L.P., West Fork Pipeline
Company II, L.P. and West Fork Pipeline Company V, L.P. These investments were recorded as
equity method investments in the accompanying consolidated balance sheet. |
|
|
|
In the fourth quarter of 2006, substantially all of the assets of West Fork Pipeline I and
West Fork Pipeline V were sold. The Company received distributions of $16.0 million and
$683,000, respectively, as a result of these asset sales. The total of these distributions,
approximately $16.7 million, is reported in the accompanying statement of cash flows for 2006
in Cash flows from operating activities as Return on investment in pipelines and gathering
systems ventures in the amount of $9.0 million, which represents the excess of distributions
received over the Company's cash investments in these ventures, and in Cash flows from investing
activities as Return of investment in pipelines and gathering systems ventures in the
amount of $7.7 million, representing the return through
distribution of the Company's previous cash
investments in the two joint ventures. |
|
|
|
The Company has invested $328,000 in West Fork Pipeline II through 2007. West Fork Pipeline II
is currently acquiring the necessary easements and permits to begin transmission of natural
gas. |
|
|
|
The Company has invested $9.6 million in the Hagerman Gas Gathering System Joint Venture
(Hagerman) to construct pipelines on certain of its leaseholds in New Mexico. In late
September 2006, transmission of natural gas commenced through the first phase of the system.
The Hagerman Gas Gathering System is currently being extended to additional productive areas.
The Company anticipates additional investments in Hagerman during 2008. |
|
|
|
The Companys investment percentage in each of these ventures was as follows: |
|
|
|
|
|
West Fork Pipeline Company II, L.P. |
|
|
23.25848 |
% |
Hagerman Gas Gathering System |
|
|
76.50000 |
% |
|
|
The Companys investment in Hagerman is accounted for by the equity method because the Company
does not have voting control. All significant actions taken by Hagerman must be approved by
the Company plus one of the two other equity owners. Consequently, the remaining equity
owners can prevent voting control by the Company. |
F-19
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
The Companys equity investments for the periods indicated consisted of the following: |
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
West Fork Pipeline Company II, L.P. |
|
$ |
312 |
|
|
$ |
280 |
|
Hagerman Gas Gathering System |
|
|
8,326 |
|
|
|
6,174 |
|
|
|
|
|
|
|
|
|
|
$ |
8,638 |
|
|
$ |
6,454 |
|
|
|
|
|
|
|
|
|
|
The Companys earnings from equity investments for the periods indicated were as follows: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
West Fork Pipeline Company I, L.P.(1) |
|
$ |
161 |
|
|
$ |
9,286 |
|
|
$ |
(83 |
) |
West Fork Pipeline Company II, L.P. |
|
|
3 |
|
|
|
(50 |
) |
|
|
(5 |
) |
West Fork Pipeline Company V, L.P.(2) |
|
|
126 |
|
|
|
(147 |
) |
|
|
(1 |
) |
Hagerman Gas Gathering System |
|
|
(601 |
) |
|
|
(496 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(311 |
) |
|
$ |
8,593 |
|
|
$ |
(89 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Included in the Companys earnings for 2007 is its
proportionate share of a final cash disbursement of $161,000
received in the fourth quarter of 2007. Included in the
Companys earnings for 2006 is its proportionate gain in the
sale of the partnership assets of approximately $9.1 million. |
|
(2) |
|
Included in the Companys earnings for 2007 is its
proportionate share of a final cash disbursement of $126,000
received in the fourth quarter of 2007. Included in the
Companys earnings for 2006 is its proportionate loss in the
sale of the partnership assets of approximately $90,000. |
|
|
Summarized combined financial information for the Company's equity investments (listed above) is
reported below. Amounts represent 100% of the investees financial information: |
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
|
($ in thousands) |
|
Balance Sheet |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
62 |
|
|
$ |
94 |
|
Account receivables affiliates |
|
|
696 |
|
|
|
1,314 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
758 |
|
|
|
1,408 |
|
Plan and pipeline costs |
|
|
10,917 |
|
|
|
8,351 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
11,675 |
|
|
$ |
9,759 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
50 |
|
|
$ |
15 |
|
Accounts payable affiliates |
|
|
523 |
|
|
|
1,314 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
573 |
|
|
|
1,329 |
|
Partner capital |
|
|
11,102 |
|
|
|
8,430 |
|
|
|
|
|
|
|
|
Owners equity |
|
$ |
11,675 |
|
|
$ |
9,759 |
|
|
|
|
|
|
|
|
F-20
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
($ in thousands) |
|
Income
Statement |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
847 |
|
|
$ |
2,402 |
|
|
$ |
627 |
|
Costs and expenses |
|
|
(1,654 |
) |
|
|
(2,597 |
) |
|
|
(699 |
) |
Gain/loss on sale of assets |
|
|
782 |
|
|
|
23,780 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(25 |
) |
|
$ |
23,585 |
|
|
$ |
(72 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2007 and 2006, Hagerman had accounts receivable due from joint venturers of
approximately $0.5 million and $1.3 million, respectively, for operating and pipeline
construction related capital contributions. Parallel advanced funds in these amounts to
Hagerman to meet capital needs until payment on account is received from the other joint
venturers. |
|
(8) |
|
Credit Arrangements |
|
|
|
In the past, the Company maintained two separate credit facilities. The Companys Third
Amended and Restated Credit Agreement (or the Revolving Credit Agreement), dated as of
December 23, 2005, with a group of bank lenders provides a revolving line of credit having a
borrowing base limitation of $200.0 million at December 31, 2007. The total amount that the
Company can borrow and have outstanding at any one time is limited to the lesser of $350.0
million or the borrowing base established by the lenders. At December 31, 2007, the principal
amount outstanding under the Companys revolving credit facility was $60.0 million, and
$445,000 was reserved for the Companys letters of credit. The second credit facility (or the
Second Lien Agreement) was a five year term loan facility provided to the Company under a
Second Lien Term Loan Agreement, dated November 15, 2005, with a group of banks and other
lenders. The Second Lien Term Loan Agreement was paid off and terminated on July 31, 2007,
with the Companys payment to the lenders of $50.2 million, including interest. This payment
was made with proceeds from the Companys sale of unsecured senior notes, or senior notes. |
|
|
|
On July 31, 2007, the Company completed a private offering of unsecured senior notes in the
principal amount of $150.0 million. |
|
|
|
The credit facilities have varying interest rates and consist of the following banks base
rate and LIBOR tranches at December 31: |
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
|
($ in thousands) |
|
Revolving Credit Facility note payable to banks, |
|
|
|
|
|
|
|
|
Agent banks base lending rate of 8.25% |
|
$ |
|
|
|
$ |
2,000 |
|
Libor Tranche at 6.84% and 7.61% |
|
|
60,000 |
|
|
|
113,000 |
|
Second Lien Term Loan payable to banks, |
|
|
|
|
|
|
|
|
Libor Tranche at 9.875% |
|
|
|
|
|
|
50,000 |
|
Senior notes (principal amount $150,000 in 2007)
rate of 10.25% |
|
|
145,383 |
|
|
|
|
|
|
|
|
|
|
|
|
Total notes payable to banks |
|
$ |
205,383 |
|
|
$ |
165,000 |
|
|
|
|
|
|
|
|
|
|
Revolving Credit Facility |
|
|
|
The Revolving Credit Agreement provides for a credit facility that allows the Company to
borrow, repay and reborrow amounts available under the revolving credit facility. The amount
of the borrowing base is based |
F-21
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
primarily upon the estimated value of the Companys oil and
natural gas reserves. The borrowing base amount is redetermined by the lenders semi-annually
on or about April 1 and October 1 of each year or at
other times required by the lenders or at the Companys request. If, as a result of the
lenders redetermination of the borrowing base, the outstanding principal amount of the
Companys loan exceeds the borrowing base, it must either provide additional collateral to the
lenders or repay the principal of the revolving credit facility in an amount equal to the
excess. Except for the principal payments that may be required because of the Companys
outstanding loans being in excess of the borrowing base, interest only is payable monthly. |
|
|
|
Loans made to the Company under this revolving credit facility bear interest at the banks
base rate or the LIBOR rate, at the Companys election. Generally, the banks base rate is
