SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K [x] Annual Report Pursuant to Section 13 or 15 (d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 2003 [ ] 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: 0 - 13305 PARALLEL PETROLEUM CORPORATION ------------------------------------------------------ (Exact Name of Registrant as Specified in its Charter) Delaware 75-1971716 -------------------------------- ------------------- (State or Other Jurisdiction of (I.R.S. Employer Incorporation or Organization) Identification No.) 1004 N. Big Spring, Suite 400 Midland, Texas 79701 --------------------------------------- ---------- (Address of Principal Executive Offices (Zip Code) Registrant's Telephone Number, Including Area Code: (432) 684-3727 Securities Registered Pursuant to Section 12(b) of the Act: None Securities Registered Pursuant to Section 12(g) of the Act: Common Stock, $.01 par value Common Stock Purchase Warrants Rights to Purchase Series A Preferred Stock (Title of Class) 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 X No ------ ---- 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 registrant's 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. [ ] Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes No X ----- ---- The aggregate market value of voting and non-voting common equity held by non-affiliates of the Registrant as of June 30, 2003 was approximately $71,608,313, based on the last sale price of the common stock on the same date. At March 1, 2004 there were 25,224,005 shares of common stock outstanding. FORM 10-K PARALLEL PETROLEUM CORPORATION TABLE OF CONTENTS Item No. PART I Item 1. Business .........................................................1 Item 2. Properties.......................................................35 Item 3. Legal Proceedings................................................38 Item 4. Submission of Matters to a Vote of Security Holders..............38 PART II Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities...................39 Item 6. Selected Financial Data..........................................41 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.........................43 Item 7A. Quantitative and Qualitative Disclosures About Market Risk...........................................62 Item 8. Financial Statements and Supplementary Data......................64 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure..........65 Item 9A. Controls and Procedures..........................................66 PART III Item 10. Directors and Executive Officers of the Registrant...............67 Item 11. Executive Compensation...........................................73 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters .............82 Item 13. Certain Relationships and Related Transactions ..............85 Item 14. Principal Accountant Fees and Services...........................86 PART IV Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.................................................87 (i) Cautionary Statement Regarding Forward Looking Statements Some statements contained in this Annual Report on Form 10-K are "forward-looking statements". All statements other than statements of historical facts included in this report, including, without limitation, statements regarding planned capital expenditures, the availability of capital resources to fund capital expenditures, estimates of proved reserves, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. You can identify forward-looking statements by the use of forward-looking terminology like "may," "will," "expect," "intend," "anticipate," "budget", "estimate," "continue," "present value," "future" or "reserves" or other variations or comparable terminology. We believe the assumptions and expectations reflected in these forward-looking statements are reasonable. However, we cannot give any assurance that our 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: . fluctuations in prices of oil and gas; . future capital requirements and availability of financing; . geological concentration of our reserves; . risks associated with drilling and operating wells; . competition; . general economic conditions; . governmental regulations; . receipt of amounts owed to us by purchasers of our production and counterparties to our hedging contracts; . hedging decisions, including whether or not to hedge; . events similar to 911; . actions of third party co-owners of interests in properties in which we also own an interest; and . fluctuations in interest rates and availability of capital. For these and other reasons, actual results may differ materially from those projected or implied. 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, 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 and under "Risks Related to Our Business" beginning on page 21. (ii) PART I ------------------------------------------------------------------------------- ITEM 1. BUSINESS -------------------------------------------------------------------------------- About Our Company Parallel Petroleum Corporation is engaged in the acquisition, development, exploitation and production of oil and natural gas and, to a lesser extent, the domestic exploration for oil and natural gas. These activities are concentrated in three core areas: . the Permian Basin of west Texas and New Mexico; . Liberty County in east Texas; and . the onshore gulf coast area of south Texas. In 2003, we spent approximately $14.9 million on oil and gas related capital expenditures, a decrease of approximately 76% over that expended in 2002. See Note 3 to the Financial Statements. In December 2002, we acquired producing oil and gas properties located in Andrews County, Texas for a total of $46.1 million. Throughout this report, we refer to some terms that are commonly used and understood in the oil and gas industry. These terms are: . Mcf - thousand cubic feet of natural gas; . MMcf - million cubic feet of natural gas; . Bcf - billion cubic feet of natural gas; . Bbls - barrels of oil or other liquid hydrocarbons; . MBbl - thousand barrels of oil or other liquid hydrocarbons; . BOE - equivalent barrel of oil or 6 Mcf of natural gas for one barrel of oil; and . MBOE - thousand BOE. Parallel was incorporated in Texas on November 26, 1979, and reincorporated in the State of Delaware on December 18, 1994. -1- 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 the SEC at the SEC's Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site (http://www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers, including Parallel, that file electronically with the SEC. Our Internet address is http://www.parallel-petro.com. 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@parallel-petro.com, 1-800-299-3727. Recent Developments On December 23, 2003 we completed a private placement of 4.0 million shares of common stock at a price of $3.25 per share for total gross proceeds of $13.0 million before offering expenses. On November 25, 2003, our Board of Directors approved in principle the adoption of an employee retention/severance plan that will become effective January 1, 2004. The aggregate payments to all officers and employees will generally be 5% of an amount equal to the positive difference between the amount by which our net asset value per share at the time of the occurrence of a change of control exceeds the net asset value per share as of January 1, 2004, compounded annually at a rate equal to the annual industry average growth rate, plus 2%. Generally, we contemplate that a "change in control" will include events such as a merger, reorganization, liquidation or sale of substantially all of the assets of Parallel, or the acquisition by a third party of 50% or more of our outstanding voting securities. Proved Reserves as of December 31, 2003 Cawley Gillespie & Associates, Inc., an independent engineering firm, estimated the total proved reserves attributable to all of our oil and gas properties to be 12.1 million Bbls of oil and 16.3 Bcf of natural gas as of December 31, 2003. Based on oil and gas prices at December 31, 2003 and current operating and development costs, the present value of our pretax future net -2- revenues from these properties, discounted at 10%, was estimated to be approximately $147.8 million as of December 31, 2003. Approximately 82% of our proved reserves are oil and approximately 74% are categorized as proved developed reserves. About Our Strategy and Business From 1993 until mid 2002, our activities were concentrated in the onshore gulf coast area of south Texas. In June, 2002 we reexamined and revised our business strategy. We shifted the balance of our investments from properties having high rates of production in early years to properties with more consistent production over a longer term. We now emphasize reducing drilling risks by dedicating a smaller portion of our capital to high risk projects, while reserving the majority of our available capital for exploitation, enhancement and development drilling opportunities. Obtaining positions in long-lived oil and gas reserves is given priority over properties that might provide more cash flow in the early years of production, but which have shorter reserve lives. Our risk reduction efforts also include emphasizing acquisition possibilities over high risk exploration projects. Since the latter part of 2002, we have reduced the emphasis on high risk exploration efforts and we now focus on established geologic trends where we can utilize the engineering, operational, financial and technical expertise of our entire staff. Although we will continue to participate in exploratory drilling activities from time to time, reducing financial, reservoir, drilling and geological risks and diversifying our property portfolio are the principal criteria in the execution of our business plan. In summary, our current business plan: . focuses on projects having less geological risk; . emphasizes exploitation and enhancement activities; . focuses on acquiring producing properties; and . expands the scope of our operations by diversifying our exploratory and development efforts, both in and outside of our current areas of operation. An integral part of our business strategy includes exploitation and enhancement activities. Exploitation and enhancement activities include: . operational enhancements, such as surface facility reconfiguration, and the installation of new or additional compression equipment; . workovers; . well recompletions; -3- . behind-pipe recompletions; . refracing (restimulating a producing formation within an existing wellbore to enhance production and add reserves); . installation of injection wells and related facilities; . development well drilling (infill drilling); . cost reduction programs; and . secondary recovery operations, including waterfloods. When we initiate exploitation and enhancement activities on our existing producing properties, we first establish and maintain an ongoing program of oil and gas well reviews with the objective of maximizing the output of existing wells. Oil and gas wells usually generate their highest volumes during the earlier stages of production after which production begins to decline. Enhancement and remedial work can be undertaken to restore varying amounts of the lost production or reduce the rate of production decline. Our approach to producing property acquisitions, and the size and timing of any acquisition, is dependent upon market conditions in the domestic oil and gas industry. Generally, during periods of moderate to high prices for oil and gas, we believe that oil and gas acquisition opportunities are not as favorable to a prospective purchaser as they are when market conditions are depressed. Producing properties that we identify and attempt to acquire will include properties that have proved undeveloped and behind-pipe reserves, operational enhancement potential, long-lived reserves, multiple pay-zone exploitation and development drilling opportunities, and the potential for operating control. Selecting and acquiring producing properties having these characteristics will diversify and improve the quality of our property portfolio. Although purchases of producing properties involve less risk than drilling, there is a risk that estimates of future prices or costs, reserves, production rates or other criteria upon which we have based our investment decision may prove to be inaccurate. In addition to acquisitions of producing properties, our business strategy also includes seeking opportunities to negotiate and enter into work to earn, joint venture and similar agreements with third parties for development operations on producing properties. Our sources for possible acquisitions of leases and prospects include independent landmen, independent oil and gas operators, geologists and engineers. We also evaluate properties that become available for purchase from major oil companies. If our review of an undeveloped lease or prospect or a producing property indicates that it may have geological characteristics favorable for 3-D seismic analysis, we may decide to acquire a working interest in -4- the property or an option to acquire a working interest. In the case of producing properties, we also seek properties that we believe are underperforming relative to their potential. To reduce our financial exposure in any one prospect, we may enter into co-ownership arrangements with third parties. These arrangements are common in the industry and enable us to participate in more prospects and share the drilling and related costs and dry-hole risks with other participants. From time to time, we sell prospects to third parties or farm-out prospects and retain an interest in revenues from these prospects. As we have in the past, we will continue to: (1) Use Advanced Technologies. We believe the use of 3-D seismic surveys and other advanced technologies provides us with a risk management tool. We believe that our use of these technologies in exploring for and developing oil and 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 reserves that might not otherwise be discovered. Generally, 3-D seismic surveys provide more accurate and comprehensive information to evaluate drilling prospects than conventional 2-D seismic technology. We evaluate substantially all of our exploratory prospects using 3-D seismic technology. On some exploratory prospects, we also use amplitude versus offset, or AVO analysis. AVO analysis shows the high contrast between sands and shales and assists in determining the presence of natural gas in potential reservoir sands. We believe that using 3-D seismic, AVO and other technologies gives us a competitive advantage because of the increased likelihood of successful drilling. When we evaluate exploratory prospects in geographical areas where the use of 3-D seismic and other advanced technologies are not likely to provide any advantages, we use traditional evaluation methods, such as 2-D seismic technology. (2) Serve as Geophysical Operator. We prefer to serve as the geophysical operator on projects located in areas where we have experience using 3-D seismic technology. By doing so, we control the design, acquisition, processing and interpretation of 3-D surveys and, in most cases, determine drilling locations and well depths. The integrity of 3-D seismic analysis in our projects is enhanced by emphasizing quality controls throughout the data acquisition, processing and interpretation phases. We retain experienced outside consultants and participate with knowledgeable joint working interest owners when we acquire, process and interpret 3-D seismic surveys. When -5- possible, we also attempt to correlate or model the interpretations of 3-D seismic surveys with wells previously drilled on or near the prospect being evaluated. (3) Conduct Exploratory Activities. Although we do not intend to emphasize exploratory drilling to the extent we have in the past, when we do undertake exploratory projects, we will continue to focus on prospects: . having known geological and reservoir characteristics; . being 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 . having a potentially meaningful impact on our reserves. When economic conditions are favorable and when we have sufficient capital resources, we believe we can maximize the value of our properties by accelerating drilling activities. This provides us an opportunity to replace reserves at a more rapid pace than existing reserves are produced. Drilling, Production and Other Activities in 2003 2003 Drilling Activity Number of Number of Wells Gross Waiting on Completion Gross Gross Area Depth Range (feet) Wells Drilled at December 31, 2003 Productive Wells Dry Wells --------------------------------- ---------------------- --------------- ---------------------- ----------------- ----------- North Texas Barnett Shale 7,000 - 8,000 1 1 - - Permian Basin Abo Gas 4,300 - 4,500 1 1 - - Diamond M (Shallow) 2,400 - 3,500 3 - 3 - East Texas Cook Mountain 11,000 - 15,000 5 - 2 3 Onshore Gulf Coast of Texas Yegua 6,300 - 13,000 0 - - - Shallow Frio 3,000 - 6,300 14 4 6 4 Deep Frio 8,000 - 11,000 2 1 - 1 Other 6,000 - 6,000 1 - - 1 ------- -------- ------- ------- 27 7 11 9 ======= ======== ======= ======= From 1993 until mid 2002, we concentrated our activities in the Yegua/Frio/Wilcox gas trends in the onshore Gulf Coast area of south Texas in Dewitt, Jackson, Lavaca, Victoria and Wharton Counties. Substantially all of our drilling success in south Texas has been in the Yegua/Frio gas trend and we intend to continue drilling additional lower risk 3-D seismic development wells in this trend. Although the successful wells we drilled in the Yegua/Frio trend provided quick payouts of our drilling and completion costs, the reserve lives of the properties in this area have proven to be very short as compared to our properties in the Permian Basin. -6- As we announced in October 2003, consistent with our strategy of reducing geologic risk, we began to diversify our exploration efforts into other oil and gas trends. However, and as planned, the majority of our drilling in 2003 was in south and east Texas. We believe we can more fully develop our existing producing properties in the Permian Basin of west Texas, which have been proven by previous drilling. Collectively, our Permian Basin properties include approximately 39,000 gross (29,000 net) developed acres, which will provide significant exploitation and development opportunities for both oil and gas. Additionally, our Permian Basin properties have longer reserve lives than our South Texas properties. Our exploitation and enhancement efforts are conducted primarily on our properties in the Permian Basin of west Texas. We own working interests in these properties ranging from 15.0% to 100%. During 2003, our Permian Basin activities included: . recompleting existing wellbores; . restimulating producing reservoirs; . identifying potential infill drilling locations; . making mechanical improvements to surface facilities and downhole equipment; and . reviewing the feasibility of applying new drilling and production technologies that could either improve recovery potential or result in the discovery of a new reservoir. As part of our remedial and enhancement operations in the Permian Basin, we routinely review the performance and economics of our oil and gas properties and, from time to time, we may also renegotiate gas purchase contracts or reconfigure gathering lines. When necessary, we take corrective action, such as: . shutting in temporarily uneconomic properties; . plugging wells we believe to be permanently impaired or depleted; . terminating oil and gas leases that are uneconomic under existing operating conditions; and/or . selling properties to third parties. -7- Drilling and Acquisition Costs The table below shows our oil and gas property acquisition, exploration and development costs for the periods indicated. Year Ended December 31, -------------------------------------------------------------------- 2003 2002 2001 2000(1) 1999(1) ------------ ------------ ------------ ------------ ------------ (in thousands) Transfers from (to) undeveloped eases held for sale(1) $ - $ - $ - $ 2,128 $ (2,128) Proved property acquisition costs 2,209 48,044 27 23 42 Unproved property