equal to the prime rate published in the Wall Street Journal. |
|
|
|
The LIBOR rate is generally equal to the sum of (a) the rate designated as British Bankers
Association Interest Settlement Rates and offered on one, two, three, six or twelve month
interest periods for deposits of $1.0 million, and (b) a margin ranging from 2.00% to 2.50%,
depending upon the outstanding principal amount of the loans. If the principal amount
outstanding is equal to or greater than 75% of the borrowing base, the margin is 2.50%. If the
principal amount outstanding is equal to or greater than 50%, but less than 75% of the
borrowing base, the margin is 2.25%. If the principal amount outstanding is less than 50% of
the borrowing base, the margin is 2.00%. |
|
|
|
The interest rate the Company is required to pay on its borrowings, including the applicable
margin, may never be less than 5.00%. At December 31, 2007, the Companys Libor interest rate,
plus margin, was 6.84% on $60.0 million. |
|
|
|
In the case of base rate loans, interest is payable on the last day of each month. In the case
of LIBOR loans, interest is payable on the last day of each applicable interest period. |
|
|
|
If the total outstanding borrowings under the revolving credit facility are less than the
borrowing base, an unused commitment fee is required to be paid to the lenders. The amount of
the fee is .25% of the daily average of the unadvanced amount of the borrowing base. The fee
is payable quarterly. |
|
|
|
If the borrowing base is increased, the Company is required to pay a fee of .375% on the
amount of any increase in the borrowing base. |
|
|
|
The Revolving Credit Agreement contains various restrictive covenants, including (i)
maintenance of a minimum current ratio, (ii) maintenance of a maximum ratio of funded
indebtedness to earnings before interest, income taxes, depreciation, depletion and
amortization, (iii) maintenance of a minimum net worth, (iv) prohibition of payment of
dividends and (v) restrictions on incurrence of additional debt. The Company has pledged
substantially all of its producing oil and natural gas properties to secure the repayment of
its indebtedness under the Revolving Credit Agreement. |
|
|
|
As of December 31, 2007 the Company was in compliance
with all of the covenants in its Revolving
Credit Agreement. |
|
|
|
All outstanding principal under the revolving credit facility is due and payable on October
31, 2010. The maturity date of the Companys outstanding loans may be accelerated by the
lenders upon the occurrence of an event of default under the Revolving Credit Agreement. |
|
|
|
Second Lien Term Loan Facility |
|
|
|
Until July 31, 2007, the Second Lien Agreement provided a $50.0 million term loan to the
Company. Loans made to the Company under this credit facility bore interest at an alternate
base rate or the LIBO rate, at the Companys election. The alternate base rate was the greater
of (a) the prime rate in effect on such day and (b) the Federal Funds Effective Rate in
effect on such day plus 1/2 of 1%, plus a margin of 3.50% per annum. |
|
|
|
The LIBO rate was generally equal to the sum of (a) a designated rate appearing in the Dow
Jones Market Service for the applicable interest periods offered in one, two, three or six
month periods and (b) an applicable margin rate per annum equal to 4.50%. |
F-22
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
In the case of alternate base rate loans, interest was payable the last day of each March,
June, September and December. In the case of LIBO loans, interest was payable the last day of
the tranche period not to exceed a three month period. |
|
|
|
Upon completion of the Companys senior notes offering, the Company paid off and terminated
this facility with $50.2 million of the net proceeds from the offering. As a result the
Company charged to earnings $760,000 of previously capitalized debt issuance costs. |
|
|
|
Senior Notes |
|
|
|
On July 31, 2007, the Company completed a private offering of unsecured senior notes
(the senior notes) in the principal amount of $150.0 million. The senior notes mature
on August 1, 2014 and bear interest at 10.25% which is payable semi-annually beginning on
February 1, 2008. Prior to August 1, 2010, the Company may redeem up to 35% of the senior
notes for a price equal to 110.250% of the original principal amount of the senior notes
with the proceeds of certain equity offerings. On or after August 1, 2011 the Company may
redeem all or some of the senior notes at a redemption price that will decrease from
105.125% of the principal amount of the senior notes to 100% of the principal amount on
August 1, 2013. In addition, prior to August 1, 2011, the Company may redeem some or all
of the senior notes at a redemption price equal to 100% of the principal amount of the
senior notes to be redeemed, plus a make-whole premium, plus any accrued and unpaid
interest. Generally, the make-whole premium is an amount equal to the greater of (a)
1% of the principal amount of the senior notes being redeemed and (b) the excess of the
present value of the redemption price of such notes as of August 1, 2011 plus all
required interest payments due through August 1, 2011 (computed at a discount rate equal
to a specified U.S. Treasury Rate plus 50 basis points), over the principal amount of
the senior notes being redeemed. |
|
|
|
The indenture governing the senior notes restricts the Companys ability to: (i) borrow money;
(ii) issue redeemable and preferred stock; (iii) pay distributions or dividends; (iv) make
investments; (v) create liens without securing the senior notes; (vi) enter into agreements
that restrict dividends from subsidiaries; (vii) sell certain assets or merge with or into
other companies; (viii) enter into transactions with affiliates; (ix) guarantee indebtedness;
and (x) enter into new lines of business. |
|
|
|
The Company agreed, pursuant to a Registration Rights Agreement with the initial purchasers of
the senior notes, to use its commercially reasonable efforts to prepare and file with the
Securities and Exchange Commission, within 180 days after July 31, 2007, a registration
statement with respect to a registered offer to exchange freely tradable notes having
substantially identical terms as the senior notes and to use its reasonable best efforts to
cause the registration statement to be declared effective within 210 days after July 31, 2007.
The registration statement became effective on January 29, 2008. If the Company fails to meet
certain other obligations under the Registration Rights Agreement, the Company may be required
to pay additional interest to holders of the senior notes. The rate of additional interest
will be .25% per year for the first 90-day period immediately following a determination that
the provisions of the Registration Rights Agreement have not been fulfilled, with the rate
increasing by an additional .25% for each subsequent 90 day period up to a maximum additional
interest rate of 1.0% per year. Under this agreement, the maximum additional interest that the
Company could be required to pay over the life of the senior notes is approximately $9.4
million. |
F-23
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(9) |
|
Income Taxes |
|
|
|
The Companys income tax provision (benefit) consists of the following: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income tax (benefit) expense |
|
$ |
(4,215 |
) |
|
$ |
13,894 |
|
|
$ |
(1,676 |
) |
Deferred tax benefits of stock option exercises credited to
additional paid in capital |
|
|
816 |
|
|
|
|
|
|
|
|
|
Deferred income tax (benefit) expense related to
loss/gain on derivatives in other comprehensive loss |
|
|
|
|
|
|
3,318 |
|
|
|
515 |
|
Current state tax |
|
|
80 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax provision (benefit) |
|
$ |
(3,319 |
) |
|
$ |
17,212 |
|
|
$ |
(1,161 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Income tax (benefit) expense differs from the amount computed at the federal statutory rate as
follows: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax (benefit) expense at statutory rate |
|
$ |
(2,712 |
) |
|
$ |
13,617 |
|
|
$ |
(1,110 |
) |
Statutory depletion |
|
|
(185 |
) |
|
|
37 |
|
|
|
(443 |
) |
State tax benefit, net of federal tax effect |
|
|
(592 |
) |
|
|
101 |
|
|
|
16 |
|
Nondeductible expenses and other |
|
|
170 |
|
|
|
139 |
|
|
|
(139 |
) |
|
|
|
|
|
|
|
|
|
|
Income tax (benefit) expense |
|
$ |
(3,319 |
) |
|
$ |
13,894 |
|
|
$ |
(1,676 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Prior to 2007, the Company had not recognized the tax
benefits of state net operating loss carryovers due to uncertainty
about their ultimate realization. The Texas Margin Tax, a revision of
Texas state tax laws, applied to earnings for the first time in 2007.
In June 2007, the state of Texas enacted changes to the Texas Margin
Tax legislation originally enacted in 2006, and issued final rules
related to that legislation in December 2007. The utilization of a
credit for prior taxable losses contained in this legislation is
dependent on an election to be made by the taxpayer. Based on the
Companys tax planning strategies and the determination (made in
December 2007) that the election to utilize the credit would
be beneficial to the Companys state and federal tax positions, the
Company decided to make the appropriate election by May 2008, as
required. As a result, the Company has recorded a net state tax
benefit of $592,000. This net state benefit is composed of
(i) current tax expense of $80,000, (ii) deferred tax
expense of $984,000 associated with changes in the state tax rate,
(iii) $156,000 of state tax benefit related to changes in
deferred state tax liabilities, (iv) benefit from the
recognition of business loss credits of approximately
$1.8 million, and (v) $305,000 of federal tax expense
associated with the net state tax benefit. |
F-24
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
The tax effects of temporary differences that give rise to significant portions of the
deferred tax assets and deferred tax liability at December 31 are as follows: |
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
|
($ in thousands) |
|
Current: |
|
|
|
|
|
|
|
|
Deferred tax assets: |
|
|
|
|
|
|
|
|
Fair market value losses on derivatives expected
to be settled within one year |
|
$ |
10,293 |
|
|
$ |
4,340 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent: |
|
|
|
|
|
|
|
|
Deferred tax assets: |
|
|
|
|
|
|
|
|
Federal
operating loss carryforwards |
|
$ |
15,081 |
|
|
$ |
16,942 |
|
State
operating loss credit carryforwards |
|
|
1,805 |
|
|
|
|
|
Statutory depletion carryforwards |
|
|
2,609 |
|
|
|
2,424 |
|
Alternative
minimum tax credit carryforwards |
|
|
157 |
|
|
|
157 |
|
Fair market value losses on derivatives not expected
to be settled within one year |
|
|
5,275 |
|
|
|
4,102 |
|
Asset retirement obligations |
|
|
350 |
|
|
|
233 |
|
Other |
|
|
73 |
|
|
|
26 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total noncurrent deferred tax assets |
|
|
25,350 |
|
|
|
23,884 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities: |
|
|
|
|
|
|
|
|
Property and equipment, principally due to differences in
basis, expensing of intangible drilling costs for tax
purposes and depletion |
|
|
(50,368 |
) |
|
|
(48,019 |
) |
Federal
impact of state operating loss credit carryforwards |
|
|
(614 |
) |
|
|
|
|
Partnership investments |
|
|
(413 |
) |
|
|
(172 |
) |
|
|
|
|
|
|
|
Total deferred tax liabilities |
|
|
(51,395 |
) |
|
|
(48,191 |
) |
|
|
|
|
|
|
|
Net noncurrent deferred income tax liability |
|
$ |
(26,045 |
) |
|
$ |
(24,307 |
) |
|
|
|
|
|
|
|
|
|
As of December 31, 2007, the Company had net operating loss carry forwards for regular tax and
alternative minimum taxable income (AMT) purposes available to reduce future taxable income.
These carry forwards expire as follows: |
|
|
|
|
|
|
|
|
|
|
|
Net operating |
|
|
AMT |
|
|
|
loss |
|
|
operating loss |
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
2019 |
|
$ |
2,566 |
|
|
$ |
2,918 |
|
2021 |
|
|
4,576 |
|
|
|
4,498 |
|
2022 |
|
|
44 |
|
|
|
44 |
|
2023 |
|
|
8 |
|
|
|
332 |
|
2024 |
|
|
3,718 |
|
|
|
3,806 |
|
2025 |
|
|
6,258 |
|
|
|
5,008 |
|
2027 |
|
|
27,187 |
|
|
|
25,015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
44,357 |
|
|
$ |
41,621 |
|
|
|
|
|
|
|
|
|
|
The Company continually assesses its ability to use all of
its federal net operating loss
carryforwards and state operating loss credit carryforwards that result from substantial income tax deductions and prior year losses. The
Company considers future federal and state taxable income in making such assessments. If the Company concludes
that it is more likely than not that some portion or all of the deferred tax assets will not |
F-25
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
be realized under accounting standards, they will be reduced by a valuation
allowance. The Company believes that it is more likely than not that it will utilize all of
these federal net operating loss carryforwards and state operating
loss credit carryforwards in connection with federal and state income tax generated
in the future. |
|
|
As of December 31, 2007, the Company had approximately $157,000 of AMT credit carryforwards that
have no expiration date. |
|
(10) |
|
Equity Transactions |
|
|
|
Sale of Equity Securities |
|
|
|
On August 16, 2006, the Company sold 2,500,000 shares of its common stock, $.01 par value per
share, pursuant to a public offering at a price of $25.25 per share. Gross cash proceeds were
$63.1 million, and net proceeds were approximately $60.3 million. The proceeds were used
for general corporate purposes, including debt repayment and the acceleration of Parallels
drilling and completion operations in certain core areas such as the Barnett Shale natural
gas, New Mexico Wolfcamp natural gas and Permian Basin west Texas oil properties. |
|
|
|
On December 6, 2007, the Company sold 3,000,000 shares of its common stock in an underwritten
public offering at a price of $18.50. The Company used the net proceeds for general
corporate purposes and for conducting exploitation, development and acquisition activities in
certain core areas such as the Companys Permian Basin properties and its Barnett Shale gas
project. |
|
(11) |
|
Stock Compensation, Warrants and Rights |
|
|
|
The Company awards both incentive stock options and nonqualified stock options to selected key
employees, officers, and directors. The options are awarded at an exercise price equal to the
closing price of the Companys common stock on the date of grant. These options vest over a
period of two to ten years with a ten-year exercise period. As of December 31, 2007, options
expire beginning in 2008 and extending through 2017. |
|
(a) |
|
Stock Options |
|
|
|
|
A summary of the Companys employee stock options as of December 31, 2007, 2006 and 2005,
and changes during the years ended on those dates is presented below: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended |
|
|
Year ended |
|
|
Year ended |
|
|
|
December 31, 2007 |
|
|
December 31, 2006 |
|
|
December 31, 2005 |
|
|
|
Number of |
|
|
Weighted |
|
|
Number of |
|
|
Weighted |
|
|
Number of |
|
|
Weighted |
|
|
|
shares |
|
|
average price |
|
|
shares |
|
|
average price |
|
|
shares |
|
|
average price |
|
|
|
(in thousands) |
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Stock options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at
beginning of year |
|
|
1,199 |
|
|
$ |
5.40 |
|
|
|
1,405 |
|
|
$ |
5.22 |
|
|
|
1,919 |
|
|
$ |
3.71 |
|
Options granted |
|
|
18 |
|
|
|
22.89 |
|
|
|
|
|
|
|
|
|
|
|
200 |
|
|
|
12.27 |
|
Options exercised |
|
|
(619 |
) |
|
|
3.98 |
|
|
|
(176 |
) |
|
|
4.35 |
|
|
|
(714 |
) |
|
|
3.15 |
|
Options cancelled |
|
|
|
|
|
|
|
|
|
|
(30 |
) |
|
|
3.09 |
|
|
|
|
|
|
|
|
|
Options forfeited |
|
|
(40 |
) |
|
|
12.27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at
end of year |
|
|
558 |
|
|
$ |
7.03 |
|
|
|
1,199 |
|
|
$ |
5.40 |
|
|
|
1,405 |
|
|
$ |
5.22 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at
end of year |
|
|
420 |
|
|
$ |
5.39 |
|
|
|
1,001 |
|
|
$ |
4.32 |
|
|
|
1,160 |
|
|
$ |
4.01 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average
fair value of options
granted during the year |
|
|
|
|
|
$ |
12.45 |
|
|
|
|
|
|
$ |
|
|
|
|
|
|
|
$ |
7.11 |
|
F-26
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
The following table summarizes information about the Companys employee stock options
outstanding and exercisable at December 31, 2007: |
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
Intrinsic |
|
|
|
Remaining Life |
|
|
Value |
|
|
|
|
|
|
|
(in thousands) |
|
Stock options outstanding
as of December 31, 2007 |
|
|
5.1 |
|
|
$ |
5,909 |
|
|
|
|
|
|
|
|
Currently exercisable
as of December 31, 2007 |
|
|
4.4 |
|
|
$ |
5,139 |
|
|
|
|
|
|
|
|
|
|
|
For the twelve months ended December 31, 2007, 2006 and 2005, Parallel recognized
compensation expense of approximately $247,000, $531,000 and $278,000 with tax benefits of
approximately $84,000, $181,000 and $95,000, respectively, associated with its stock
option grants. |
|
|
|
|
The following table presents the future stock-based compensation expense expected to be
recognized over the vesting period: |
|
|
|
|
|
|
|
($ in thousands) |
|
2008 |
|
$ |
228 |
|
2009 |
|
|
93 |
|
2010 |
|
|
29 |
|
|
|
|
|
Total |
|
$ |
350 |
|
|
|
|
|
|
|
|
Nonvested options were 137,500 at December 31, 2007. During the twelve months ended
December 31, 2007, 618,500 options were exercised, options to purchase 17,500 shares of
common stock were granted to one individual, options to purchase 40,000 shares were
forfeited and no options expired. During 2006 the Company settled 30,000 options for
approximately $511,000. |
|
|
|
|
The fair value of each option award is estimated on the date of grant. The fair value of
stock options granted prior to and remaining outstanding at December 31, 2007 and that had
option shares subject to future vesting at that date was determined using the
Black-Scholes option valuation method and the assumptions noted in the following table.