acquisition costs 3,831 2,295 3,420 3,372 1,979 Exploration costs 3,240 1,291 6,820 2,163 1,856 Development costs 5,650 9,308 1,203 1,087 639 -------- -------- -------- -------- -------- $ 14,930 $ 60,938 $ 11,470 $ 8,773 $ 2,388 ======== ======== ======== ======== ======== __________ (1) Reflects costs associated with assets being held for sale in 1999 and transferred back to oil and gas property in 2000. Actual capital expenditures during 2000 and 1999, excluding transfers, were approximately $6.6 million and $4.5 million, respectively. Capital Investments for 2004 Our 2004 capital investment budget for properties we owned at March 1, 2004 is estimated to be approximately $17.0 million, which includes less than $1.0 million for the purchase of undeveloped leasehold acreage in our areas of activity. The budget will be funded from our estimated operating cash flows, which is based on anticipated commodity prices and forecasted production volumes. The amount and timing of expenditures are subject to change based upon market conditions, results of expenditures, new opportunities and other factors. On a geographic basis, approximately 59% of our projected 2004 capital investment program will be directed toward oil and gas reserves in the Permian Basin, 24% to gas reserves in east Texas and in the Yegua/Frio/Wilcox gas trend onshore the Gulf Coast area of south Texas, 15% for north Texas Barnett Shale gas project, and 2% to other projects. Permian Basin of West Texas The Permian Basin of west Texas generated approximately 57% of our 2003 production and represented approximately 84% of our reserve value as of December 31, 2003. Our significant producing properties in the Permian Basin are described below. . Fullerton Field, Andrews County -We acquired this non-operated property in December 2002 and it represented approximately 37% of our 2003 production and 57% of our reserve value as of December 31, 2003. Production is from the San Andres formation at a depth of 4,400 feet and consists of 128 producing wells supported by 80 water injection wells located on nine contiguous leases -8- containing approximately 3,640 gross acres. A total of 41 water-frac stimulations were performed during the period from mid-February 2003 through the end of January 2004. We have accelerated activity to two refracs per week and expect to refrac an additional 80 wells through the end of 2004. We are also evaluating the potential for infill drilling the San Andres formation at a depth of approximately 4,500 feet. Our working interest in these properties ranges from 25% to 85%. We have budgeted approximately $2.0 million, net to our interest, for this project in 2004. . Diamond M Shallow Leases, Scurry County - This operated property was acquired in December, 2001. It represented less than 1% of our 2003 production and approximately 8% of our reserve value as of December 31, 2003. Eight shallow leases comprise approximately 2,600 gross productive acres in the Glorietta, Clearfork and Wichita Albany intervals, which range in depth from 2,450 feet to 4,000 feet. Prior to our acquisition of this property, these intervals had produced approximately 4.0 million barrels of oil from a total of 130 wells on 20 acre spacing and a random waterflood pattern. In January 2004, we commenced a 30 well infill drilling program that we expect to complete by the fourth quarter of 2004. Depending upon the results of this program, we presently anticipate drilling approximately 60 additional wells prior to the end of 2005. We anticipate that we will spend on this project, net to our 66% working interest, approximately $19.0 million over the next three years, $6.5 million of which is budgeted for 2004. . Lion Diamond M Canyon Unit, Scurry County - This operated property includes the same surface acreage as our Diamond M Shallow leases and is in its early stage of development. It generated approximately 4% of our 2003 production and represented approximately 3% of our reserve value as of December 31, 2003. The Lion Diamond M Canyon Unit consists of approximately 5,500 gross acres in the Canyon Reef formation at a depth of approximately 6,700 feet, and is located between the Kinder Morgan, Inc. operated SACROC Unit to the north and the ExxonMobil Corporation operated Sharon Ridge Unit to the south. The SACROC Unit and Sharon Ridge Unit were both discovered in 1948 and have produced approximately 1.3 billion barrels of oil and 250.0 million barrels of oil, respectively. The Lion Diamond M Canyon Unit, also discovered in 1948, has produced 44.0 million barrels of oil. Most of the original 145 wells initially penetrated only the top 50 feet of the reef, with deeper evaluation accomplished through a limited number of well deepenings. The unit was pumping a total of 150 barrels of oil per day from 15 producing wells prior to commencement of our operations and is currently spaced on 40 acre proration units. -9- We have identified 42 mechanically viable Canyon Reef wells as deepening candidates. The first two of these workovers have recently been completed. Both wells were deepened approximately 150 feet. The combined current production rate of the two wells has stabilized at approximately 50 gross (30 net) BOE per day. We are currently expanding the field's injection and facility fluid handling capacity to accommodate increased volumes from future workovers. We are also preparing to shoot a 3-D seismic survey utilizing both compressional and shear wave technology. We anticipate that we will spend on this project, net to our 66% working interest, approximately $8.0 million over the next three years, of which $1.0 million is budgeted for 2004. However, this program and our expenditures could be accelerated if future deepenings exceed our current economic model. Onshore Gulf Coast of South Texas This area generated approximately 27% of our 2003 production and represented approximately 12% of our reserve value as of December 31, 2003. From 1993 to June 2002, this area had been our primary focus. However, because of the high decline rate and short-lived reserves, we are decreasing our re-investment in this area and are now re-deploying a majority of the cash flow from this area to the acquisition, development and exploitation of longer-lived oil and natural gas reserves. . Yegua/Frio Gas Project, Jackson and Wharton Counties - This non-operated project primarily focuses on natural gas production from the Yegua and Frio trends at depths ranging from 3,000 feet to 16,000 feet. A new deep Frio prospect well, the Cornelius No. 1, is currently drilling to a projected depth of 16,000 feet. Our working interest in the well is approximately 20%. We have approximately 3 Yegua and 7 Frio 3-D seismic natural gas prospects remaining to be drilled. We expect drilling operations on 1 Yegua prospect to begin in the second quarter of 2004. Our working interest in the well is approximately 30%. We have budgeted $2.0 million, net to our interest, for the drilling of these prospects, the majority of which will be spent in 2004. East Texas . Cook Mountain Gas Project, Liberty County - We commenced this non-operated project in 2002 and it represented approximately 13% of our 2003 production and 3% of our reserve value as of December 31, 2003. We have participated in eight Cook Mountain natural gas wells, five of which have been successful. We have approximately 5 additional 3-D seismic Cook Mountain natural gas prospects remaining to be drilled. We have revised the budget and plan to spend $1.0 million for the drilling of these prospects, the majority of which will be spent in 2004. -10- New Undeveloped Projects All four of the following new projects have been acquired since June 2002 and no production or proved reserves have been recognized on these projects as of December 31, 2003. . North Texas Barnett Shale Gas Project, Tarrant County - We acquired our initial interest in this non-operated project in April 2003 and drilled an initial well in May 2003. We are in the process of acquiring additional leasehold on the project and drilling activity is anticipated to resume during the third quarter of 2004. Our current leasehold on the project is approximately 5,000 gross acres with natural gas targets at a depth of approximately 8,000 feet. We anticipate that we will spend on this project, net to our 28% working interest, approximately $16.0 million over the next three years, of which $2.5 million is budgeted for 2004. . Utah Oil and Gas Project - We have increased our acreage position in this project to approximately 125,000 gross acres. It is a multiple zone project consisting of both oil and natural gas targets at a depth of less than 6,000 feet. We continue to build our leasehold position and geological data base. We expect to spud the first exploratory well in this project as early as the third quarter of 2004. We own and operate 100% of this project and estimate that the cost to drill and complete a well will be approximately $0.5 million. Our budget on this project for 2004 is approximately $0.5 million. . New Mexico Gas Project - This non-operated project consists of approximately 50,000 gross acres with the primary target being the Abo formation at a depth of approximately 5,000 feet. The Abo formation is a known natural gas-producing reservoir but historically has been marginally economic due to low per-well producing rates and low natural gas prices. Since December 2003, we have participated in three Abo formation natural gas wells that have been drilled and are in the process of being completed. We expect this project to become commercial because of the application of new horizontal drilling and hydraulic fracture stimulation technologies. Depending on production results, we expect accelerated development in 2004 of this potential long-life natural gas project. Our working interest in the project is approximately 8.5%. Our budget on this project for 2004 is approximately $0.5 million. . Cotton Valley Reef Gas Project, Texas - We acquired an interest in this non-operated 3-D seismic natural gas project in November 2003. The objective is the Cotton Valley barrier reef facies found between the depths of 16,000 and 18,000 feet on the flank of the east Texas Basin as it existed in the Jurassic time. Nearby, existing long-life natural gas fields, with impressive production profiles, produce from Cotton Valley patch reef facies; however, this project targets a much larger, seaward barrier reef reservoir. This project consists of approximately 5,000 gross acres and the first well is expected to spud during the second quarter of 2004. We -11- have budgeted approximately $1.0 million in 2004, net to our working interest, for the drilling of the first of nine potential prospects within this project. Our working interest in the remaining prospects will be approximately 12.0%. Oil and Natural Gas Prices Our revenues, profitability and cash flows are highly dependent on the prices we receive for our oil and natural gas. Generally, oil and natural gas prices improved and stabilized during the period from mid-2000 to the third quarter of 2001, when prices began to decline. During the first quarter of 2002, prices began to increase again and this upward trend in price has continued. The average prices we received for the oil and natural gas we produced in 2003, 2002 and 2001 are shown in the table below. Average Price Received for the Year Ended December 31, ---------------------------------------- 2003 2002 2001 ------------ ------------ ------------ Oil (Bbl) $ 29.11 $ 24.59 $ 24.80 Natural gas (Mcf) $ 5.40 $ 3.33 $ 4.41 The average price we received for our oil sales at March 1, 2004 was approximately $30.92 per Bbl, excluding our hedging activities. At the same date, the average price we were receiving for our natural gas was approximately $5.19 per Mcf, excluding our hedging activities. There is substantial uncertainty regarding future oil and gas prices and we can provide no assurance that prices will remain at current levels. We have entered into hedge contracts in an attempt to reduce the risk of fluctuating oil and gas prices and interest rates. In 2003, approximately 47% of our daily production was natural gas and 53% was oil. Executive Officers of Parallel At March 11, 2004, Parallel's executive officers were Thomas R. Cambridge, Larry C. Oldham, Donald E. Tiffin, Eric A. Bayley, John S. Rutherford and Steven D. Foster. Thomas R. Cambridge, age 68, is the Chairman of the Board of Directors of Parallel. He is an independent petroleum geologist engaged in the exploration for, development and production of oil and natural gas. From 1970 until 1990, such activities were carried out primarily through Cambridge & Nail Partnership, a Texas general partnership. Since 1990, such activities have been carried out through Cambridge Production, Inc., a Texas corporation. Mr. Cambridge has served as a Director of Parallel since February 1985; as President and Chief Executive Officer during the period from October 1985 to October 1994 and October 1985 to January 2004 respectively; and as Chairman of the Board of Directors since October 1985. He -12- received a Bachelors degree in geology from the University of Nebraska in 1958 and a Masters of Science degree in 1960. Larry C. Oldham, age 50, is a founder of Parallel. He has served as an officer and Director since Parallel's formation in 1979. He served as Executive Vice President until October, 1994 when he became President. As of January 1, 2004 he replaced Thomas R. Cambridge as Chief Executive Officer and continued his current position as President. Before Parallel's formation, Mr. Oldham was employed by Dorchester Gas Corporation from 1976 to 1979 and KPMG Peat Marwick LLP during 1975 to 1976. He received a Bachelor of Business Administration degree from West Texas State University in 1975. Mr. Oldham is a member of the Permian Basin Landman's Association. Donald E. Tiffin, age 46, served as Vice President of Business Development from June, 2002 until January, 2004 when he became the Chief Operating Officer of Parallel. From August, 1999 until May, 2002, Mr. Tiffin served as General Manager of First Permian, L.P. 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. Eric A. Bayley, age 55, has been Vice President of Corporate Engineering since July, 2001. From October, 1993 until July, 2001, Mr. Bayley was employed as Manager of Engineering. From June, 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 Master's of Business Administration degree. John S. Rutherford, age 44, 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 Parallel's 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 Master's degree in Business Administration. Steven D. Foster, age 48, 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. 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. The term of our officers expires at Parallel's annual meeting of Directors or when their respective successors are duly elected and qualified. There are no family relationships among our executive officers. -13- Employees In 2003, we added nine new employees. At March 1, 2004, Parallel had twenty-four full time employees. Mr. Cambridge serves in the capacity of a consultant and not as a full-time employee. Parallel also retains independent land, geological, geophysical and engineering consultants and expects to continue to do so in the future. Additionally, Parallel retains four contract pumpers on a month-to-month basis. 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, 2003. Exploratory Wells (1) Development Wells (2) ----------------------------------- ----------------------------------- Productive Dry Productive Dry ----------------- ----------------- ----------------- ----------------- Year Ended December 31, Gross Net Gross Net Gross Net Gross Net ------------ -------- ------- -------- -------- -------- -------- -------- -------- 2003 15.0 5.05 8.0 2.09 3.0 2.6 1.0 0.25 2002 12.0 3.10 3.0 0.70 4.0 2.3 - - 2001 18.0 4.10 13.0 3.41 - - - - ---------------- (1) An exploratory well is a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. (2) A development well is a well drilled within the proved area of an oil or 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. At March 3, 2004, we were participating in the completion of 7 gross (3.68 net) gas wells in Jackson, Liberty, Scurry and Tarrant Counties, Texas and Eddy County, New Mexico. Volumes, Prices and Lifting Costs The following table shows certain information about our oil and gas production, average sales prices per Mcf of gas and Bbl of oil and the average lifting cost per BOE for the three-year period ended December 31, 2003. -14- Year Ended December 31, ---------------------------------------------- 2003 2002 2001 --------------- -------------- -------------- (in thousands except per unit data) Production, Prices and Lifting Costs: Oil (Bbls) 629 131 138 Natural gas (Mcf) 3,356 2,670 3,266 BOE 1,188 576 682 Oil price (per Bbl)(1) $ 29.11 $ 24.59 $ 24.80 Natural gas price (per Mcf)(1) $ 5.40 $ 3.33 $ 4.41 BOE price(1) $ 30.66 $ 21.03 $ 26.13 Average Production (lifting) Cost per BOE(2) $ 7.07 $ 5.00 $ 5.74 _____________ (1) Average price received at the wellhead for our oil and natural gas. (2) The increase in 2003 is attributable to increased lifting costs associated with our waterflood projects. The following summarizes our revenue for each of the three years ended December 31 by product sold. 2003 2002 2001 ------------ ------------- ------------- (in thousands) Oil revenue $ 18,300 $ 3,217 $ 3,429 Oil hedge (1,659) - - Gas revenue 18,121 8,889 14,411 Gas hedge (907) - - ------------ ------------- ------------- $ 33,855 $ 12,106 $ 17,840 ============ ============= ============= Our gas sales in 2003 represented approximately 50% of our combined oil and gas sales for the year ended December 31, 2003 as compared to 73% in 2002. Markets and Customers Our oil and 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. -15- In the table below, we show the purchasers that accounted for 10% or more of our revenues during the specified years. 2003 2002 2001 ------------- ------------ ------------ Allegro Investments, Inc. 30% 31% 38% Pure Resources, Inc. - 16% 23% Sue Ann Production - 11% 25% Texland Petroleum, Inc. 33% - - We do not believe the loss of any one of our purchasers would materially affect our ability to sell the oil and gas we produce. Other purchasers are available in our areas of operations. Our future ability to market our oil and gas production depends upon the availability and capacity of gas gathering systems and pipelines and other transportation facilities. We do not currently own or operate our own pipelines or transportation facilities. We are dependent on third parties to transport our products. We are not obligated to provide a fixed and determinable quantity of oil or 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 14,882 square feet of office space at 1004 North Big Spring, Suite 400, Midland, Texas 79701. Our current rental rate is $8,931 per month. In December 2003, we amended our lease to add an additional 6,758 square feet of space. Commencing August 1, 2004, the total monthly rental rate for our office space will be $13,474. The lease expires August 31, 2006. From January through May, 2003, we continued to make monthly lease payments of $4,489 for our former office space. The lease agreement was terminated May 31, 2003. Competition The oil and gas industry is highly competitive, particularly in the areas of acquiring exploration and development prospects and producing properties. The principal means of competing for the acquisition of oil and gas properties are the amount and terms of the consideration offered. Our competitors include major oil companies, independent oil and gas firms and individual producers and operators. Many of our competitors have financial resources, staffs and facilities much larger than ours. -16- We are also affected by competition for drilling rigs and the availability of related equipment. With relatively high oil and gas prices, the oil and gas industry typically experiences shortages of drilling rigs, equipment, pipe and qualified field personnel. We are unable to predict when or to what extent our exploration and development activities will be affected by rig, equipment or personnel shortages. Intense competition among independent oil and gas producers requires us to react quickly to available exploration and acquisition opportunities. We try to position for these opportunities by maintaining: . adequate capital resources for projects in our primary areas of operations; . the technological capabilities to conduct a thorough evaluation of a particular project; and . 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 gas are: . leasehold prospects under which oil and gas reserves may be discovered; . drilling rigs and related equipment to explore for such reserves; and . knowledgeable and experienced personnel to conduct all phases of oil and gas operations. Oil and Gas Regulations Our operations are regulated by certain federal and state agencies. Oil and gas production and related operations are or have been subject to: . price controls; . taxes; and . environmental and other laws relating to the oil and gas industry. We cannot predict how existing laws and regulations may be interpreted by enforcement 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 gas exploration, production and related operations are subject to extensive rules and regulations that are enforced by federal, state and local agencies. Failure to comply with these rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability. Because -17- 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 gas are also imposed. These states also have statutes or regulations addressing conservation matters, including provisions for: . the unitization or pooling of oil and gas properties; . the establishment of maximum rates of production from oil and gas wells; and . 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 regulates interstate and certain intrastate gas transportation rates and services conditions, which affect the marketing of our 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 FERC's purposes in issuing the orders was to increase competition in all phases of the 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 FERC's 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 gas marketing efforts. Generally, Order 636 has eliminated or substantially reduced the interstate pipelines' traditional role as wholesalers of gas, and has substantially increased competition and volatility in gas markets. While significant regulatory uncertainty remains, Order 636 may ultimately enhance our ability to market and transport our 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 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. -18- We are required to comply with various federal and state regulations regarding plugging and abandonment of oil and 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: . require prior governmental authorization for certain activities; . limit or prohibit activities because of protected areas or species; . impose substantial liabilities for pollution related to our operations or properties; and . 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 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: . containment or cleanup; . personal injury; . property damage; and . penalties assessed or other claims sought for natural resource damages. The following are examples of some environmental laws that potentially impact our operations. . Water. The Oil Pollution Act, or OPA, was enacted in 1990 and amends provisions of the Federal Water Pollution Control Act of 1972 and other statutes as they pertain to prevention of and response to major oil spills. The OPA -19- 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 Parallel. States in which Parallel operates 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 Parallel. 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 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 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. . Solid Waste. Parallel generates non-hazardous solid wastes that fall under the requirements of the Federal Resource Conservation and Recovery Act and comparable state statutes. 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 govern 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 Parallel incurring additional capital expenditures or operating expenses. . 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 -20- 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 CERCLA's definition of a hazardous substance. We may be jointly and severally liable under CERCLA for all or part of the costs required cleaning 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 Parallel's hazardous substances occurred. Parallel may also fall into the category of a current owner or operator. We currently own or lease numerous properties that for many years have been used for exploring and producing oil and 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. Risks Related to Our Business The volatility of the oil and 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 gas. In recent years, oil and gas prices and, therefore, the level of drilling, exploration, development and production, have been extremely volatile. Any significant or extended decline in oil and/or 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 gas industry results from numerous factors over which we have no control, including; . 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; . the cost of exploring for, producing and transporting oil and natural gas; . the level and price of foreign oil and natural gas transportation; . available pipeline and other oil and natural gas transportation capacity; . weather conditions; -21- . international political, military, regulatory and economic conditions; . the level of consumer demand; . the price and the availability of alternative fuels; . the effect of worldwide energy conservation measures; and . the ability of oil and natural gas companies to raise capital. Significant declines in oil and natural gas prices for an extended period may: . impair our financial condition, liquidity, ability to finance planned capital expenditures and results of operations; . reduce the amount of oil and natural gas that we can produce economically; . cause us to delay or postpone some of our capital projects; . reduce our revenues, operating income and cash flow; and . reduce the carrying value of our oil and natural gas properties. No assurance can be given that current levels of oil and gas prices will continue. We expect oil and gas prices, as well as the oil and gas industry generally, to continue to be volatile. We must replace oil and 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 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 gas reserves to replace reserves being depleted by production. No assurance can be given that we'll be able to find and develop or acquire additional reserves on an economical basis. If we cannot economically replace our reserves, our results of operations may be materially adversely affected. 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 gas in an exact way. Accordingly, oil and 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 -22- quantities of oil and 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 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 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 gas properties also will be affected by factors such as: . actual prices we receive for oil and gas; . the amount and timing of actual production; . supply and demand of oil and gas; . limits of increases in consumption by gas purchasers; and . 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 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 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: . seeking to acquire desirable producing properties or new leases for future exploration; -23- . marketing our oil and natural gas production; . integrating new technologies; and . 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 companies. These companies may be able to pay more for 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. Substantially all of our business activities are conducted through joint operating agreements under which we own partial interests in oil and gas wells. At December 31, 2003, we owned interests in 148 gross (110.9 net) producing oil and gas wells for which we were the operator and 427 gross (194.9 net) producing oil and gas wells where we were not the operator. If we do not operate wells in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties. The failure of an operator of our wells to adequately perform operations, or an operator's breach of the applicable agreements, could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator's: . timing and amount of capital expenditures; . expertise and financial resources; . inclusion of other participants in drilling wells; and . use of technology. -24- Since we do not have a majority interest in most wells we do not operate, we may not be in a position to remove the operator in the event of poor performance. Our business involves many operating risks, which may result in substantial losses, and insurance may be unavailable or inadequate to protect us against these risks. Our operations are subject to hazards and risks inherent in drilling for, producing and transporting oil and natural gas, such as: . fires; . natural disasters; . explosions; . pressure forcing oil or natural gas out of the wellbore at a dangerous velocity coupled with the potential for fire or explosion; . weather; . failure of oilfield drilling and service tools; . changes in underground pressure in a formation that causes the surface to collapse or crater; . pipeline ruptures or cement failures; . environmental hazards such as natural gas leaks, oil spills and discharges of toxic gases; and . availability of needed equipment at acceptable prices, including steel tubular products. Any of these risks can cause substantial losses resulting from: . injury or loss of life; . damage to and destruction of property, natural resources and equipment; . pollution and other environmental damage; . regulatory investigations and penalties; . suspension of our operations; and -25- . repair and remediation costs. We do not insure against the loss of oil or natural gas reserves as a result of operating hazards or insure against business interruption. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operations. The oil and gas industry is capital intensive. The oil and gas industry is capital intensive. We make substantial capital expenditures for the acquisition, exploration for and development of oil and gas reserves. Historically, we have financed capital expenditures primarily with cash generated by operations, proceeds from bank borrowings and sales of our equity securities. In addition, we may consider selling non-core assets to raise additional operating capital. From time to time, we may also reduce our ownership interests in 3-D seismic and other projects in order to reduce our capital expenditure requirements, depending on our working capital needs. Our cash flow from operations and access to capital is subject to a number of variables, including: . our proved reserves; . the level of oil and gas we are able to produce from existing wells; . the prices at which oil and gas are sold; and . 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 decreases as a result of lower oil and 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, sales of debt or equity securities or other forms of financing. There can be no assurance as to the availability or terms of any additional financing. 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. Our business strategy includes growing our reserve base through acquisitions. Our failure to integrate acquired businesses successfully into our existing business, or the expense -26- 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. 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 gas gathering systems and 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. We are subject to many restrictions under our revolving credit facility. As required by our revolving credit facility with our bank lenders, we have pledged substantially all of our oil and natural gas properties as collateral to secure the payment of our indebtedness. 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. The revolving credit facility prohibits us from declaring or paying dividends on our common stock, but we are permitted to pay dividends on our outstanding shares of 6% convertible preferred stock if we are not in default under the revolving credit facility. Although we are currently in compliance with these covenants, 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. Our failure to comply with any of the restrictions and covenants under the revolving credit facility could result in a default under the revolving credit facility, which could cause all of our existing indebtedness to be immediately due and payable. The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders, based upon projected revenues from the oil and gas properties securing our loan. The lenders can adjust the borrowing base and the borrowings -27- 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 each lender. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other oil and gas properties as additional collateral. We do not currently have any substantial unpledged properties and no assurance can be given that we would be able to make any mandatory principal prepayments required under the revolving credit facility. 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, at December 31, 2003, approximately 84% of the discounted present value of our proved reserves were 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 gas produced from the wells. Hedging 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 swap, floor, and collar hedging arrangements that generally result in a fixed price or a range of minimum and maximum price limits over a specified time period. Hedging contracts limit the benefits we will realize if actual prices rise above the contract price. Our hedging arrangements may expose us to the risk of financial loss in certain circumstances. In a typical hedge transaction, the hedging party will have the right to receive from the counterparty to the hedge, the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, the hedging party is required to pay the counterparty this difference multiplied by the quantity hedged. In this case, if we are the hedging party we would be required to pay the difference regardless of whether we had sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though the payments are not offset by sales of production. Hedging will also prevent us from receiving the full advantage of increases in oil or gas prices above the fixed amount specified in the hedge. In addition, these transactions may expose us to the risk of financial loss in certain circumstances, including instances in which: . production is less than expected; . there is a widening of price differentials between delivery points for our production and the delivery point assumed in the arrangement; . the counterparties to our future contracts fail to perform under the contract; or -28- . a sudden, unexpected event materially impacts oil or natural gas prices. In the past, some of our hedging 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 natural gas and oil prices. 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 gas industry significantly affects our operations. In particular, our oil and natural gas exploration, development and production, 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: . discharge permits for drilling operations; . drilling bonds; . spacing of wells; . unitization and pooling of properties; . environmental protection; . reports concerning operations; and . taxation. Under these laws and regulations, we could be liable for: . personal injuries; . property damage; . oil spills; . discharge of hazardous materials; . reclamation costs; . remediation and clean-up costs; and . other environmental damages. -29- Failure to comply with these laws and regulations also may result in the suspension or termination 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. Declining oil and 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 gas operations. This means that we capitalize the costs to acquire, explore for and develop oil and gas properties. Under full cost accounting rules, the capitalized costs of oil and 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 gas production at unescalated oil and gas prices in effect at the end of each fiscal quarter, with effect given to cash flow hedge positions. If capitalized costs of oil and gas properties, as adjusted for asset retirement obligations, 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. Impairment charges cannot be restored by subsequent increases in the prices of oil and gas. The risk that we will be required to write down the carrying value of our oil and gas properties increases when oil and gas prices decline. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves. We did not recognize impairment in 2003. 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 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 measure may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all. -30- 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. 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 or long term contractual arrangements with any of our officers or other key employees. In periods of improving market conditions, our ability to obtain and retain qualified consultants on a timely basis may be adversely affected. 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. Our Oil and Gas Operations Are Subject to Many Inherent Risks Oil and 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 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 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 gas. These hazards and risks include: . encountering unusual or unexpected formations and pressures; . explosions, blowouts and fires; . pipe and tubular failures and casing collapses; . environmental pollution; and . personal injuries. -31- Any one of these potential hazards could result in accidents, environmental damage, personal injury, property damage and other harm that could result in substantial liabilities to us. As is customary in the industry, we maintain insurance against some, but not all, of these hazards. We maintain general liability insurance and obtain insurance against blowouts on a well-by-well basis. We do not carry insurance against pollution hazards. If we sustain an uninsured loss or liability, our ability to operate could be materially adversely affected. Our oil and gas operations are not subject to renegotiation of profits or termination of contracts at the election of the federal government. Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests. Our revolving credit facility contains a number of significant covenants that, among other things, restrict our ability to: . dispose of assets; . incur additional indebtedness; . restrictions on all retained earnings and net income for payment of dividends on our common stock; . create liens on our assets; . enter into specified investments or acquisitions; . repurchase, redeem or retire our capital stock or other securities; . merge or consolidate, or transfer all or substantially all of our assets and the assets of our subsidiaries; . engage in specified transactions with subsidiaries and affiliates; or . engage in other specified corporate activities. Also, our revolving credit facility requires us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control, and we cannot assure you that we will meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests 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 -32- covenants under the revolving credit facility impose on us. A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under the revolving credit facility. A default, if not cured or waived, could result in acceleration of all indebtedness outstanding under the revolving credit facility. The accelerated debt would become immediately due and payable. If that should occur, we may not be able to pay all such debt or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. If we fail to meet our payment obligations under our revolving credit facility, the lenders under such credit facility could foreclose on, and acquire control of, substantially all of our assets. The lenders under our revolving credit facility have liens on substantially all of our assets. As a result of the liens held by our revolving credit facility lenders, if we fail to meet our payment or other obligations under the revolving credit facility, those lenders would be entitled to foreclose on substantially all of our assets and liquidate those assets. 