Expected volatilities are based on historical volatility of the common stock. The
expected term of the options granted used in the model represent the period of time that
options granted are expected to be outstanding. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2005 |
|
2001 |
Expected volatility |
|
|
52.52 |
% |
|
|
54.20 |
% |
|
|
57.95 |
% |
Expected dividends |
|
|
0.00 |
|
|
|
0.00 |
|
|
|
0.00 |
|
Expected term (in years) |
|
|
6 |
|
|
|
7 |
|
|
|
8 |
|
Risk free rate |
|
|
4.89 |
% |
|
|
4.20 |
% |
|
|
5.05 |
% |
F-27
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
($ in thousands) |
|
|
|
|
|
Intrinsic Value of Options Exercised Twelve Months Ended December 31, 2007 |
|
$ |
10,071 |
|
Intrinsic Value of Options Exercised Twelve Months Ended December 31, 2006 |
|
$ |
2,855 |
|
Intrinsic Value of Options Exercised Twelve Months Ended December 31, 2005 |
|
$ |
9,169 |
|
|
|
|
|
|
Fair Market Value of Options Granted Twelve Months Ended December 31, 2007 |
|
$ |
218 |
|
Fair Market Value of Options Granted Twelve Months Ended December 31, 2006 |
|
$ |
|
|
Fair Market Value of Options Granted Twelve Months Ended December 31, 2005 |
|
$ |
1,423 |
|
|
|
|
There were 17,500 stock options granted for the twelve months ended December 31, 2007 with
a fair market value of $218,000. For the twelve months ended December 31, 2005 there were
200,000 options granted with a fair market value of $1.4 million. |
|
|
(b) |
|
Stock Warrants |
|
|
|
|
The Company has 300,030 perpetual warrants outstanding at December 31, 2007, 2006, and
2005, which were issued as part of the Companys initial public offering in 1980. Each
warrant allows the holder to buy one share of common stock for $6.00. The warrants are
exercisable for a 30 day period commencing on the date a registration statement covering
exercise is declared effective. The warrants contain antidilution provisions. |
|
|
|
|
The Company also had an additional 136,708 warrants outstanding at December 31, 2005
issued as partial payment for services rendered for financial and investment advice in
2001. The warrants had a term of five years from date of issuance and a vesting period of
one year. The warrants had an exercise price of $2.95 per share and contain a provision
for cashless exercise. The expense related to these warrants in the amount of $99,000 was
recorded in other expenses in 2001 based on the estimated fair value on the date of grant
using the Black-Scholes option pricing model. As of December 31, 2006 these warrants had
been fully exercised. |
|
|
|
|
The Company had 100,000 warrants outstanding at December 31, 2006, 2005 and 2004, which
were issued as partial payment for services rendered for financial and investment advice
for the Companys private placement offering in December, 2003. The warrants had a term of
five years from date of issuance and vesting period of one year. The warrants had an
exercise price of $3.98 per share and contained a provision for cashless exercise. The
fair value related to these warrants in the amount of $157,000 was recorded in other
expenses in 2003 based on the estimated fair value on the date of grant using the
Black-Scholes option pricing model. The holders of these warrants elected to exercise
during 2007 through cashless exercise as allowed under the terms of the warrants. As a
result, 82,734 common shares were issued to the warrant holders. |
|
|
(c) |
|
Stock Rights |
|
|
|
|
On October 5, 2000, the board of directors adopted a Stockholder Rights Plan (the Plan)
and declared a dividend of one Stock Right for each outstanding share of the Companys
common stock. Generally, the Plan is designed to protect the Company from unfair or
coercive takeover attempts, prevent a potential acquiror from gaining control of the
Company without fairly compensating all of the Companys stockholders, and encourage third
parties that may have an interest in acquiring the Company to negotiate with the Companys
board of directors. In particular, the Plan is intended to (i) reduce the risk of coercive
or partial tender offers that may not offer fair value to all stockholders; (ii) deter
purchasers who through open market or private purchase may attempt to achieve a position
of substantial influence or control over the Company without paying a fair control premium
to selling or remaining stockholders; and (iii) preserve the board of directors
bargaining power and flexibility to deal with acquirors and otherwise to seek to maximize
value for all stockholders. The Plan is intended to achieve these goals by confronting a
potential acquiror of the Companys common stock with the possibility that the Company or
its stock- |
F-28
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
holders will be able to substantially dilute the acquirors equity interest by
using the Stock Rights to acquire additional Company common stock, or in certain cases
stock of the acquiror, at a 50% discount. |
|
|
|
|
If a person acquires 15% or more of the Companys common stock or a tender offer or
exchange offer is made for 15% or more of the common stock, each Stock Right will entitle
the holder to purchase from the Company one one-thousandth of a share of Series A
Preferred Stock, par value $0.10 per share, at an exercise price of $26.00 per one
one-thousandth of a share, subject to adjustment. |
|
|
|
|
Initially, the Stock Rights attach to all common stock certificates representing shares
then outstanding, and no separate Stock Rights certificates will be distributed. The Stock
Rights separate from the common stock upon the earlier of (1) ten business days following
a public announcement that a person or group of affiliated or associated persons has
acquired or obtained the right to acquire, beneficial ownership of 15% or more of the
outstanding shares of common stock or (2) ten business days (or such later date as the
board of directors shall determine) following the commencement of a tender or exchange
offer that would result in a person or group beneficially owning 15% or more of such
outstanding shares of common stock. The date the Stock Rights separate is referred to as
the distribution date. |
|
|
|
|
Under certain circumstances the Stock Rights entitle the holders to buy shares of the
acquirers common stock at a 50% discount. In the event that, at any time after a person
has acquired 15% or more of the Companys common stock, (1) the Company enters into a
merger or other business combination transaction in which the Company is not the surviving
corporation; (2) the Company is the surviving corporation in a transaction in which all or
part of the common stock is exchanged for cash, property or securities of any other
person; or, (3) more than 50% of the assets, cash flow or earning power of the Company is
sold, each right holder will have the option to buy for the purchase price stock of the
acquiring company having a value equal to two times the purchase price of the Stock Right. |
|
|
|
|
The Stock Rights are not exercisable until the distribution date and will expire at the
close of business on October 5, 2010, unless earlier redeemed by the Company for $0.001
per Stock Right. |
|
|
|
|
At issuance, the Stock Rights had no determinable value and, therefore, no accounting
entry was required. The Stock Rights have not had, nor does the Company anticipate that the Stock
Rights will have, an effect on its results of operations. |
|
|
(d) |
|
Non-Employee Director Stock Grant Plan |
|
|
|
|
Effective July 1, 2004, the Company began paying an annual retainer fee to each
non-employee Director in the form of shares of the Companys common stock. Under the 2004
Non-Employee Director Stock Grant Plan, each non-employee Director is entitled to receive
an annual retainer fee in the form of shares of common stock having a value of $25,000.
The shares of stock are automatically granted on the first day of July in each year. The
actual number of shares received is determined by dividing $25,000 by the average daily
closing price of the common stock on the Nasdaq Stock Market for the ten consecutive
trading days commencing fifteen trading days before the first day of July of each year. On
July 1, 2007 and in accordance with the terms of the plan, the Company issued a total of
4,400 shares of common stock to four non-employee Directors as follows: Jeffrey G. Shrader
1,100 shares; Edward A. Nash 1,100 shares; Martin B. Oring 1,100 shares; and Ray
M. Poage 1,100 shares. On July 1, 2006 and in accordance with the terms of the plan,
the Company issued a total of 4,696 shares of common stock to four non-employee Directors
as follows: Jeffrey G. Shrader 1,174 shares; Dewayne E. Chitwood 1,174 shares;
Martin B. Oring 1,174 shares; and Ray M. Poage 1,174 shares. On July 1, 2005, and in
accordance with the terms of the plan, the Company issued a total of 11,596 shares of
common stock to four non-employee Directors as follows: Jeffrey G. Shrader 2,899
shares; Dewayne E. Chitwood 2,899 shares; Martin B. Oring 2,899 shares; and Ray M.