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, to retire debt and to pay dividends on our outstanding shares of 6% convertible preferred stock. Any decision to pay dividends on the common stock in the future will depend upon our profitability at that time, the available cash and other factors. Our ability to pay dividends on our common stock is further limited by the terms of our loan agreement and the terms of our preferred stock. Changes in control may be discouraged. 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 interests 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 Parallel's 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 Parallel's stock at a 50% discount. See Note 9 to Financial Statements, on page F-24. -33- On November 25, 2003, our Board of Directors approved in principle the adoption of an employee retention/severance plan that became effective January 1, 2004. Although specific details of the plan have not been determined and the plan is not in final written form, we expect that the significant provisions of the plan will provide for a one-time payment of all officers and employees of Parallel upon the occurrence of a change of control. The aggregate payments of all officers and employees will generally be 5% of an amount equal to the positive difference between the amount by which our net asset value per share at the time of the occurrence of a change of control exceeds the net asset value per share as of January 1, 2004, compounded annually at a rate equal to the annual industry average growth rate, plus 2%. Generally Parallel contemplates that a "change of control" will include events such as a merger, reorganization, liquidation or sale of substantially all of the asset of Parallel, or the acquisition by a third party of 50% or more of our outstanding voting securities. We are authorized to issue 10.0 million shares of preferred stock, 957,000 shares of which were outstanding on March 1, 2004. 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: . 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; . 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; . dilution of the equity interest of common stock and other series of preferred stock; and . limitation on the right of holders of common stock and other series of preferred stock to share in Parallel's 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. -34- ------------------------------------------------------------------------------- ITEM 2. PROPERTIES ------------------------------------------------------------------------------- General Our principal properties consist of developed and undeveloped oil and gas leases and the reserves associated with these leases. Generally, developed oil and gas leases remain in force so long as production is maintained. Undeveloped oil and 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. Producing Wells and Acreage We have presented the following table to provide you with a summary of the producing oil and gas wells and the developed and undeveloped acreage in which we owned an interest at December 31, 2003. We have not included in the table acreage in which our interest is limited to options to acquire leasehold interests, royalty or similar interests. Producing Wells Acreage ----------------------------------------------- ----------------------------------------------- Oil(1) Gas Developed Undeveloped ----------------------- ---------------------- ----------------------- ----------------------- Gross Net(2) Gross Net(2) Gross Net(3) Gross Net(3) ----------- ----------- ---------- ---------- ---------- ----------- ----------- ---------- Texas 468 267.3 106 38.50 62,585 37,423 63,279 9,423 Nevada - - - - - - 3,326 3,326 New Mexico - - 1 0.06 - - 54,364 4,447 Utah - - - - - - 124,026 98,337 ----------- ----------- ---------- ---------- ---------- ----------- ----------- ---------- Total 468 267.3 107 38.56 62,585 37,423 244,995 115,533 =========== =========== ========== ========== ========== =========== =========== ========== --------------------- (1) Does not include 261 wells that are currently shut in or temporarily abandoned. (2) Net wells are computed by multiplying the number of gross wells by our working interest in the gross wells. (3) Net acres are computed by multiplying the number of gross acres by our working interest in the gross acres. At December 31, 2003, we owned interests in 148 gross (110.9 net) producing oil and gas wells for which we were the operator and 427 gross (194.9 net) producing oil and 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 gas leases, we do not own any patents, licenses, franchises or concessions which are significant to our oil and gas operations. -35- Title to Properties As is customary in the oil and gas industry, we make only a cursory review of title to undeveloped oil and 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 gas properties, some of which are subject to immaterial encumbrances, easements and restrictions. The oil and 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 Gas Reserves For the year ended December 31, 2003, our oil and gas reserves were estimated by Cawley Gillespie & Associates, Inc., Fort Worth, Texas. At December 31, 2003, our total estimated proved reserves were approximately 12,100 MBbls of oil and 16.3 Bcf of gas, or 14,800 MBOEs. -36- The information in this table provides you with certain information regarding the proved reserves as estimated by Cawley Gillespie & Associates, Inc., at December 31, 2003. Proved Proved Developed Undeveloped Total ---------------- ----------------- ------------------- ($ in thousands) Oil (MBbls) 8,944 3,140 12,084 Gas (MMcf) 12,066 4,205 16,271 MBOE 10,955 3,841 14,796 Future Net Revenues (before income taxes) $ 216,595 $ 77,095 $ 293,690 Present Value of Future Net Revenues (before income taxes) $ 117,483 $ 30,306 $ 147,789 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 such reserve estimates that are held constant throughout the life of the properties, except to the extent a contract specifically provides for escalation. The average realized prices for our reserves as of December 31, 2003 were $30.63 per Bbl of oil and $5.45 per Mcf of natural gas. For additional information concerning our estimated proved oil and gas reserves, you should read Note 15 to the Financial Statements. See also Item 8 - Financial Statements and Supplementary Data beginning on page 64 of this Annual Report on Form 10-K. The reserve data in this report 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 gas or oil reserves outside the United States. Our oil and gas reserves and production are not subject to any long term supply or similar agreements with foreign governments or authorities. -37- Our estimated reserves have not been filed with or included in reports to any federal agency other than the SEC. ------------------------------------------------------------------------------- ITEM 3. LEGAL PROCEEDINGS ------------------------------------------------------------------------------- At March 1, 2004, we were involved in one lawsuit incidental to our business. We do not believe the ultimate outcome of this lawsuit will have a material adverse effect on our financial position or results of operations and we have not made an accrual for this item. We accrue for such items when a liability is both probable and the amount can be reasonably estimated. We are not aware of any other threatened litigation. We have not 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 2003. -38- PART II ------------------------------------------------------------------------------- ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES ------------------------------------------------------------------------------- Market Information Our common stock trades on the Nasdaq National Market under the symbol PLLL. The following table shows, for the periods indicated, the high and low closing sales prices for the common stock as reported by Nasdaq. Price Per Share -------------------------- High Low ------------- ------------ 2001 First Quarter $ 4.93 $ 3.50 Second Quarter $ 5.57 $ 4.20 Third Quarter $ 4.18 $ 2.95 Fourth Quarter $ 4.20 $ 2.77 2002 First Quarter $ 4.38 $ 3.08 Second Quarter $ 3.41 $ 2.60 Third Quarter $ 2.95 $ 2.15 Fourth Quarter $ 2.91 $ 2.03 2003 First Quarter $ 3.10 $ 2.51 Second Quarter $ 4.03 $ 2.40 Third Quarter $ 3.86 $ 3.15 Fourth Quarter $ 4.49 $ 3.19 The last sale price of our common stock on March 1, 2004 was $3.96 per share, as reported on the Nasdaq National Market. As of March 1, 2004, there were approximately 1,884 stockholders of record. Dividends We have not paid, and do not intend to pay in the foreseeable future, cash dividends on our common stock. The revolving credit facility we have with our bank lenders prohibits the -39- payment of dividends on the common stock. Our 6% convertible preferred stock also contains provisions that restrict us from paying dividends or making distributions on our common stock if all dividends on the preferred stock have not been paid in full. Any dividends on our preferred stock that are not declared and paid will accumulate. All accumulated dividends must be paid in full before dividends may be paid to holders of common stock. The credit facility allows us to pay dividends on our outstanding shares of preferred stock as long as we are not in default under the terms of the credit facility. The holders of the preferred stock are entitled, as and when declared by the Board of Directors, to receive an annual dividend of $.60 per share, payable semi-annually on June 15 and December 15 of each year. See "Risks Related to Our Business - We do not pay dividends on our common stock" on page 21 and "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity " on page 53. Equity Compensation Plans At December 31, 2003, a total of 2,705,650 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 option plans beginning on page 78. Equity Compensation Plan Information -------------------------------------------------------------------------------------------------------------- (a) (b) (c) -------------------------------------------------------------------------------------------------------------- Plan category Number of securities to Weighted-average Number of securities be issued upon exercise exercise price of remaining available for of outstanding options, outstanding future issuance under warrants and rights options, warrants equity compensation and rights plans (excluding securities reflected in column (a)) -------------------------------------------------------------------------------------------------------------- Equity compensation plans approved by 1,938,150 $ 3.53 192,500 security ho1ders -------------------------------------------------------------------------------------------------------------- Equity compensation plans not approved by 575,000(1) $ 3.83 - security holders -------------------------------------------------------------------------------------------------------------- Total 2,513,150 $ 3.60 192,500 -------------------------------------------------------------------------------------------------------------- (1) These shares include an aggregate of 200,000 shares of common stock underlying stock options granted in June, 2001 to non-officer employees pursuant to Parallel's Employee Stock Option Plan; 275,000 shares of common stock underlying a stock purchase warrant we issued to an investment banking firm in November, 2001; and 100,000 shares of common stock underlying a stock purchase warrant we issued to the same investment banking firm in December, 2003. -40- Sale of Equity Securities On December 23, 2003, we privately placed a total of 4.0 million shares of common stock, $.01 par value per share, at a price of $3.25 per share. Gross cash proceeds from the placement were $13.0 million. The shares of common stock were sold to twenty accredited investors, including individuals, investment funds and other privately held entities. The shares of common stock were issued without registration under the Securities Act of 1933 in reliance on the exemptions provided by Section 4(2) of the Securities Act and Rule 506 of Regulation D under the Securities Act. Each purchaser acquired shares for investment and not with a view to distribution and certificates evidencing the shares bear restrictive legends. The net proceeds of the offering, approximately $12.1 million, will be used for acquisition and development activities and for general corporate purposes. Pending the use of proceeds, in January 2004, we used the net proceeds to repay outstanding bank indebtedness under our revolving credit facility. Stonington Corporation acted as our placement agent and received a placement fee in the amount of 6% of the gross proceeds, and warrants to purchase 100,000 shares of common stock. The warrants are exercisable, in whole or in part, at an exercise price equal to $3.98, the fair market value of the common stock on the date of closing, and are exercisable at any time during the four-year period commencing one year after the closing of the placement. The warrants contain customary provisions providing for adjustment of the exercise price and the number and type of securities issuable upon exercise of the warrants if any one or more of certain specified events occur. The warrants grant to the holder certain registration rights for the securities issuable upon exercise of the warrants. 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, 2003. ------------------------------------------------------------------------------- ITEM 6. SELECTED FINANCIAL DATA ------------------------------------------------------------------------------- In the table below, we provide you with selected historical financial data. We have prepared this information using the audited financial statements for the five-year period ended December 31, 2003. It is important that you read this data along with our financial statements and related notes, and "Management's 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. -41- Year Ended December 31, -------------------------------------------------------------- 2003(1) 2002(2) 2001(3) 2000 1999(4) ------------ ----------- ----------- ------------ ----------- (in thousands, except per share and per unit data) Consolidated Income Statements Data: Operating revenues $ 33,855 $ 12,106 $ 17,840 $ 17,134 $ 8,974 Operating expenses $ 21,138 $ 11,250 $ 28,405 $ 9,530 $ 10,174 Income (loss) before cumulative effect of change in accounting principle $ 7,664 $ 18,701 $ (4,708) $ 5,977 $ (2,450) Net income (loss) $ 7,602 $ 18,701 $ (4,708) $ 5,977 $ (2,450) Cumulative preferred stock dividend $ (580) $ (585) $ (585) $ (585) $ (585) Net income (loss) available to common stockholders $ 7,022 $ 18,116 $ (5,292) $ 5,393 $ (3,035) Net income (loss) per common share before cumulative effect of change in accounting principle Basic $ 0.33 $ 0.88 $ (0.26) $ 0.26 $ (0.16) Diluted $ 0.31 $ 0.79 $ (0.26) $ 0.25 $ (0.16) Weighted average common stock and common stock equivalents outstanding Basic 21,264 20,680 20,458 20,332 18,549 Diluted 24,175 23,549 20,458 23,465 18,549 Cash dividends - common stock $ - $ - $ - $ - $ - Consolidated Balance Sheet Data: Total assets $118,343 $102,351 $ 41,760 $ 46,456 $ 43,264 Total liabilities $ 57,111 $ 56,852 $ 15,446 $ 15,288 $ 17,464 Long-term debt, less current maturities $ 39,750 $ 45,604 $ 9,600 $ 11,624 $ 12,300 Total stockholders' equity $ 61,232 $ 45,499 $ 26,314 $ 31,168 $ 25,800 Consolidated Statement of Cash Flow Data: Cash provided (used) by Operating activities $ 19,465 $ 1,528 $ 13,383 $ 10,694 $ 3,406 Investing activities $(15,494) $(30,277) $(11,357) $ (5,846) $ (3,788) Financing activities $ 1,595 $ 37,210 $ (676) $ (4,123) $ 455 Operating Data: Product Sales Oil (Bbls) 629 131 138 165 164 Gas (Mcf) 3,356 2,670 3,266 2,822 2,709 BOE 1,188 576 682 635 615 Average sales price Oil (per Bbl) $ 29.11 $ 24.59 $ 24.80 $ 28.88 $ 17.32 Gas (per Mcf) $ 5.40 $ 3.33 $ 4.41 $ 4.38 $ 2.27 Proved reserves Oil (Bbls) 12,084 10,271 916 974 1,008 Gas (Mcf) 16,271 15,633 13,947 15,686 17,284 Present value of proved oil and gas reserves discounted at 10% (before estimated federal income taxes $147,789 $122,934 $ 17,074 $ 90,950 $ 25,499 Other Data: Operating cash flow (5) $ 19,310 $ 5,225 $ 11,568 $ 11,718 $ 4,378 -42- --------------- (1) Result includes $8.8 million and $3.3 million for operating revenue and operating expenses, respectively, associated with our Fullerton properties acquired December 2002. (2) Results include a $31.0 million gain attributable to equity in income of First Permian, L.P. See Note 6 to the Financial Statements. Results also include noncash charges of $717,000 on the sale of Energen stock, $509,000 for the change in fair value of derivatives and $440,000 for the change in fair market value of our crude oil swaps. (3) Results include noncash charges of $2.2 million in the fiscal quarter ended September 30, 2001 and $14.6 million in the fourth quarter ended December 31, 2001, in each case related to the impairment of oil and gas properties incurred in 2001 and primarily a result of a decrease in year-end reserves and lower oil and gas prices. (4) Results include a non-cash charge of $1.7 million related to the impairment of oil and gas properties incurred in the fourth quarter of 1999, primarily a result of a decrease in year-end reserves. (5) Defined as cash provided by operating activities before changes in operating assets and liabilities. Because of the exclusion of changes in assets and liabilities, this cash flow statistic is different from cash provided (used) by operating activities, as is disclosed under generally accepted accounting principles and is reconciled to operating cash flow as follows: 2003 2002 2001 2000 1999 ---------- -------- --------- --------- ------- (in thousands) Cash provided (used) by operating activities $19,465 $1,528 $13,383 $10,694 $3,406 Changes in operating assets and liabilities (155) 3,697 (1,814) 1,024 972 --------- -------- --------- --------- ------- Operating cash flow $19,310 $5,225 $11,569 $11,718 $4,378 ========= ======== ========= ========= ======= As compared to cash provided by operating activities, we believe operating cash flow is a better liquidity indicator for oil and gas producers because changes in assets and liabilities eliminates fluctuations related to the timing of cash receipts and disbursements which can vary from period-to-period because of conditions we cannot control. ------------------------------------------------------------------------------- ITEM 7. MANAGEMENT'S 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, 2003. You should read the following discussion and analysis in conjunction with our financial statements and the related notes. 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 Our primary objective is to increase shareholder value of our common stock through increasing reserves, production, cash flow and earnings. We are shifting the balance of our investments from properties having high rates of production in early years to properties with -43- more consistent production 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 exploitation and development drilling opportunities. Obtaining positions in long-lived oil and gas reserves will be 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. During the latter part of 2002, we 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 anticipate participating in exploratory drilling activities in the future, 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 geological risk; . emphasizes exploitation and enhancement activities; . 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 high 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 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; . 