Poage 2,899 shares. The Company has 74,420 remaining shares of common stock available
to issue to directors under this arrangement. |
(12) |
|
Related Party Transactions |
|
|
|
An entity owned by Thomas R. Cambridge, the Companys former Chairman of the Board of
Directors, is the owner and acted as the Companys agent in performing the routine day to day
operations on two wells. In 2007, 2006 and 2005 the Company was billed approximately $27,000,
$23,000 and $20,000, respectively, for
|
F-29
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
the Companys pro rata share of lease operating and
drilling expenses and received approximately $65,000, $176,000 and $161,000 in 2007, 2006 and
2005 respectively, in oil and natural gas revenues related to these wells. These two wells
were acquired in 1984. |
|
|
|
An entity, of which Mr. Cambridge is the President, owned interests in certain wells that are
administered by the Company. During 2007 the Company charged approximately $1,300 for lease
operating expenses and paid approximately $4,600 in oil and natural gas revenues related to
these wells. In June 2007, these wells were sold by the entity and the Company to an
unaffiliated third party and the Company distributed approximately $10,000 to the entity, its
pro rata share of the sales proceeds. |
|
|
|
Dewayne E. Chitwood, a former Director of the Company, also serves as director of an entity
which owned 110,000 shares of preferred stock of the Company. In addition, a Foundation, where
Mr. Chitwood is the Chairman of the board of directors of the Foundation; and a Trust where he
is Trustee, owned a total of 55,000 shares each of preferred stock of the Company. These shares of preferred stock of the
Company were purchased in 1998 at a price of $10 per share on the same terms as all other
unaffiliated purchasers. On June 6, 2005 the 110,000 and the 55,000 shares of preferred stock
were converted to 314,285 and 157,142 shares of common stock, respectively. |
|
|
|
An entity, in which Mr. Chitwood is an officer of the managing general partner, owned
interests in certain wells that are operated by the Company. During 2005 the Company charged
approximately $4,000 for lease operating expenses and paid approximately $8,000 in oil and
natural gas revenues related to these wells. In 2005 the Company paid to the entity
approximately $140,000 in payment of net proceeds attributable to its pro rata share from the
sale of the interests. |
|
|
|
In December, 2001, and prior to his employment with Parallel, Donald E. Tiffin, Parallels
Chief Operating Officer, received a 3% working interest from an unaffiliated third party in
the Diamond M Project in Scurry County, Texas for services rendered in connection with
assembling the project. In August, 2002, shortly after his employment with Parallel, and due
to the personal financial exposure in the Diamond M Project and to prevent the interest from
being acquired by a third party, Mr. Tiffin assigned two-thirds of his ownership interest in
the project to Parallel at no cost, leaving him with a 1% working interest. Parallel acquired
its initial interest in the Diamond M Project in December, 2001. During 2007, the Company
charged approximately $45,000 for capital expenditures and lease operating expenses and paid
approximately $65,000 in oil and natural gas revenues related to this project. In addition,
$5,000 and $8,000 of this balance was for outstanding joint interest billings to an executive
officer as of December 31, 2007 and 2006. These receivables were collected within one month
of billing. |
|
|
|
As of December 31, 2007 and 2006, the Company had accounts receivable of $4.0 million and $3.3
million, respectively, from affiliates. Joint interest receivables from a joint interest
owner (who is also a joint venture partner in Hagerman) represented $3.4 million and $2.0
million of these balances at the December 31, 2007 and 2006, respectively. |
|
|
|
The remaining receivables from affiliates represent Parallels advance to Hagerman as described in Note 7. |
|
(13) |
|
Statements of Cash Flows |
|
|
|
In 2006, $40,000 was paid for estimated alternative minimum tax. No income taxes were paid in
2007 and 2005. |
|
|
|
The Company made interest payments of approximately $13.1 million, $12.5 million, and
$5.4 million in 2007, 2006 and 2005, respectively. |
|
|
|
At December 31, 2007, 2006 and 2005, there were $11.0 million, $8.5 million and $2.5 million,
respectively, of property additions accrued in accounts payable. |
F-30
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(14) |
|
Major Customers |
|
|
|
The following purchasers accounted for 10% or more of the Companys oil and natural gas sales
for the years ended December 31: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Allegro Investments, Inc. |
|
|
(1 |
) |
|
|
(1 |
) |
|
|
14 |
% |
Conoco, Inc. |
|
|
21 |
% |
|
|
20 |
% |
|
|
12 |
% |
Texland Petroleum, Inc. |
|
|
30 |
% |
|
|
30 |
% |
|
|
40 |
% |
Tri-C Resources, Inc. |
|
|
(1 |
) |
|
|
12 |
% |
|
|
(1 |
) |
Dale Op erating Company |
|
|
(1 |
) |
|
|
10 |
% |
|
|
(1 |
) |
Chesapeake Op erating, Inc. |
|
|
12 |
% |
|
|
(1 |
) |
|
|
(1 |
) |
(15) |
|
Commitments and Contingencies |
|
|
|
On May 21, 2007, the Company received a Notice of Proposed Adjustment, or the Notice from
the Internal Revenue Service, or the Service, advising the Company of a proposed adjustment
to its calculations of federal income tax resulting in a proposed alternative minimum tax
liability in the aggregate amount of approximately $2.0 million for the years 2004 and 2005.
After advising the Service that the Company intended to appeal the Notice, the Company
received correspondence from the Service on July 10, 2007 stating that the issue remains in
development pending receipt of additional documents requested and any proposed tax adjustment
would not be made until after reviewing the documents requested. On
November 5, 2007, the Company
received an examination report related to this matter which reduces the amount of proposed
adjustment to approximately $1.1 million, which includes interest. On December 21, 2007, the
Company filed an appeal with the Service protesting the proposed adjustment of $1.1 million.
The Company intends to vigorously contest the adjustment proposed by the Service and believes
that it will ultimately prevail in its position. The Company would expect the recording of any
adjustment, if later determined to be required, to entail recognition of a deferred tax asset
and a corresponding current liability for federal income taxes payable. Such an adjustment
would generally not result in a charge to earnings except for amounts which might be assessed
for penalties or interest on underpayment of current tax for the Companys fiscal years ended
December 31, 2004 and 2005. If a liability for penalties or interest were determined to be
probable, the amounts of such penalties and/or interest would be charged to earnings. The
Company believes that the effects of this matter will not have a material adverse effect on
its financial position or results of operations for any fiscal year, but could have a material
adverse effect on its results of operations for the fiscal quarter in which it actually incurs
or establishes a liability for penalties or interest. |
|
|
|
On January 1, 2005 the Company established a 401(k) Plan and Trust for eligible employees.
During 2007, 2006 and 2005, the Company contributed an aggregate of approximately $274 000,
$240,000 and $168,000, respectively, to the 401(k) Plan. |
|
|
|
The Company leases office space under a non-cancelable operating lease expiring in 2010.