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. -44- Significant changes in the prices we receive for our oil and gas drilling results, 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 gas and our production volumes. 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. 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 . to a lesser extent, world oil prices. Additional factors influencing our overall operating performance include: . production expenses; . overhead requirements; and . costs of capital. Our oil and gas exploration, development and acquisition activities require substantial and continuing capital expenditures. Historically, the sources of financing to fund our capital expenditures have included: . cash flow from operations; . sales of our equity securities; . bank borrowings; and . industry joint ventures. -45- Depletion per BOE in 2003 was $6.83 versus $10.52 in 2002 and $9.13 in 2001. The decrease per BOE in 2003 was a result of lower cost reserves associated with our acquisition of the Fullerton properties as of December, 2002. Our oil and gas producing activities are accounted for using the full cost method of accounting. Under this accounting method, we capitalize all costs incurred in connection with the acquisition of oil and gas properties and the exploration for and development of oil and gas reserves. See Note 3 to the Financial Statements. These costs include lease acquisition costs, geological and geophysical expenditures, costs of drilling productive and non-productive wells, and overhead expenses directly related to land and property acquisition and exploration and development activities. Proceeds from the disposition of oil and gas properties are accounted for as a reduction in capitalized costs, with no gain or loss recognized unless a disposition involves a material change in reserves, in which case the gain or loss is recognized. Depletion of the capitalized costs of oil and gas properties, including estimated future development costs, is provided using the equivalent unit-of-production method based upon estimates of proved oil and gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. Unproved oil and gas properties are not amortized, but are individually assessed for impairment. The cost of any impaired property is transferred to the balance of oil and gas properties being depleted. Results of Operations Our business activities are characterized by frequent, and sometimes significant, changes in our: . reserve base; . sources of production; . product mix (gas versus oil volumes); and . the prices we receive for our oil and gas production. -46- Year-to-year or other periodic comparisons of the results of our operations can be difficult and may not fully and accurately describe our condition. The following table shows selected operating data for each of the three years ended December 31, 2003. Year Ended December 31, ---------------------------------------------- 2003 2002 2001 --------------- -------------- -------------- (in thousands except per unit data) Production, Prices and Lifting Costs: Oil (Bbls) 629 131 138 Natural gas (Mcf) 3,356 2,670 3,266 BOE 1,188 576 682 Oil price (per Bbl)(1) $ 29.11 $ 24.59 $ 24.80 Natural gas price (per Mcf)(1) $ 5.40 $ 3.33 $ 4.41 BOE price(1) $ 30.66 $ 21.03 $ 26.13 Average Production (lifting) Cost per BOE(2) $ 7.07 $ 5.00 $ 5.74 ----------- (1) Average price received at the wellhead for our oil and natural gas. (2) The increase in 2003 is attributable to increased lifting costs associated with our waterflood projects. Critical Accounting Policies and Practices 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, as adjusted for asset retirement obligations, 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 of fair market value of our unproved properties. Revenues are measured at unescalated oil and 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 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 earnings. It reduces earnings and impacts stockholders' equity in the period of occurrence and results 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 gas properties increases when oil and 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 gas properties, under the full cost method, is calculated using the unit of production method based upon estimates of proved oil and gas reserves with oil and gas production being converted to a common unit of measure based upon -47- 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. The cost of any impaired property is transferred to the balance of oil and gas properties being depleted. Proved Reserve Estimates. Our discounted present value of 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 outside consultants. 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 significant revisions are necessary that reduce previously estimated reserve quantities, it could result in a full cost ceiling writedown. In addition to the impact of these estimates of proved reserves on calculation of the ceiling, estimates of proved reserves are also a significant component of the calculation of depreciation, depletion and amortization. While the quantities of proved reserves require substantial 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 any particular day at the end 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 financial statements in accordance with accounting principles generally accepted in the United States of America 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 expense are the most critical estimates to our financial statements. Derivatives. The Financial Accounting Standards Board issued SFAS No. 133 and SFAS No. 138 requiring that all derivative instruments be recorded on the balance sheet at their respective values. SFAS No. 133 and SFAS No. 138 are effective for all fiscal quarters of all fiscal years beginning after June 30, 2000. We adopted SFAS No. 133 and SFAS No. 138 on January 1, 2001. For the periods prior to January 1, 2003, derivative contracts were not designated as hedges. Accordingly, the unrealized gains or losses were recorded in income. As of January 1, 2003 we designated costless collars, oil and gas swaps, and interest rate swaps as cash flow hedges. Accordingly, the effective portion of the unrealized gain or loss on cash flow hedges is recorded in other comprehensive income until the forecasted transaction occurs. We -48- continued to record the unrealized loss on put positions outstanding in income during 2003. The purpose of our hedges is to provide a measure of stability in our oil and gas prices and interest rate payments and to manage exposure to commodity price and interest rate risk under existing sales contracts. Overhead Reimbursement - Joint Operations. As compensation for administration, supervision office services and warehousing cost, an operator may charge drilling and producing overhead costs based upon rates negotiated in the joint operating agreement. Overhead reimbursements charged to working interest owners for properties that we operate are treated as reductions in general and administrative expense for producing overhead. For 2003, capital costs were reduced by approximately $34,000 and general and administrative costs were reduced by approximately $123,000 for drilling and producing overhead reimbursements. Prior to 2003, overhead was recorded as other income. The amounts reimbursed to us for 2002 and 2001 were $20,000 and $24,000 respectively. Years Ended December 31, 2003 and December 31, 2002 Oil and Gas Revenues. Our total oil and gas revenues for 2003 were $33.9 million, an increase of $21.8 million, or approximately 180%, from $12.1 for 2002. The increase in revenues for 2003, compared to 2002, is related to a 106% increase in oil and gas production due to the Fullerton acquisition on December 20, 2002, two additional productive wells drilled in 2003 in the Cook Mountain along with a full year's production of the Murphy #1 and a 36% increase in the average sales price per BOE including hedges. On an equivalent barrel basis, 2003 production totaled 1.2 million BOE compared with 576,000 BOE in 2002, approximately a 612,000 BOE increase. Lease Operating Expense. The increase in lease operating expense for 2003, compared with 2002, was primarily the result of increased lease operating expense associated with the waterfloods on Fullerton and Diamond M properties. Lease operating costs increased $4.4 million or 210%, to $6.5 million for the twelve months ended December 31, 2003, from $2.1 million for the same period of 2002. General and Administrative Costs. Overall general and administrative expenses increased $2.2 million or approximately 102% to $4.3 million for the year ended December 31, 2003. General and administrative expenses for the same period of 2002 were $2.1 million. The increase in general and administrative expenses was primarily due to additional personnel in conjunction with the implementation of our new business plan in June 2002 and increased public reporting costs. . General and administrative expense included in oil and gas properties is $915,000 and $1.3 million for 2003 and 2002 respectively. Depreciation Depletion and Amortization Expense. Depreciation, depletion and amortization expenses for 2003 increased $2.2 million or approximately 35% to $8.4 million as compared to $6.2 million in 2002. The increase was primarily attributable to the 106% increase -49- in production volumes for the year ended December 31, 2003 and associated depletable property base in connection with our property acquisitions. Depreciation, depletion and amortization expenses did not increase at a comparable rate to production volume increases because with the addition of the Fullerton properties in late 2002, our depreciation, depletion and amortization rate on a BOE basis decreased from $10.52 in 2002 to $6.83 in 2003. Equity in Income of First Permian, L.P. As discussed in Note 3 to the Financial Statements, First Permian, L.P. sold all of its oil and gas properties on April 8, 2002. As the owner of a 30.675% interest in First Permian, we received our prorata share of the net sales proceeds, or $5.5 million in cash and 933,589 shares of common stock of Energen Corporation. Our pro rata share of the net income and distributions for 2002 was $31.0 million. Incentive Awards attributable to the sale of First Permian, L.P. The Incentive Awards reflect bonus payments made to certain officers and employees in 2002 as a result of First Permian's sale of all of its assets. Loss on Marketable Securities. We recognized a loss in marketable securities for the year ended December 31, 2002 in the amount of approximately $717,000, which resulted from our sales of 933,589 shares, all of our investment of Energen common stock. This loss represents the difference in Energen's stock price of $27.40 per share at the time of the First Permian sale and our realized net price of approximately $26.63 per share. Change in Fair Value of Derivatives. We recognized a loss of approximately $22,000 for the year ended December 31, 2003 compared to a loss of $948,000 for the same period of 2002. The loss of $22,000 in 2003 was attributable to the expiration of put options not designated as cash flow hedges. The decrease from 2002 to 2003 is primarily due to our adopting cash flow hedge accounting which allows us to record changes in fair value of contracts designated as cash flow hedges through other comprehensive income until realized. When realized, we reflect the gain or loss on commodity derivatives designed as cash flow hedges in revenue and on interest rate derivative designated as cash flow hedges in interest expense. See Note 5 to the Financial Statements. Gain (loss) in Ineffective Portion of Hedges. The gain on the ineffective portion of our hedges was $191,000 for 2003. We did not use hedge accounting for derivatives prior to 2003. Dividend Income. Dividend income during 2002 was approximately $371,000 associated with our investment in and ownership of Energen common stock. All of our investment in Energen stock was sold in 2002. Interest Expense. Interest expense increased $1.4 million or 241% to $2.0 million for the year ended December 31, 2003, from approximately $601,000 for the same period of 2002. This increase was due principally to increased bank borrowings associated with our acquisitions, partially offset by a decrease in the minimum interest rate under our revolving credit facility. The minimum interest rate decreased from 4.75% to 4.50% in December 2002. -50- Income Tax Benefit (Expense) Deferred. For the period ended December 31, 2003, we recorded federal and state income tax expense of $3.9 million and a credit of $900,000, which was a reduction of our estimate of State income tax liability, respectively compared to an income tax expense of $8.8 million and $932,000, respectively in 2002. See Note 8 to the Financial Statements. Net Income. Our net income for 2003 was $7.6 million a decrease of $11.1 million or approximately 59% compared to $18.7 million for 2002. The decrease was principally due to the gain on sale of First Permian, L.P. and dividend income from the Energen stock recognized in 2002. Other items affecting net income include: . a 106% increase in oil and gas production due to the Fullerton acquisition and increased production at Cook Mountain along with a 36% increase in sales price per BOE; . a 210% increase in lease operating expense due to increased production and operating costs associated with water flood projects; . a 102% increase in general and administrative costs due to a full year of our business plan in place, which included increased staffing needs and associated costs. We are also experiencing increased public reporting costs due to expanded reporting requirements and activity. Years Ended December 31, 2002 and December 31, 2001 Oil and Gas Revenues. Our total oil and gas revenues for 2002 were $12.1 million, a decrease of $5.7 million, or approximately 32%, from $17.8 million for 2001. The decrease in revenues for 2002, compared to 2001, is related to a 20% decline in the average price we received for our oil and natural gas production volumes, and a 16% decline in oil and natural gas production volumes on a BOE basis. On an equivalent barrel basis, 2002 production totaled 576,000 BOE compared with 682,000 BOE in 2001. The decrease in natural gas production was primarily due to production declines, which was partially offset by our drilling activities in 2002. Lease Operating Expense. The decrease in lease operating expenses for 2002, compared with 2001, was primarily the result of decreased production volumes and, to a lesser extent, reduction in ad valorem taxes and other direct operating expenses. Production costs decreased $656,000 or 24%, to $2.1 million for the twelve months ended December 31, 2002, from $2.7 million for the same period of 2001. General and Administrative Costs. Overall general and administrative expenses increased $807,000 or 60% to $2.2 million for the year ended December 31, 2002. General and administrative expenses for the same period of 2001 were $1.3 million. The increase in general and administrative expenses was primarily due to increased public reporting costs, increased costs associated with our new office and increased staffing for six months ending 2002 associated with our new business plan. General and administrative expense included in oil and gas properties is $1.3 million and $782,000 for 2002 and 2001 respectively. -51- Depreciation Depletion and Amortization Expense. Depreciation, depletion and amortization expenses for 2002 were slightly lower at $6.2 million, as compared to $6.3 million in 2001. The decline was attributable to an increase in reserves as of December 31, 2002, which was partially offset by an increase in net depletable property basis. Impairment of Oil and Gas Properties. We recognized a noncash impairment charge of $16.8 million in 2001 related to our oil and gas reserves and unproved properties. The impairment of oil and gas assets was primarily the result of significantly lower oil and natural gas prices on both proved and unproved oil and gas properties. An impairment was not recognized in 2002. Equity in Income of First Permian, L.P. As discussed in Note 6 to the Financial Statements, First Permian, L.P. sold all of its oil and gas properties on April 8, 2002. As the owner of a 30.675% interest in First Permian, we received our prorata share of the net sales proceeds, or $5.5 million in cash and 933,589 shares of common stock of Energen Corporation. Our pro rata share of the net income and distributions for 2002 was $31.0 million. Incentive Awards attributable to the sale of First Permian, L.P. The Incentive Awards reflect bonus payments made to certain officers and employees in 2002 as a result of First Permian's sale of all of its assets. Loss on Marketable Securities. We recognized a loss in marketable securities in the amount of approximately $717,000, which resulted from our sales of 933,589 shares, all of our investment, of Energen common stock during 2002. This loss represents the difference in Energen's stock price of $27.40 per share at the time of the First Permian sale and our realized net price of approximately $26.63 per share. Change in Fair Value of Derivatives. We also recognized a loss of $948,000 which represented the decrease in fair value of our natural gas puts of $508,000 and mark-to-market accounting for approximately $440,000. See Note 5 to the Financial Statements. Dividend Income. Dividend income during 2002 was $371,000 associated with our investment in and ownership of Energen common stock. Interest Expense. Interest expense decreased $201,000 or 25% to $601,000 for the year ended December 31, 2002, from $802,000 for the same period of 2001. This decrease was principally a result of a decrease in average borrowings associated with the redeployment of cash from the sale of the Energen stock and lower interest rates. Income Tax Benefit (Expense) Deferred. For the period ended December 31, 2002, we recorded federal and state income tax expense of $8.7 million and $932,000, respectively. See Note 8 to the Financial Statements. Net Income (Loss). Our income, before preferred stock dividends, was $18.7 million for the year ended December 31, 2002, compared with a loss of $4.7 million for the year ended -52- December 31, 2001. In 2002, income of $29.7 million resulted entirely from the sale of First Permian's oil and gas properties, net of incentive awards attributable to First Permian's sale of its assets. Other items affecting net income included: . a 32% decrease in oil and gas revenues related to a decline in volumes and average price received; . decreased production costs of approximately 27% primarily related to decreased production volumes and, to a lesser extent, reductions in ad valorem taxes and other direct operating expenses, . increased general and administrative expenses of 60%, increased public reporting costs, increased costs associated with our new office and increased staffing needs associated with our new business plan; and . non-cash charges associated with the sale of Energen stock, fair market value of our put options and mark to market of the crude oil swaps. Capital Resources and Liquidity Our capital resources consist primarily of cash flows from our oil and gas properties and bank borrowings supported by our oil and gas reserves. 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 increased 92% or $7.9 million as of December 31, 2003 compared with December 31, 2002. Current assets exceeded current liabilities by $16.4 million at December 31, 2003. The working capital increase was primarily due to the private placement of 4.0 million shares of common stock with gross proceeds of $13.0 million and no current maturities on our revolving credit facility and increased receivables associated with increased oil and gas volumes and prices. See Note 9. The following table summarizes our cash flows from operating, investing and financing activities: Year ended December 31, ---------------------------------------- 2003 2002 2001 ------------- ------------ ------------- (in thousands) Operating activities $ 19,465 $ 1,528 $ 13,383 Investing activities $(15,494) $(30,277) $(11,357) Financing activities $ 1,595 $ 37,210 $ (676) Cash from operating activities in 2003 increased $17.9 million over 2002 largely due to increased operating income from the Fullerton acquisition, increased production in the Cook Mountain Gas project and increased sales prices in 2003. Investing and financing activities -53- decreased in 2003 compared to 2002 primarily as a result of the Fullerton acquisition in 2002. These declines were partially offset by proceeds from the First Permian asset sale also recorded in 2002. Cash provided from operating activities declined $11.9 million in 2002 compared to 2001 primarily due to reduced production and product prices. Investing and financing activities increased in 2002 compared to 2001 primarily as a result of the Fullerton acquisition. We incurred net property costs of $14.9 million for the period ended December 31, 2003, primarily for our oil and gas property leasehold acquisition, development, and enhancement activities. Also added to our property basis were asset retirement costs of $1.5 million for the adoption of SFAS 143 (see Note 4). The property leasehold acquisition, development and enhancement activities were financed by the utilization of cash flows provided by operations. Based on our projected oil and gas revenues and related expenses and available bank borrowings, we believe that we will have sufficient capital resources to fund normal operations and capital requirements, interest expense and principal reduction payments on bank debt, if required, and preferred stock dividends. We continually review and consider alternative methods of financing. Bank Borrowings On December 20, 2002, Parallel and its subsidiary, Parallel, L.P., entered into a First Amended and Restated Credit Agreement with First American Bank, SSB, Western National Bank and BNP Paribas. The credit facility provides for revolving loans. This means that we can borrow, repay and reborrow funds drawn under the credit facility. However, the aggregate amount that we can borrow and have outstanding at any one time is subject to a borrowing base. The borrowing base calculation is based primarily upon the estimated value of our oil and gas reserves. Generally, we can borrow only up to the borrowing base in effect from time to time. The borrowing base amount is redetermined by the banks on or about April 1 and October 1 of each year or at other times required by the banks or at our request. If, as a result of the banks' redetermination of the borrowing base, the outstanding principal amount of our loan exceeds the borrowing base, we must either provide additional collateral to the banks or prepay the principal of the note 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. The credit agreement was amended in September 2003. The amendment included: . the deletion of the monthly commitment reduction, a provision that would have required us to begin amortizing our loan beginning August 31, 2003; . the modification of certain financial ratio tests; . an increase in our borrowing base to $50 million; . changes in certain reporting requirements to the banks; and -54- . the revision of covenants in the credit agreement governing our hedging activities. The principal amount outstanding under the revolving credit facility was $39.8 million at December 31, 2003. This facility bears interest at First American Bank's base rate or the libor rate, at our election. Generally, First American Bank's base rate is equal to the prime rate published in the Wall Street Journal, but not less than 4.50%. 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 or six month interest periods for deposits of $1.0 million, and (b) a margin ranging from 2.25% to 2.75%, depending upon the outstanding principal amount of the loans. The interest rate we are required to pay, including the applicable margin, may never be less than 4.50%. If the principal amount outstanding is equal to or greater than 75% of the borrowing base established by the banks, the margin is 2.75%. If the principal amount outstanding is equal to or greater than 50%, but less than 75% of the borrowing base, the margin is 2.50%. If the principal amount outstanding is less than 50% of the borrowing base, the margin is 2.25%. 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 facility are less than the borrowing base, an unused commitment fee is required to be paid to the bank 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. All outstanding principal under the revolving credit facility is due and payable on December 20, 2006. The loan is secured by substantially all of our oil and gas properties, including the properties Parallel, L.P. Parallel, L.L.C., a subsidiary of Parallel Petroleum Corporation, guaranteed payment of the loans. We are highly dependent on bank borrowings to fund our exploration and drilling activities. The borrowing base calculation is based upon the estimated value of oil and gas reserves. If our borrowing base declines significantly, our liquidity would be suddenly and materially limited. If the borrowing base is increased, we are required to pay a fee of ..25% on the amount of any increase in the borrowing base. Our obligations to the bank are secured by substantially all of our oil and gas properties. Our bank borrowings have been incurred to finance our property acquisition, 3-D seismic surveys, enhancement and drilling activities. In addition to customary affirmative covenants, the credit agreement contains various restrictive covenants and compliance requirements, including: . maintaining certain financial ratios; -55- . limitations on incurring additional indebtedness; . prohibiting the payment of dividends on our common stock; . limitations on the disposition of assets; and . prohibiting liens (other than in favor of the lenders) to exist on any of our properties. If we have borrowing capacity under our credit agreement, we intend to borrow, repay and reborrow under the revolving credit facility from time to time as necessary, subject to borrowing base limitations, to fund: . interpretation and processing of 3-D seismic survey data; . lease acquisitions and drilling activities; . acquisitions of producing properties or companies owning producing properties and; . general corporate purposes. Preferred Stock At December 31, 2003 we had 959,500 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; . is 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; . is redeemable at our option, in whole in part, for $10 per share, plus accrued dividends; . has no voting rights, except as required by applicable law, and except that as long as any shares of preferred stock remain outstanding, the holders of a majority of the outstanding shares of the preferred stock may vote on any proposal to change any provision of the preferred stock which materially and adversely affects the rights, preferences or privileges of the preferred stock; . is senior to the common stock with respect to dividends and on liquidation, dissolution or winding up of Parallel; . has a liquidation value of $10 per share, plus accrued and unpaid dividends. -56- Commodity Price Risk Management Transactions During 2001, we did not use derivative contracts. For the year ended December 31, 2002, we used mark-to-market accounting for all our derivative contracts. As of January 1, 2003 we designated the costless collars, oil and gas swaps and interest rate swaps as cash flow hedges under the provisions of SFAS 133, as amended. We continued mark-to-market accounting for our put positions. The purpose of our hedges is to provide a measure of stability in our oil and gas prices and interest rate payments and to manage exposure to commodity price and interest rate risk. Our objective is to lock in a range of oil and gas prices and a fixed interest rate for certain notional amounts. Under cash flow hedge accounting, the quarterly change in the fair value of the commodity derivatives is recorded in stockholders' equity as other comprehensive income (loss) and then transferred to revenue when the production is sold. Ineffective portions of cash flow hedges (changes in realized prices that do not match the changes in the hedge price) are recognized in other expense as they occur. While the cash flow hedge contract is open, the ineffective gain or loss many increase or decrease until settlement of the contract. Under cash flow hedge accounting for interest rate swaps, the quarterly change in the fair value of the derivatives is recorded in stockholders' equity as other comprehensive income (loss) and then transferred to interest expense when the contract settles. Ineffective portions of cash flow hedges are recognized in other expense as they occur. We are exposed to credit risk in the event of nonperformance by the counterparty in its derivative instruments. However, we periodically assess the creditworthiness of the counterparty to mitigate this credit risk. Certain of our commodity price risk management arrangements have required us to deliver cash collateral or other assurances of performance to the counterparties in the event that our payment obligations with respect to our commodity price risk management transactions exceed certain levels. For additional information about our price risk management transactions, see Item 7A of this Annual Report on Form 10-K, beginning on page 62. Future Capital Requirements Our capital expenditure budget for 2004 is approximately $17.0 million and is highly dependent on future oil and gas prices and the availability of funding. These expenditures will be governed by the following factors: . internally generated cash flows; . availability of borrowing under our revolving credit facility; -57- . additional sources of financing; and . future drilling successes. In 2003, we have focused on drilling lower risk natural gas prospects that could have a meaningful effect on our reserve base and cash flows. In selected cases, we may elect to reduce our interest in higher risk, higher impact projects. We may also sell certain non-core producing properties to raise funds for capital expenditures. Contractual Obligations, Commitments and Off-Balance Sheet Arrangements We have contractual obligations and commitments that may affect our financial position. However, based on our assessment of the provisions and circumstances of our contractual obligation and commitments, we do not feel there would be an adverse effect on our consolidated results of operations, financial condition or liquidity. The following table is a summary of significant contractual obligations: Obligation Due in Period ----------------------------------------------------------------------------------------------- After 5 Contractual Cash Obligations 2004 2005 2006 2007 2008 years Total ---------------------------------- -------------- ------------- ------------ ------------- ------------- ----------- ------------ (in thousands) Revolving Credit Facility (secured) $ - $ - $ 39,750 $ - $ - $ - $ 39,750 Office Lease (Dinero Plaza) 128 157 105 - - - 390 Preferred Stock Dividend 574 574 574 574 574 (2) 2,870 Other Long-term Liabilities(1) 503 38 66 66 30 998 1,701 Derivative Obligations 3,231 1,673 982 - - - 5,886 ------- ------- -------- ------- -------- ------- -------- Total $ 4,436 $ 2,442 $ 41,477 $ 640 $ 604 $ 998 $ 50,597 ======= ======= ======== ======= ======== ======= ======== ------------ (1) Assets retirement obligations of oil and natural gas assets, excluding salvage value. (2) Payments of preferred dividends so long as preferred stock remains outstanding and not converted. 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. Purchase obligations are not included in the table because they are not considered material. In addition to our principal payment obligations under the revolving credit facility payment noted in the table above, we are subject to interest payments on such indebtedness. See Note 7 to the Financial Statements. -58- We have no off-balance sheet financing arrangements or any unconsolidated special purpose entities. Outlook The oil and 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 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 gas we produce from existing wells; . the prices at which we sell oil and gas; and . our ability to acquire, locate and produce new reserves. 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 Parallel's securities; . sales of non-core properties; or . other forms of financing. We do not have agreements for any future financing and there can be no assurance as to the availability or terms of any such financing. -59- Inflation Inflation has not had a significant impact on our financial condition or results of operations. We do not believe that inflation poses a material risk to our business. Recent Accounting Pronouncements FIN No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Other. FIN No. 45 requires that a liability be recorded in the guarantor's balance sheet upon issuance of certain guarantees. Initial recognition and measurement of the liability will be applied on a prospective basis to guarantees issued or modified after December 31, 2002. FIN No. 45 also requires disclosures about guarantees in financial statements for interim or annual periods ending after December 15, 2002. The adoption of FIN No. 45 did not have a material impact on the Company's consolidated financial statements. FIN No. 46, Consolidation of Variable Interest Entities. In December 2003, the FASB issued Interpretation No. 46R, Consolidation of Variable Interest Entities" ("FIN 46"), which requires the consolidation of certain entities that are determined to be variable interest entities ("VIE"). An entity is considered to be a VIE when either (i) the entity lacks sufficient equity to carry on its principal operations, (ii) the equity owners of the entity cannot make decisions about the entity's activities or (iii) the entity's equity neither absorbs losses or benefits from gains. The Company owns no interests in variable interest entities, and therefore this new interpretation has not affected the Company's consolidated financial statements. In March 2003, the Financial Accounting Standards Board issued SFAS No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure, which amends SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. As of September 30, 2003, the Company adopted the Prospective method which applies prospectively the fair value recognition method to all employee and director awards granted, modified or settled after the beginning of the fiscal year in which the fair value based method of accounting for stock-based compensation is adopted. SFAS 148 also amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. In April, 2003, the Financial Accounting Standards Board issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, which clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. The Statement is effective for contracts entered into or modified after June 20, 2003. The adoption of SFAS 149 did not have a material impact on the Company's consolidated financial statements. In May, 2003, the Financial Accounting Standards Board issued SFAS No. 150 -60- "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. This statement was effective for financial instruments entered into or modified after May 31, 2003, and otherwise was effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of SFAS 150 did not have a material impact on the Company's consolidated financial statements. A reporting issue has arisen regarding the application of certain provisions of SFAS No. 141 and SFAS No. 142 to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS No. 142 requires registrants to classify the costs of mineral rights held under lease or other contractual arrangements associated with extracting oil and gas as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. Historically, Parallel has included the costs of such mineral rights associated with extracting oil and gas as a component of oil and gas properties. If it is ultimately determined that SFAS No. 142 requires oil and gas companies to classify costs of mineral rights held under lease or other contractual arrangement associated with extracting oil and gas as a separate intangible assets line item on the balance sheet, the Company would be required to reclassify approximately $17.3 million at December 31, 2003 and $13.5 million at December 31, 2002 out of Oil and Gas Properties and into a separate intangible assets line item. Parallel's cash flows and results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with full cost accounting rules. Effects of Derivative Instruments For the year ended December 31, 2002, we used mark-to-market accounting for all our derivative contracts. As of January 1, 2003 we designated the costless collars, oil and gas swaps and interest rate swaps as cash flow hedges under the provisions of SFAS 133, as amended. The adoption of cash flow hedge accounting allows us to record changes in fair value of contracts designated as cash flow hedges through other comprehensive income until realized. When realized, we reflect the gain or loss on commodity derivatives designated as cash flow hedges in revenue and on interest rate derivatives designated as cash flow hedges in interest expense. We continued mark-to-market accounting for our put positions. The purpose of our hedges is to provide a measure of stability in our oil and gas prices and interest rate payments and to manage exposure to commodity price and interest rate risk. Our objective is to lock in a range of oil and gas prices and a fixed interest rate for certain notional amounts. Under cash flow hedge accounting, the quarterly change in the fair value of the derivatives is recorded in stockholders' equity as other comprehensive income (loss) and then transferred to earnings when the production is sold. Ineffective portions of cash flow hedges (changes in realized prices that do not match the changes in the hedge price) are recognized in other expense as they occur. While the cash flow hedge contract is open, the ineffective gain or loss many increase or decrease until settlement of the contract. -61- We are exposed to credit risk in the event of nonperformance by the counterparty in its derivative instruments. However, we periodically assess the creditworthiness of the counterparty to mitigate this credit risk. ------------------------------------------------------------------------------- ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ------------------------------------------------------------------------------- The following quantitative and qualitative information is provided about market risks and derivative instruments to which Parallel was a party at December 31, 2003, and from which Parallel 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, 2003 Our only financial instrument sensitive to changes in interest rates is our bank debt. As the interest rate is variable and reflects current market conditions, the carrying value approximates the fair value. The table below shows principal cash flows and related weighted average interest rates by expected maturity dates. Weighted average interest rates were determined using weighted average interest paid and accrued in December, 2003. You should read Note 7 to the Financial Statements for further discussion of our debt that is sensitive to interest rates. 