Future annual payments under this operating lease are approximately $200,000, $200,000 and
$33,000 for the years ending December 31, 2008 through February 28, 2010, respectively. Rental
expense under the Companys current lease totaled approximately $200,000, $194,000 and
$162,000 for the years ended December 31, 2007, 2006, and 2005, respectively. |
|
|
|
The Company has three field offices and storage facilities. These facilities are located in
Andrews and Snyder, Texas and Hagerman, New Mexico. The Snyder office lease expires upon the
cessation of production from the Diamond M area wells. Future annual payments under this
lease agreement total approximately $14,000 for 2008 through 2012. Rental expense totaled
approximately $23,000, $23,000 and $23,000 for the years ended December 31, 2007, 2006 and
2005, respectively. |
F-31
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
The Company has an Incentive and Retention Plan which provides for the payment to eligible
officers and employees of a one time performance bonus and retention payment upon the
occurrence of a change of control as defined in the Plan. Because of the uncertainty of the
occurrence of a change of control or corporate transaction within the meaning of the plan, the amount of
these bonuses is undeterminable. Although the amount of the bonus is undeterminable at this time, if the bonus was calculated
using the December 31, 2007 stock price of $17.63 per share, the amount would be approximately
$18.6 million. |
|
|
|
In January 2006, the Company adopted a Non-officer Employee Severance Plan for the purpose of
providing the Companys non-officer employees with an incentive to remain employed with the
Company. This Plan provides for a one-time severance payment to the non-officer employees
equal to one year of their then current base salary upon the occurrence of a change of
control within the meaning of the Plan. Based on the aggregate non-officer base salaries in
effect as of December 31, 2007, the total severance amount payable under the plan would have
been approximately $3.8 million. |
|
(16) |
|
Supplemental Oil and Natural Gas Reserve Data (Unaudited) |
|
|
|
The Company has presented the reserve estimates utilizing an oil price of $89.93, $54.67 and
$56.09 per Bbl and a natural gas price of $6.77, $5.00 and $8.68 per Mcf as of December 31,
2007, 2006 and 2005, respectively. Information for oil is presented in barrels (Bbl) and for
natural gas in thousands of cubic feet (Mcf). |
|
|
|
The estimates of the Companys proved oil and natural gas reserves and related future net cash
flows that are presented in the following tables are based upon estimates made by independent
petroleum engineering consultants. |
|
|
|
The Companys reserve information was prepared by independent petroleum engineering
consultants as of December 31, 2007, 2006 and 2005. The Company cautions that there are many
inherent uncertainties in estimating proved reserve quantities, projecting future production
rates, and timing of development expenditures. Accordingly, these estimates are likely to
change as future information becomes available. Proved oil and natural gas reserves are the
estimated quantities of crude oil and natural gas which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions. Proved developed reserves are those reserves
expected to be recovered through existing wells, with existing equipment and operating
methods. |
F-32
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
A summary of changes in reserve balances is presented below: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Condensate (Bbls) |
|
|
For the Year Ended December 31, |
|
|
2007 |
|
2006 |
|
2005 |
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed and undeveloped reserves |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year |
|
|
28,721 |
|
|
|
21,192 |
|
|
|
18,916 |
|
Purchase of oil and natural gas properties |
|
|
|
|
|
|
3,270 |
|
|
|
2,299 |
|
Sales of oil and natural gas properties |
|
|
(75 |
) |
|
|
|
|
|
|
(14 |
) |
Extensions and discoveries |
|
|
1,146 |
|
|
|
8,182 |
|
|
|
944 |
|
Revisions of previous estimates |
|
|
(307 |
) |
|
|
(2,786 |
) |
|
|
(30 |
) |
Production |
|
|
(1,051 |
) |
|
|
(1,137 |
) |
|
|
(923 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
End of Year |
|
|
28,434 |
|
|
|
28,721 |
|
|
|
21,192 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves at year end |
|
|
14,378 |
|
|
|
14,932 |
|
|
|
13,614 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (MCF) |
|
|
For the Year Ended December 31, |
|
|
2007 |
|
2006 |
|
2005 |
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed and undeveloped reserves |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year |
|
|
58,896 |
|
|
|
25,237 |
|
|
|
16,825 |
|
Purchase of oil and natural gas properties |
|
|
|
|
|
|
4,355 |
|
|
|
456 |
|
Sales of oil and natural gas properties |
|
|
(3,105 |
) |
|
|
|
|
|
|
(205 |
) |
Extensions and discoveries |
|
|
25,905 |
|
|
|
38,159 |
|
|
|
13,106 |
|
Revisions of previous estimates |
|
|
(17,040 |
) |
|
|
(2,316 |
) |
|
|
(1,353 |
) |
Production |
|
|
(7,422 |
) |
|
|
(6,539 |
) |
|
|
(3,592 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
End of Year |
|
|
57,234 |
|
|
|
58,896 |
|
|
|
25,237 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves at year end |
|
|
41,556 |
|
|
|
28,741 |
|
|
|
17,246 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company made significant acquisitions in 2005 and 2006 that resulted in additions to its
estimated proved reserves for those years. In 2005, the Company purchased producing
properties in the Harris San Andres Field located in Andrews and Gaines counties. In 2006,
the Company acquired additional interests in these properties. Also in 2006, the Company
purchased additional interests in the Barnett Shale Gas Project located in Tarrant County,
Texas. |
|
|
|
The Companys drilling programs over the last three years have resulted in significant natural
gas discoveries and extensions in the Companys Barnett Shale resource gas project and the
Companys New Mexico projects. Over this same time period, the Companys drilling in the
Carm-Ann, Harris and Diamond M fields of west Texas resulted in significant increases in
extensions and discoveries in the Companys oil reserves. |
|
|
|
The Company experienced downward revisions in estimated proved natural gas reserves in 2007.
This was the result of two factors. First, the Company changed its
method of recognizing proved undeveloped reserves related to its horizontal drilling gas
projects in March 2007. Under this new method, which the Company believes conforms with
regulatory requirements applicable to horizontal well reserve booking practices for publicly
owned exploration and production companies, estimates of proved undeveloped reserves from
horizontal wells are limited to two parallel offset wells to a productive horizontal well,
unless productive continuity is demonstrated through pressure communication between wells more
than an offset location away and on either side of a future horizontal well. Secondly, the
Company adjusted its reserve estimates on certain New Mexico Wolfcamp and Barnett Shale wells
where performance did not meet our 2007 production estimates. |
|
|
|
The following is a standardized measure of the discounted net future cash flows and changes
applicable to proved oil and natural gas reserves required by Statement of Financial
Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities (SFAS No. 69). The future cash flows are based on
estimated oil and natural gas reserves utilizing prices and costs in effect as of year end,
discounted at 10% per year and assuming continuation of existing economic conditions. |
F-33
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
The standardized measure of discounted future net cash flows, in managements opinion, should
be examined with caution. The basis for this table is the reserve studies prepared by
independent petroleum engineering consultants, which contain imprecise estimates of quantities
and rates of production of reserves. Revisions of previous year estimates can have a
significant impact on these results. Also, exploration costs in one year may lead to
significant discoveries in later years and may significantly change previous estimates of
proved reserves and their valuation. Therefore, the standardized measure of discounted future
net cash flow is not necessarily indicative of the fair value of the Companys proved oil and
natural gas properties. |
|
|
|
Future income tax expense was computed by applying statutory rates less the effects of tax
credits for each period presented to the difference between pre-tax net cash flows relating to
the Companys proved reserves and the tax basis of proved properties and available net
operating loss and percentage depletion carryovers. |
Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
($ in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows |
|
$ |
2,944,746 |
|
|
$ |
1,864,860 |
|
|
$ |
1,407,153 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future costs: |
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
(824,261 |
) |
|
|
(606,138 |
) |
|
|
(361,563 |
) |
Development |
|
|
(117,981 |
) |
|
|
(138,715 |
) |
|
|
(36,335 |
) |
Future income taxes |
|
|
(536,227 |
) |
|
|
(292,954 |
) |
|
|
(249,621 |
) |
|
|
|
|
|
|
|
|
|
|
Future net cash flows |
|
|
1,466,277 |
|
|
|
827,053 |
|
|
|
759,634 |
|
10% annual discount for estimated timing of cash flows |
|
|
(831,839 |
) |
|
|
(490,565 |
) |
|
|
(398,844 |
) |
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net
cash flows |
|
$ |
634,438 |
|
|
$ |
336,488 |
|
|
$ |
360,790 |
|
|
|
|
|
|
|
|
|
|
|
Changes in Standardized Measure of
Discounted Future Net Cash Flows From Proved Reserves
($ in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
Increase (decrease): |
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of minerals in place |
|
$ |
|
|
|
$ |
20,698 |
|
|
$ |
29,354 |
|
Extensions and discoveries and improved recovery,
net of future production and development costs |
|
|
97,918 |
|
|
|
104,622 |
|
|
|
87,790 |
(1) |
Accretion of discount |
|
|
46,996 |
|
|
|
47,281 |
|
|
|
26,625 |
|
Net change in sales prices net of production costs |
|
|
341,421 |
|
|
|
(78,387 |
) |
|
|
135,242 |
|
Changes in estimated future development costs |
|
|
28,424 |
|
|
|
12,726 |
|
|
|
(10,886 |
) |
Revisions of quantity estimates |
|
|
(64,408 |
) |
|
|
(44,561 |
) |
|
|
(4,518 |
) |
Net change in income taxes |
|
|
(116,010 |
) |
|
|
(21,452 |
) |
|
|
(52,181 |
) |
Sales, net of production costs |
|
|
(89,818 |
) |
|
|
(86,130 |
) |
|
|
(47,974 |
) |
Changes of production rates (timing) and other |
|
|
53,427 |
|
|
|
20,901 |
|
|
|
(9,071 |
)(1) |
|
|
|
|
|
|
|
|
|
|
Net increase |
|
|
297,950 |
|
|
|
(24,302 |
) |
|
|
154,381 |
|
Standardized measure of discounted future net cash flows: |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year |
|
|
336,488 |
|
|
|
360,790 |
|
|
|
206,409 |
|
|
|
|
|
|
|
|
|
|
|
End of year |
|
$ |
634,438 |
|
|
$ |
336,488 |
|
|
$ |
360,790 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
During 2006, the Company revised its method of calculating Extensions and
discoveries and improved recovery, net of future production and development costs.