2004 2005 2006 2007 2008 Total ---------- ---------- ------------ ------------ ------------ ----------- (in thousands, except interest rates) Variable rate debt $ - $ - $ 39,750 $ - $ - $ 39,750 Revolving Facility (secured) 4.50% 4.50% 4.50% - - - Average interest rate At December 31, 2003, we had bank loans in the amount of approximately $39.7 million outstanding at an average interest rate of 4.50%. Borrowings under our credit facility bear interest, at our election, at (i) the bank's base rate or (ii) the libor rate, plus libor margin, but in no event less than 4.50%. As a result, our annual interest cost in 2004 will fluctuate based on short-term interest rates. As the interest rate is variable and is reflective of current market conditions, the carrying value approximates the fair value. Under our credit facility, we may elect an interest rate based upon the agent lender's base lending rate, or the libor rate, plus a margin ranging from 2.25% to 2.75% 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 4.50%. -62- In January, 2003, we entered into a 45-month libor fixed interest rate swap contract with BNP Paribas. We will receive fixed 90-day libor interest rates for the 45-month period beginning March 31, 2003 through December 20, 2006. A recap for the period of time, notional amounts, libor fixed interest rates, expected margin rates and expected fixed interest rates for the contract are as follows: Libor Expected Expected Period of Time Notional Amounts(1) Fixed Interest Rates(2) Margin Rates(3) Fixed Interest Rates(4) ---------------------------------- ----------------------- ------------------------ ------------------ ------------------------ Dec 31, 2003 thru Dec 31, 2004 $ 30,000,000 2.660% 2.500% 5.160% Dec 31, 2004 thru Dec 31, 2005 $ 20,000,000 4.050% 2.250% 6.300% Dec 31, 2005 thru Dec 20, 2006 $ 10,000,000 4.050% 2.250% 6.300% ---------------- (1) Based on the anticipated principal reductions under our credit facility. (2) Parallel's swap contract with BNP Paribas. (3) Based on the anticipated borrowing base usage under our credit facility. (4) Total of the libor fixed interest rate plus the expected margin rate under our credit facility. Commodity Price Sensitivity as of December 31, 2003 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 gas production have been volatile and unpredictable. We expect pricing volatility to continue. Oil prices ranged from a low of $16.49 per barrel to a high of $36.60 per barrel during 2003. Natural gas prices we received during 2003 ranged from a low of $1.98 per Mcf to a high of $10.28 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. Put Options. On May 24, 2002 we purchased put floors on volumes of 100,000 Mcf per month for a total of 700,000 Mcf during the seven month period from April 2003 through October 2003 at a floor price of $3.00 per Mcf for a total consideration of $139,500. These derivatives are not held for trading purposes. A decrease in fair value of the put floors of approximately $22,000 was recognized for the period ended December 31, 2003 in our consolidated statements of operations. Costless Collar. Collars are created by purchasing puts to establish a floor price and then selling a call which establishes a maximum amount the producer will receive for the oil or gas hedged. Calls are sold to offset or reduce the premium paid for buying the put. We did not have any collars in place during 2002. In 2003, we entered into several costless, seven-month -63- Houston ship channel gas collars. A majority of our natural gas production is sold based on Houston ship channel prices. A recap for the period of time, number of MMBtu's and gas prices is as follows: Houston Ship Channel gas prices MMBtu of --------------------------------- Period of Time Natural Gas Floor Cap --------------------------------------------- ------------- ------------ ------------------- January 1, 2004 thru March 31, 2004 273,000 $ 5.43 $ 6.58 April 1 2004 thru October 31, 2004 214,000 $ 4.40 $ 5.50 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 price into a fixed price. For any particular swap transaction, the counterparty is required to make a payment to the hedge party if the reference price for any settlement period is less than the swap price for such hedge, and the hedge party is required to make a payment to the counterparty if the reference price for any settlement period is greater than the swap price for such hedge. In 2003, we entered into oil and gas swap contracts with BNP Paribas. A recap for the period of time, number of MMBtu's, number of barrels, and swap prices are as follows: Barrels Houston Ship of Nymex Oil MMBtu of Channel Period of Time Oil Swap Price Natural Gas Gas Swap Price -------------------------------------------------- ------------- -------------- --------------- ------------------- January 1, 2004 thru December 31, 2004 439,200 $ 24.45 - $ - April 1, 2004 thru December 31, 2004 - $ - 764,000 $ 4.692 January 1, 2005 thru December 31, 2005 365,000 $ 23.35 - $ - January 1, 2005 thru March 31, 2005 - $ - 180,000 $ 4.705 January 1, 2006 thru December 20, 2006 265,500 $ 23.04 - $ - ------------------------------------------------------------------------------- ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ------------------------------------------------------------------------------- Parallel's financial statements and supplementary financial data are included in this report beginning on page F-1. -64- ------------------------------------------------------------------------------- ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE ------------------------------------------------------------------------------- Resignation of KPMG LLP On December 4, 2003, we received written notice from KPMG LLP confirming that the client-auditor relationship between Parallel and KPMG had ceased as of December 2, 2003. KPMG resigned due to an independence issue arising from retirement benefits paid to Ray M. Poage, a former partner of KPMG who is also a director of Parallel. For the period from April 28, 2003 to December 2, 2003, Mr. Poage received eight monthly retirement payments from KPMG, each in the amount of $856.26. KPMG's audit reports on our financial statements for the two fiscal years ended December 31, 2001 and December 31, 2002 did not contain an adverse opinion or disclaimer of opinion and were not qualified or modified as to audit scope or accounting principles. During the two fiscal years ended December 31, 2001 and December 31, 2002 and the period from January 1, 2003 through December 2, 2003, there were no disagreements between Parallel and KPMG on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which, if not resolved to the satisfaction of KPMG would have caused it to make reference to the subject matter of the disagreement in connection with its report on the financial statements for that period, nor have there been any reportable events as defined under Item 304(a)(1)(v) or regulation S-K during such period. We provided KPMG with a copy of our Current Report on Form 8-K, dated December 2, 2003 and filed with the SEC on December 9, 2003, reporting KPMG's resignation. We requested that KPMG furnish us with a letter addressed to the Securities and Exchange Commission stating whether it agreed with the statements we made in our Form 8-K Report and, if not, stating the respects in which it did not agree. KPMG's letter, filed as an exhibit to the Form 8-K Report, expressed agreement with our statements. Engagement of BDO Seidman, LLP Effective January 20, 2004, we engaged BDO Seidman, LLP as the principal accountant to audit our financial statements. The decision to engage BDO Seidman was recommended and approved by the Audit Committee of our Board of Directors. During the two fiscal years ended December 31, 2001 and December 31, 2002 and during any subsequent interim period, BDO Seidman was not engaged as either the principal accountant to audit our financial statements or as an independent accountant to audit a significant subsidiary and on whom the principal accountant was expected to express reliance on its report. In addition, during the two most recent fiscal years and during any subsequent interim period prior to engaging BDO Seidman, neither we, nor anyone on our behalf consulted BDO Seidman -65- regarding (a) either the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on our financial statements, and no written report was provided to us and no oral advice was provided to us by BDO Seidman which was considered by us in reaching a decision as to the accounting, auditing or financial reporting issues; and (b) there was no matter that was a subject of disagreement as defined in paragraph 304(a)(1)(iv) of Regulation S-K, or a reportable event, as described in paragraph 304(a)(1)(v) of Regulation S-K. ------------------------------------------------------------------------------- ITEM 9A. CONTROLS AND PROCEDURES ------------------------------------------------------------------------------- We use certain disclosure controls and procedures to help ensure that information we are required to disclose in reports that we file with the SEC 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 Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934) was evaluated by Larry C. Oldham, our President and Chief Executive Officer (principal executive officer), and Steven D. Foster, our Chief Financial Officer (principal financial officer). Mr. Oldham and Mr. Foster have concluded that our disclosure controls and procedures are effective, as of the end of the period covered by this Annual Report on Form 10-K, for their intended purposes. There were no changes in our internal controls over financial reporting that occurred during our last fiscal quarter (the quarter ended December 31, 2003) that have materially affected, or are reasonably likely to materially affect our internal controls over financial reporting. -66- PART III ------------------------------------------------------------------------------- ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT ------------------------------------------------------------------------------- The Directors and executive officers of Parallel at March 1, 2004 are as follows: Director Name Age Since Position with Company ---------------------------------------- ------------ ------------ ------------------------------------------------------- Thomas R. Cambridge(1) 68 1985 Chairman of the Board of Directors Larry C. Oldham(1) 50 1979 Director, President and Chief Executive Officer Dewayne E. Chitwood (2)(3)(4) 67 2000 Director Martin B. Oring(1)(2)(3)(4) 58 2001 Director Charles R. Pannill(2)(4) 78 1982 Director Ray M. Poage(2)(3)(4) 56 2003 Director Jeffrey G. Shrader(1)(2)(4) 53 2001 Director Donald E. Tiffin 46 - Chief Operating Officer Eric A. Bayley 55 - Vice President of Corporate Engineering John S. Rutherford 44 - Vice President of Land and Administration Steven D. Foster 48 - Chief Financial Officer __________ (1) Member of Hedging and Acquisitions Committee (2) Member of Compensation Committee (3) Member of Audit Committee (4) Member of Corporate Governance and Nominating Committee Mr. Cambridge is an independent petroleum geologist engaged in the exploration for, development and production of oil and natural gas. From 1970 until 1990, his activities were carried out primarily through Cambridge & Nail Partnership. Since 1990, Mr. Cambridge's oil and gas activities have been carried out through Cambridge Production, Inc. He received a Bachelors degree in geology from the University of Nebraska in 1958 and a Master of Science degree in geology from the University of Nebraska in 1960. Mr. Cambridge served as Chief Executive Officer of Parallel from 1987 until January 1, 2004 when Mr. Oldham became Chief Executive Officer. 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 replaced Mr. Cambridge as Chief Executive Officer. Mr. Oldham received a Bachelor of Business Administration degree from West Texas State University in 1975. -67- Mr. Chitwood is president, chief executive officer and a manager of Wes-Tex Holdings, LLC, the general partner of Wes-Tex Drilling Company, L.P., a partnership engaged in oil and gas exploration and production. During the five-year period preceding Mr. Chitwood's association with Wes-Tex in 1997, he was an owner and founder of CBS Insurance L.P., a general insurance agency. Mr. Oring is the owner 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. Pannill was employed by The Western Company of North America for over thirty years until his retirement in February, 1982. During his employment with The Western Company of North America, Mr. Pannill served in various capacities, including those of an executive officer and director. He received a Bachelor of Science degree in Geology from Texas A&M University in 1950. Mr. Poage was employed by KPMG LLP from 1972 until June 2002 when he retired. Mr. Poage's 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 gas industry. He is a Certified Financial Planner and member of the American Institute of Certified Public Accountants and the Texas Society of Certified Public Accountants. At March 1, 2004 Mr. Poage was Chairman of the Audit Committee of the Board of Directors of Parallel. 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 March 1, 2004 Mr. Shrader was Chairman of the Compensation Committee of the Board of Directors of Parallel. 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 Master's of Business Administration degree. -68- 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 Parallel's 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 Master's 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. Directors hold office until the annual meeting of stockholders following their election or appointment and until their respective successors have been duly elected or appointed. Officers are appointed annually by the Board of Directors to serve at the Board's discretion and until their respective successors in office are duly appointed. There are no family relationships between any of Parallel's 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 Pursuant to the Delaware General Corporation Law and Parallel's 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 Parallel's business through discussions with 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 seven members of the Board. The Board has determined that all of the Directors, other than Mr. Cambridge and 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. -69- The Board has four standing committees: . The Audit Committee; . The Corporate Governance and Nominating Committee; . The Compensation Committee; and . The Hedging and Acquisitions Committee. Audit Committee The Audit Committee reviews the results of the annual audit of our 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 is also responsible for overseeing management's conduct of our financial reporting process, our systems of internal accounting and financial controls, and the independent audit of our financial statements. The Audit Committee is directly responsible for the appointment, compensation, retention and oversight of the work of the auditors. The Audit Committee of the Board of Directors consists of three 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 401(h) of Regulation S-K, and is independent for purposes of Nasdaq listing standards and Section 10A (m)(3) of the Securities Exchange Act of 1934, as amended. Mr. Poage's 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 pursuant to a charter, which was revised in March 2004. The charter can be viewed in our website on www.parallel-petro.com. From May 2001 until April 2003, the Audit Committee was composed of Mr. Oring (Chairman), Mr. Pannill and Mr. Shrader. Upon Mr. Poage's appointment to the Board of Directors in April 2003, Mr. Pannill resigned from the Audit Committee and Mr. Poage was appointed Chairman of the Audit Committee. Mr. Shrader resigned from the Audit Committee in October 2003, because the law firm with which Mr. Shrader is affiliated provided legal services to Parallel. Mr. Chitwood was then appointed to serve on the Audit Committee in place of Mr. Shrader. Since October 2003, the members of the Audit Committee have been and continue to be Messrs. Poage (Chairman), Chitwood and Oring. Corporate Governance and Nominating Committee At its March 15, 2004 meeting, the Board formed a Corporate Governance and Nominating Committee and adopted a charter for this new committee. The functions of the Corporate Governance and Nominating Committee will include: recommending to the Board of -70- 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 members of the new Corporate Governance and Nominating Committee are Dewayne E. Chitwood, Martin B. Oring, Charles R. Pannill, Ray M. Poage and Jeffrey G. Shrader. The Corporate Governance and Nominating Committee will operate under the charter setting out the functions and responsibilities of this committee. A copy of the charter can be viewed in our website at www.parallel-petro.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: . a statement that the writer is a stockholder and is proposing a candidate for consideration by the committee; . the name of and contact information for the candidate; . a statement of the candidate's age, business and educational experience; . information sufficient to enable the committee to evaluate the candidate; . a statement detailing any relationship between the candidate and any joint interest owners, customer, supplier or competitor of Parallel; . detailed information about any relationship or understanding between the proposing stockholder and the candidate; and . a statement that the candidate is willing to be considered and willing to serve as a Director if nominated and elected. Compensation Committee The members of the Compensation Committee at March 1, 2004 were Dewayne E. Chitwood, Martin B. Oring, Charles R. Pannill, Ray M. Poage and Jeffrey G. Shrader. Mr. Shrader presently acts as the Chairman of the Compensation Committee. The Compensation Committee's responsibilities include reviewing and recommending to the Board the compensation and terms of benefit arrangements with Parallel's officers, and the making of awards under such arrangements. -71- Hedging and Acquisitions Committee The Hedging and Acquisitions Committee presently consists of four Directors, including Messrs. Oring, Shrader, Oldham and Cambridge. With respect to hedging, the committee reviews, assists, and advises management on overall risk management strategies and techniques. The committee strives to implement prudent commodity and interest rate hedging arrangements, and monitors our compliance with certain covenants in our revolving credit facility. The Hedging and Acquisitions Committee also reviews with management oil and gas acquisition opportunities, and consults with members of management to review plans and strategies for pursing acquisitions. Code of Ethics On March 15, 2004, the Board also adopted a code of ethics as part of our efforts to comply with the Sarbanes-Oxley Act of 2002 and rule changes made by the Securities and Exchange Commission and Nasdaq. Our code of ethics 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.parallel-petro.com. We have also filed a copy of our code of ethics with the Securities and Exchange Commission 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: . if you request, forward the communication to the other Directors; . 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 . 