Consequently, related calculations in 2005 have been adjusted to be consistent with the
2006 calculation. |
F-34
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(17) |
|
Selected Quarterly Financial Data (Unaudited) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter |
|
|
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
|
|
($ in thousands, except per share data) |
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenues |
|
$ |
23,116 |
|
|
$ |
27,354 |
|
|
$ |
29,487 |
|
|
$ |
36,074 |
|
Total costs and expenses |
|
|
14,827 |
|
|
|
15,291 |
|
|
|
18,206 |
|
|
|
18,742 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
8,289 |
|
|
|
12,063 |
|
|
|
11,281 |
|
|
|
17,332 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(96 |
) |
|
$ |
3,464 |
|
|
$ |
293 |
|
|
$ |
(8,322 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders |
|
$ |
(96 |
) |
|
$ |
3,464 |
|
|
$ |
293 |
|
|
$ |
(8,322 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share basic |
|
$ |
|
|
|
$ |
0.09 |
|
|
$ |
0.01 |
|
|
$ |
(0.21 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share diluted |
|
$ |
|
|
|
$ |
0.09 |
|
|
$ |
0.01 |
|
|
$ |
(0.21 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenues |
|
$ |
20,543 |
|
|
$ |
26,342 |
|
|
$ |
26,211 |
|
|
$ |
23,929 |
|
Total costs and expenses |
|
|
11,102 |
|
|
|
13,962 |
|
|
|
16,686 |
|
|
|
14,856 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
9,441 |
|
|
|
12,380 |
|
|
|
9,525 |
|
|
|
9,073 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
1,611 |
|
|
$ |
2,464 |
|
|
$ |
10,996 |
|
|
$ |
11,084 |
(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders |
|
$ |
1,611 |
|
|
$ |
2,464 |
|
|
$ |
10,996 |
|
|
$ |
11,084 |
(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share basic |
|
$ |
0.05 |
|
|
$ |
0.07 |
|
|
$ |
0.30 |
|
|
$ |
0.30 |
(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share diluted |
|
$ |
0.05 |
|
|
$ |
0.07 |
|
|
$ |
0.30 |
|
|
$ |
0.29 |
(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
2006 results include $9.0 million of equity in income of pipeline and gathering
systems representing the Companys share of net gain on sale of certain pipeline assets.
See Note 7. |
F-35
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
|
|
|
|
|
|
PARALLEL PETROLEUM CORPORATION
|
|
February 20, 2008 |
By: |
/s/ Larry C. Oldham
|
|
|
|
Larry C. Oldham |
|
|
|
President and Chief Executive Officer |
|
|
|
|
|
February 20, 2008 |
By: |
/s/ Steven D. Foster
|
|
|
|
Steven D. Foster |
|
|
|
Chief Financial Officer |
|
S-1
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the Registrant and in the capacities and on the
dates indicated.
|
|
|
|
|
/s/ Jeffrey G. Shrader
|
|
Director and Chairman of the Board of Directors
|
|
February 20, 2008 |
|
|
|
|
|
Jeffrey G. Shrader |
|
|
|
|
|
|
|
|
|
/s/ Larry C. Oldham
|
|
President and Chief Executive Officer
|
|
February 20, 2008 |
|
|
|
|
|
Larry C. Oldham
|
|
(Principal Executive Officer) |
|
|
|
|
|
|
|
/s/ Steven D. Foster
|
|
Chief Financial Officer
|
|
February 20, 2008 |
|
|
|
|
|
Steven D. Foster
|
|
(Principal Financial and
Accounting Officer) |
|
|
|
|
|
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/s/ Edward A. Nash
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Director
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February 20, 2008 |
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Edward A. Nash |
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/s/ Martin B. Oring
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Director
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February 20, 2008 |
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Martin B. Oring |
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/s/ Ray M. Poage
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Director
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February 20, 2008 |
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Ray M. Poage |
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S-2
INDEX TO EXHIBITS
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No. |
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Description of Exhibit |
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3.1
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Certificate of Incorporation of Registrant (Incorporated by reference to Exhibit 3.1 to Form
10-Q of the Registrant for the fiscal quarter ended June 30, 2004) |
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3.2
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Bylaws of Registrant (Incorporated by reference to Exhibit 10.1 of the Registrants Current
Report on Form 8-K filed on November 30, 2007) |
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3.3
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Certificate of Formation of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.3 of
the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004) |
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3.4
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Limited Liability Company Agreement of Parallel, L.L.C. (Incorporated by reference to Exhibit
No. 3.4 of the Registrants Statement on Form S-3, No. 333-119725 filed on October 13, 2004) |
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3.5
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Certificate of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit
No. 3.5 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on
October 13, 2004) |
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3.6
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Agreement of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No.
3.6 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October
13, 2004) |
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4.1
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Certificate of Designations, Preferences and Rights of Serial Preferred Stock 6%
Convertible Preferred Stock (Incorporated by reference to Exhibit 4.1 of Form 10-Q of the
Registrant for the fiscal quarter ended June 30, 2004) |
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4.2
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Certificate of Designations, Preferences and Rights of Series A Preferred Stock (Incorporated
by reference to Exhibit 4.2 of Form 10-K of the Registrant for the fiscal year ended December
31, 2000) |
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4.3
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Rights Agreement, dated as of October 5, 2000, between the Registrant and Computershare Trust
Company, Inc., as Rights Agent (Incorporated by reference to Exhibit 1 of Form 8-A of the
Registrant filed with the Securities and Exchange Commission on October 10, 2000) |
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4.4
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Form of common stock certificate of the Registrant (Incorporated by reference to Exhibit No.
4.6 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October
13, 2004) |
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4.5
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Warrant Purchase Agreement, dated November 20, 2001, between the Registrant and Stonington
Corporation (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant for the
fiscal year ended December 31, 2004) |
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4.6
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Warrant Purchase Agreement, dated December 23, 2003, between the Registrant and Stonington
Corporation (Incorporated by reference to Exhibit 4.8 of Form 10-K of the Registrant for the
fiscal year ended December 31, 2004) |
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4.7
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Purchase Warrant Agreement, dated as of October 1, 1980, between the Registrant and American
Stock Transfer, Inc. (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant
for the fiscal year ended December 31, 2006) |
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4.8
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First Amendment to Warrant Agreement, dated as of February 22, 2007, among the Registrant,
Computershare Shareholder Services, Inc. and Computershare Trust Company, N.A. (Incorporated
by reference to Exhibit 4.8 of Form 10-K of the Registrant for the fiscal year ended December
31, 2006) |
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4.9
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Form of Rule 144A 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.2 to the
Registrants Current Report on Form 8-K filed on August 1, 2007) |
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4.10
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Form of IAI 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.3 to the
Registrants Current Report on Form 8-K filed on August 1, 2007) |
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4.11
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Form of Regulation S 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.4 to
the Registrants Current Report on Form 8-K filed on August 1, 2007) |
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No. |
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Description of Exhibit |
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4.12
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Indenture, dated as of July 31, 2007, among the Registrant as Issuer and Wells Fargo Bank,
National Association as Trustee (Incorporated by reference to Exhibit 4.1 to the Registrants
Current Report on Form 8-K filed on August 1, 2007) |
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4.13
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Registration Rights Agreement, dated as of July 31, 2007, by and among the Registrant,
Jefferies & Company, Inc., Merrill Lynch, Pierce, Fenner and Smith Incorporated and BNP
Paribas Securities Corp. (Incorporated by reference to Exhibit 10.2 to the Registrants
Current Report on Form 8-K filed on August 1, 2007) |
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4.14
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Purchase Agreement, dated as of July 26, 2007, by and among the Registrant, Jefferies &
Company, Inc., Merrill Lynch, Pierce, Fenner and Smith Incorporated and BNP Paribas Securities
Corp. (Incorporated by reference to Exhibit 4.2 to the Registrants Current Report on Form 8-K
filed on August 1, 2007) |
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4.15
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Form of 101/4% Unrestricted Senior Note due 2014 (Incorporated by reference to Exhibit 4.13 of
Form S-4 of the Registrant, Registration No. 333-148465) |
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Executive Compensation Plans and Arrangements (Exhibit No.s 10.1 through 10.7):
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10.1
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1992 Stock Option Plan (Incorporated by reference to Exhibit 10.1 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2004) |
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10.2
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Merrill Lynch, Pierce, Fenner & Smith Incorporated Prototype Simplified Employee Pension Plan
(Incorporated by reference to Exhibit 10.6 of the Registrants Form 10-K for the fiscal year
ended December 31, 1995) |
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10.3
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Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.3 of the
Registrants Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2005) |
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10.4
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1998 Stock Option Plan (Incorporated by reference to Exhibit 10.4 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2006) |
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10.5
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2001 Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.7 of
the Registrants Form 10-Q Report for the fiscal quarter ended March 31, 2004) |
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10.6
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2004 Non-Employee Director Stock Grant Plan (Incorporated by reference to Exhibit 10.1 of the
Registrants Form 8-K Report dated September 22, 2004) |
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10.7
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Incentive and Retention Plan (Incorporated by reference to Exhibit 10.7 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2006) |
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10.8
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First Amended and Restated Credit Agreement, dated December 20, 2002, by and among Parallel
Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, Western
National Bank and BNP Paribas (Incorporated by reference to Exhibit 10.2 of Form 8-K of the
Registrant, dated December 20, 2002) |
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10.9
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Guaranty dated December 20, 2002, between Parallel, L.L.C. and First American Bank, SSB, as
Agent (Incorporated by reference to Exhibit 10.3 of Form 8-K of the Registrant, dated December
20, 2002) |
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10.10
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First Amendment to First Amended and Restated Credit Agreement, dated as of September 12,
2003, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First
American Bank, SSB, Western National Bank, and BNP Paribas (Incorporated by reference to
Exhibit 10.29 of Form 10-Q of the Registrant for the quarter ended September 30, 2003) |
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10.11
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Second Amended and Restated Credit Agreement, dated September 27, 2004, by and among
Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB,
BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit
10.1 of the Registrants Form 8-K Report dated September 27, 2004 and filed with the
Securities and Exchange Commission on October 1, 2004) |
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10.12
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Agreement of Limited Partnership of West Fork Pipeline Company LP (Incorporated by reference
to Exhibit 10.21 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004) |
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10.13
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First Amendment to Second Amended and Restated Credit Agreement, dated as of December 27,
2004, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First
American Bank, SSB, BNP Paribas, |
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No. |
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Description of Exhibit |
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Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit 10.1 of the
Registrants Form 8-K Report dated December 30, 2004 and filed with the Securities and
Exchange Commission on December 30, 2004) |
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10.14
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Second Amendment to Second Amended and Restated Credit Agreement, dated as of April 1, 2005,
by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American
Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference
to Exhibit 10.1 of the Registrants Form 8-K Report dated April 4, 2005 and filed with the
Securities and Exchange Commission on April 8, 2005) |
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10.15
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Third Amendment to Second Amended and Restated Credit Agreement (Incorporated by reference
to Exhibit 10.1 of the Registrants Form 8-K Report dated October 4, 2005 and filed with the
Securities and Exchange Commission on October 20, 2005) |
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10.16
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Purchase and Sale Agreement, dated as of October 14, 1005, among Parallel, L.P., Lynx
Production Company, Inc., Elton Resources, Inc., Cascade Energy Corporation, Chelsea Energy,
Inc., William P. Sutter, Trustee, William P. Sutter Trust, J. Leroy Bell, E. L. Brahaney,
Brent Beck, Cavic Interests, LLC and Stanley Talbott (Incorporated by reference to Exhibit
10.2 of the Registrants Form 8-K Report dated October 14, 2005 and filed with the Securities
and Exchange Commission on October 20, 2005) |
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10.17
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Ancillary Agreement to Purchase and Sale Agreement, dated October 14, 2005, between
Parallel, L.P. and Lynx Production Company, Inc. (Incorporated by reference to Exhibit 10.3 of
the Registrants Form 8-K Report dated October 14, 2005 and filed with the Securities and
Exchange Commission on October 20, 2005) |
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10.18
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Guarantee of Parallel, L.P., dated October 13, 2004 (Incorporated by reference to Exhibit
10.4 of the Registrants Form 8-K Report dated October 14, 2005 and filed with the Securities
and Exchange Commission on October 20, 2005) |
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10.19
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ISDA Master Agreement, dated as of October 13, 2005, between Parallel, L.P. and Citibank,
N.A. (Incorporated by reference to Exhibit 10.5 of the Registrants Form 8-K Report dated
October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005) |
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10.20
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Third Amended and Restated Credit Agreement, dated as of December 23, 2005, among Parallel
Petroleum Corporation, Parallel, L.P., Parallel, L.L.C. and Citibank Texas, N.A., BNP Paribas,
CitiBank F.S.B., Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland and
Fortis Capital Corp. (Incorporated by reference to Exhibit No. 10.1 of the Registrants Form
8-K Report, dated December 23, 2005, as filed with the Securities and Exchange Commission on
December 30, 2005) |
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10.21
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Second Lien Term Loan Agreement, dated November 15, 2005, among Parallel Petroleum
Corporation, Parallel, L.P., BNP Paribas and Citibank Texas, N.A. (Incorporated by reference
to Exhibit No. 10.4 of the Registrants Form 8-K Report, dated November 15, 2005, as filed
with the Securities and Exchange Commission on November 21, 2005) |
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10.22
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Intercreditor and Subordination Agreement, dated November 15, 2005, among Citibank Texas,
N.A., BNP Paribas, Parallel Petroleum Corporation, Parallel, L.P. and Parallel, L.L.C.
(Incorporated by reference to Exhibit No. 10.5 of the Registrants Form 8-K Report, dated
November 15, 2005, as filed with the Securities and Exchange Commission on November 21, 2005) |
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10.23
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Guaranty, dated as of December 23, 2005, made by Parallel, L.L.C. to and in favor of
Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.23 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2006) |
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10.24
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Third Amended and Restated Pledge Agreement, dated as of December 23, 2005, between
Parallel, L.L.C. and Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.24 of Form
10-K of the Registrant for the fiscal year ended December 31, 2006) |
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10.25
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Second Lien Guarantee and Collateral Agreement, dated as of November 15, 2005, made by
Parallel Petroleum Corporation and Parallel, L.P. to and in favor of BNP Paribas (Incorporated
by reference to Exhibit 10.25 of Form 10-K of the Registrant for the fiscal year ended
December 31, 2006) |
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No. |
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Description of Exhibit |
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10.26
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Third Amendment to Third Amended and Restated Credit Agreement, dated as of July 31, 2007,
among the Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank,
Comerica Bank, Bank of Scotland, and Fortis Capital Corp. (Incorporated by reference to
Exhibit 10.3 of the Registrants Current Report on Form 8-K filed on August 1, 2007) |
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10.27
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Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of November 30,
2007, among the Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank,
Comerica Bank, Bank of Scotland, and Fortis Capital Corp. (Incorporated by reference to
Exhibit 10.27 of Form S-4 of the Registrant, Registration No. 333-148465) |
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*10.28
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Hagerman Gas Gathering System Joint Venture Agreement, dated as of January 16, 2007, among
the Registrant, Feagan Gathering Company and Capstone Oil & Gas Company, L.P. |
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14
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Code of Ethics (Incorporated by reference to Exhibit No. 14 of the Registrants Form 10-K
Report for the fiscal year ended December 31, 2003 and filed with the Securities and Exchange
Commission on March 22, 2004) |
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*23.1
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Consent of BDO Seidman, LLP |
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*23.2
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Consent of Cawley Gillespie & Associates Inc. Independent Petroleum Engineers |
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*31.1
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Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of
the Sarbanes Oxley Act of 2002. |
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*31.2
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Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of
the Sarbanes Oxley Act of 2002. |
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*32.1
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Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes Oxley Act of 2002. |
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*32.2
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Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes Oxley Act of 2002. |