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. -72- 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 seven of the individuals then serving as Director attended our annual meeting of stockholders. ------------------------------------------------------------------------------- ITEM 11. EXECUTIVE COMPENSATION ------------------------------------------------------------------------------- Summary of Annual Compensation The table below shows a summary of the types and amounts of compensation paid to Mr. Cambridge, our Chief Executive Officer for the last three fiscal years, and the type and amounts of compensation paid to each of the four most highly compensated executive officers, based on salary and bonus for 2003. Compensation Table ----------------------------------------------------------------------------------------------------------------------------------- Long-Term Compensation ----------------------------------- Annual Compensation Awards Payouts --------------------------------------------------- ---------------------- ---------- Other Restricted Securities All Annual Stock Underlying LTIP Other Name and Salary Bonus Compensation Awards Options/ Payouts Compensation Principal Position Year ($) ($)(1) ($) ($) SAR (#) ($) ($) --------------------------- -------- ------------- ------------- ------------ ----------- ----------- ---------- ------------ T. R. Cambridge 2003 $ 110,000 $ 25,000 $ - 0 0 0 0 Chairman of the Board and 2002 $ 106,284 $ 158,888 $ 450 0 0 0 0 Chief Executive Officer 2001 $ 91,362 $ 26,000 $ 900 0 100,000 0 0 L. C. Oldham 2003 $ 191,000 $ 61,391 $ 20,198 (2) 0 0 0 $ 14,064 (3) President and Director 2002 $ 187,316 $ 555,674 $ 17,850 0 0 0 $ 11,113 2001 $ 170,392 $ 26,000 $ 17,922 0 200,000 0 $ 14,470 E. A. Bayley 2003 110,000 $ 23,391 $ 16,470 (4) 0 0 0 $ 6,600 (5) Vice President 2002 $ 111,792 $ 172,178 $ 16,127 0 0 0 $ 6,303 2001 $ 96,155 $ 13,000 $ 15,705 0 50,000 0 $ 6,489 J. S. Rutherford 2003 $ 110,000 $ 23,391 $ 15,763 (6) 0 0 0 $ 6,600 (7) Vice President 2002 $ 110,384 $ 410,352 $ 16,540 0 0 0 $ 6,488 2001 $ 103,411 $ 13,000 $ 15,028 0 50,000 0 $ 6,925 D. E. Tiffin 2003 $ 171,140 $ 44,391 $ 17,464 (8) 0 0 0 $ 10,268 (9) Vice President 2002 $ 99,832 $ 47,421 $ 8,257 0 50,000 0 $ 5,990 -------------- (1) The bonuses paid to Messrs. Cambridge, Oldham, Bayley and Rutherford during 2002 includes payments made to them under Incentive Award Agreements as a result of the sale of First Permian's assets. Parallel entered into these Incentive Award Agreements with Messrs. Cambridge, Oldham, Bayley, Rutherford and four other employees in December 2001 to provide an incentive to the participants and to reward outstanding efforts and achievements by them when a material contribution to Parallel's success resulted from an Award Event. An Award Event generally meant an acquisition of First Permian, a sale of substantially all of First Permian's assets, or Parallel's sale or other disposition of its 30.675% ownership interest in First Permian. The agreements awarded Unit Equivalent Rights to the recipients. A Unit Equivalent Right was essentially equivalent to a Common Unit of common membership interest in First Permian. At March 1, 2002, First -73- Permian had outstanding 1,140,992 Common Units and 1,350,000 Preferred Units. Parallel owned 350,000 Common Units of First Permian. The Unit Equivalent Rights entitled the recipient to a one-time cash bonus. Payment of the bonus was triggered by the occurrence of an Award Event. The amount of a bonus payment was defined as the difference between $30.00 per Common Unit and the price per Common Unit received by First Permian's holders of Common Units in a transaction constituting an Award Event, multiplied by the number of Unit Equivalent Rights granted to the recipient. To illustrate, assuming the holders of First Permian's Common Units received $100.00 per Common Unit from a sale of assets, a recipient of 1,000 Unit Equivalent Rights would be entitled to receive a cash payment equal to $70.00 ($100.00 minus $30.00) multiplied by 1,000, or $70,000. Under these Incentive Award Agreements, 9,565 Unit Equivalent Rights were granted to Mr. Oldham; 2,394 were granted to Mr. Cambridge; 2,869 to Mr. Bayley; and 7,173 to Mr. Rutherford. In April, 2002 an Award Event occurred when First Permian sold all of its oil and gas properties to Energen Corporation. Because shares of Energen Corporation's common stock were a component of the total purchase price for First Permian's properties, the portion of the bonus payments attributable to the Energen stock was based upon the price at which we sold our shares of Energen stock. Under these agreements, Mr. Cambridge received $132,480; Mr. Oldham - $529,266; Mr. Bayley - $158,770; and Mr. Rutherford - $396,944. The Incentive Award Agreements automatically terminated upon payment of the bonuses. Mr. Tiffin received a signing and inducement bonus in the amount of $46,013 when he joined Parallel in June 2002. (2) These amounts include insurance premiums for nondiscriminatory group life, medical, disability and dental insurance as follows: $19,697 for 2003; $17,647 for 2002; and $16,366 for 2001. (3) For 2003, such amount includes $11,460 contributed by Parallel to Mr. Oldham's individual retirement account maintained under Parallel's 408(k) simplified employee pension plan/individual retirement account, and $2,604 for income tax preparation and planning. For 2002, such amount includes $11,113 contributed by Parallel to Mr. Oldham's individual retirement account maintained under Parallel's 408(k) simplified employee pension plan/individual retirement account, and the reimbursement of $4,624 for income tax preparation and planning. For 2001, such amount includes $11,482 contributed by Parallel to Mr. Oldham's retirement account and the reimbursement to Mr. Oldham of $2,988 for income tax preparation and planning. (4) This amount includes insurance premiums for nondiscriminatory group life, medical, disability and dental insurance as follows: $16,470 for 2003; $15,150 for 2002; and $14,808 for 2001. (5) This amount represents Parallel's contribution to Mr. Bayley's individual retirement account maintained under the 408(k) simplified employee pension plan/individual retirement account. (6) This amount includes insurance premiums for nondiscriminatory group life, medical, disability and dental insurance as follows: $15,763 for 2003; $14,221 for 2002; and $13,155 for 2001. (7) This amount represents Parallel's contribution to Mr. Rutherford's individual retirement account maintained under the 408(k) simplified employee premium plan/individual retirement account. (8) This amount includes insurance premiums for nondiscriminatory group life, medical, disability and dental insurance as follows: $16,964 for 2003; and $8,150 for 2002. (9) This amount represents Parallel's contribution to Mr. Tiffin's individual retirement account maintained under the 408(k) simplified employee premium plan/individual retirement account. Stock Options We use stock options as part of the overall compensation of directors, officers and employees. However, we did not grant any stock options in 2003 to any of the executive officers named in the Summary Compensation Table. Summary descriptions of our stock option plans are included in this report so you can review the types of options we have granted in the past and the significant features of our stock options. In the table below, we show certain information about the exercise of stock options in 2003 and the value of unexercised stock options held by the named executive officers at December 31, 2003. -74- Aggregated Option/SAR Exercises in Last Fiscal Year and Fiscal Year-End Option/SAR Values Value of Number of Securities Underlying Unexercised Shares Acquired Value Unexercised Options at Fiscal in-the-Money Options on Realized Year-End (#) at Fiscal Year-End ($)(2) ----------------------------------- -------------------------------------- Name Exercise ($)(1) Exercisable Unexercisable Exercisable Unexercisable -------------------- ------------------- ------------ ------------------ ---------------- ------------------ ----------------- T.R. Cambridge 0 0 300,000 0 190,000 (3) 0 L.C. Oldham 0 0 340,000 60,000 328,700 (4) 0 (4) E. A. Bayley 0 0 205,000 0 156,730 (5) 0 J.S. Rutherford 0 0 158,750 0 120,230 (6) 0 D.E. Tiffin 0 0 25,000 25,000 54,250 54,250 ----------------- (1) The value realized is equal to the fair market value of a share of common stock on the date of exercise, less the exercise price of the stock options exercised. (2) The value of unexercised in-the-money options is equal to the fair market value of a share of common stock at fiscal year-end ($4.35 per share), based on the last sale price of Parallel's common stock, less the exercise price. (3) At December 31, 2003, the exercise prices of exercisable options to purchase a total of 100,000 shares of common stock held by Mr. Cambridge exceeded $4.35, the fair market value of our common stock on that date. (4) At December 31, 2003, the exercise prices of exercisable options to purchase a total of 140,000 shares of common stock held by Mr. Oldham exceeded $4.35, the fair market value of our common stock on that date. In addition, an unexercisable stock option to purchase 60,000 shares of common stock was held by Mr. Oldham at fiscal year-end, which also had an exercise price greater than $4.35. (5) At December 31, 2003, the exercise prices of exercisable options to purchase a total of 100,000 shares of common stock held by Mr. Bayley exceeded $4.35, the fair market value of our common stock on that date. (6) At December 31, 2003, the exercise prices of exercisable options to purchase a total of 93,750 shares of common stock held by Mr. Rutherford exceeded $4.35, the fair market value of our common stock on that date. Change of Control Arrangements Stock Option Plans Parallel's outstanding stock options and stock option plans contain certain change of control provisions which are applicable to Parallel's outstanding stock options, including the options held by our officers and Directors. For purposes of our options, a change of control occurs if: . Parallel is not the surviving entity in a merger or consolidation; . Parallel sells, leases or exchanges all or substantially all of its assets; . Parallel is to be dissolved and liquidated; -75- . any person or group acquires beneficial ownership of more than 50% of Parallel's 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. 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 Parallel's stockholders in a merger, consolidation, sale of assets or dissolution transaction; . the price per share offered to Parallel's 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. Change of Control Agreements In June, 2001, Parallel entered into Change of Control Agreements with Mr. Cambridge, Mr. Oldham, Mr. Bayley, Mr. Rutherford and four other employees. The Compensation Committee determined not to renew these agreements and they expired by their own terms in June 2003. The agreements provided that upon the occurrence of a Change of Control, each person would be entitled to receive a single lump sum cash payment in an amount equal to one year's salary. The agreements also provided for continued participation in Parallel's medical, -76- dental, disability and life insurance and retirement plans for a period of twelve months after a Change of Control. A Change of Control would have occurred if: . any person became the beneficial owner of Parallel's voting shares entitling that person to 20% or more of the voting power of Parallel; . the stockholders of Parallel approved a transaction providing for (1) Parallel to be merged, consolidated or otherwise combined with another person, (2) the sale of all or substantially all the assets or stock of Parallel or (3) the liquidation or dissolution of Parallel; or . less than a majority of the members of the Board were continuing directors. A continuing director meant a director of Parallel who either (1) was a director of Parallel on June 1, 2001, the date of the Change of Control Agreements or (2) was an individual whose appointment, election, or nomination for election, as a director of Parallel was approved by a vote of at least a majority of the directors of Parallel then still in office who were continuing directors (other than an individual whose initial assumption of office was in connection with an actual or threatened election contest relating to the election of the directors of Parallel). Compensation of Directors In 2003, Parallel's nonemployee Directors each received $1,500 for attending meetings of the Board of Directors. Nonemployee Directors who are members of a Board committee also received the following fees: . $750 per meeting for service on the Compensation Committee, with the Chairman of the Compensation Committee being entitled to receive an additional fee of $5,000 per year; . $750 per meeting for service on the Audit Committee, with the Chairman of the Audit Committee being entitled to receive an additional fee of $10,000 per year and each other Audit Committee member receiving $5,000 per year; and . $750 per meeting for service on the Hedging and Acquisitions Committee. Under these arrangements, for 2003, Mr. Pannill received $35,000; Mr. Chitwood - $30,000 Mr. Shrader - $56,500; Mr. Poage - $35,250; and Mr. Oring - $52,750. All Directors are reimbursed for expenses incurred in connection with attending meetings. Directors who are not employees of Parallel are eligible to participate in Parallel's 1997 Nonemployee Directors Stock Option Plan and the 2001 Nonemployee Directors Stock Option Plan. As previously reported, on April 28, 2003, Mr. Poage was granted a stock option to purchase 50,000 shares of common stock at an exercise price of $2.61 per share, the fair market value of the common stock on that date. The option becomes exercisable as to one-half of the -77- shares on April 28, 2004 and the remaining one-half become exercisable on April 28, 2005. The option expires ten years from the grant date. 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 nonemployee Directors are not incentive stock options. The 1992 Plan is administered by the Board's 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 nonemployee 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. An option may be granted in exchange for an individual's right and option to purchase shares of common stock pursuant to the terms of a prior option agreement. An agreement that grants an option in exchange for a prior option must provide for the surrender and cancellation of the prior option. The purchase price of common stock issued under an option granted in exchange for a prior option is determined by the Compensation Committee and may be equal to the price for which the optionee could have purchased common stock under the prior option. At 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 March 1, 2004, options to purchase a total of 358,750 shares of common stock were outstanding under the 1992 Plan. 1997 Nonemployee Directors Stock Option Plan. The Parallel Petroleum 1997 Non-Employee 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 -78- 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 nonemployee Directors who are to be granted options; to establish the number of shares which may be issued to nonemployee 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 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 or stock, as established by the Compensation Committee. Options may not be granted under this plan after March 27, 2007. At March 1, 2004, options to purchase a total of 320,000 shares of common stock were outstanding under this plan. At March 1, 2004, options to purchase 142,500 shares of common stock were available for future grants 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. 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 or 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. -79- Options may not be granted under the 1998 Plan after March 11, 2008. At March 1, 2004, options to purchase a total of 809,400 shares of common stock were outstanding under this plan. At March 1, 2004, there were no available options to purchase shares of common stock for future grant under the 1998 Stock Option Plan. 2001 Nonemployee Directors Stock Option Plan. The Parallel Petroleum 2001 Non-employee 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 nonemployee Directors who are to be granted options; to establish the number of shares which may be issued to nonemployee 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 or stock, as established by the Compensation Committee. Options may not be granted under this plan after May 2, 2011. At March 1, 2004, options to purchase 450,000 shares of common stock were outstanding under this plan. At March 1, 2004, there were available for future grant under this plan options to purchase 50,000 shares of common stock. Employee Stock Option Plan. In June, 2001, our Board of Directors adopted the Parallel Petroleum 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. The Employee Stock Option Plan is administered 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. -80- 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 or 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. Unless some of the options that have been granted under the plan are forfeited and again become available for future grant, no additional options may be granted under this plan. At March 1, 2004, options to purchase 200,000 shares of common stock were outstanding under this plan. Other Option Grants. The Board of Directors granted a nonqualified stock option to Mr. Cambridge in October, 1993 under the general corporate powers of Parallel, without stockholder approval. Upon recommendation of the Board's Compensation Committee, the Board granted the option to Mr. Cambridge to purchase 100,000 shares of common stock at an exercise price of $3.9375 per share, the fair market value of the common stock on the grant date. The option is not transferable, except by will or the laws of descent and distribution. The option expired in October, 2003. Retirement Plan Parallel maintains under Section 408(k) of the Internal Revenue Code a combination simplified employee pension and individual retirement account plan for eligible employees. Generally, eligible employees include all employees who are at least twenty-one years of age. Contributions to employee SEP accounts may be made at the discretion of Parallel, as authorized by the Compensation Committee of the Board of Directors. The percentage of contributions may vary from time to time. However, the same percentage contribution must be made for all participating employees. Parallel is not required to make annual contributions to the SEP accounts. Under the prototype simplified employee pension plan adopted by Parallel, all of the SEP contributions must be made to SEP/IRAs maintained with the sponsor of the plan, a national investment banking firm. All contributions to employees' accounts are immediately 100% vested and become the property of each employee at the time of contribution, including employer contributions, income-deferral contributions and IRA contributions. Generally, earnings on contributions to an employee's SEP/IRA account are not subject to federal income tax until withdrawn. -81- In addition to receiving SEP contributions made by Parallel, employees may make individual annual IRA contributions of up to the maximum of $12,000. Maximum total contribution for Parallel and Parallel's employees can be no more than $40,000. In addition to the annual salary deferral limit stated above, employees who reach age 50 or older during a calendar year can elect to take advantage of a catch-up salary deferral contribution; eligible participants can increase their salary deferral by $2,000 for the year 2003. Each employee is responsible for the investment of funds in his or her own SEP/IRA and can select investments offered through the sponsor of the plan. Distributions may be taken by employees at any time and must commence by April 1st following the year in which the employee attains age 70 1/2. Parallel presently makes matching contributions to employee accounts in an amount equal to the contribution made by each employee, not to exceed, however, 6% of each employee's salary during any calendar year. During 2003, Parallel contributed an aggregate of $105,822 to the accounts of 23 employee participants. Of this amount, $11,460 was allocated to Mr. Oldham's account; $6,600 was allocated to Mr. Bayley's account; $6,600 was allocated to Mr. Rutherford's account; $10,268 to Mr. Tiffin's account; and $6,360 to Mr. Foster's account. ------------------------------------------------------------------------------- ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS ------------------------------------------------------------------------------- This table shows information as of March 12, 2004 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) the executive officers named in the Summary Compensation Table in this report; (3) each director of Parallel; and (4) all of Parallel's executive officers and directors as a group. -82- Name and Address Amount and Nature Percent of of of Beneficial Owner Beneficial Ownership(1) Class(2) --------------------------------------- ------------------------- ------------------------ Thomas R. Cambridge 1,057,045 (3) 4.14% 2201 Civic Circle, Suite 216 Amarillo, Texas 79109 Dewayne E. Chitwood 1,656,057 (4) 6.38% 400 Pine St., Suite 700 Abilene, Texas 79601 Larry C. Oldham 887,090 (5) 3.46% 1004 N. Big Spring, Suite 400 Midland, Texas 79701 Martin B. Oring 190,666 (6) * 706 Cinnamon Lane Franklin Lakes, New Jersey 07417 Charles R. Pannill 173,495 (7) * 3416 Acorn Run Fort Worth, Texas 76019 Ray M. Poage 25,000 (8) * 4711 Meandering Way Colleyville, Texas 76034 Jeffrey G. Shrader 100,000 (9) * 801 S. Filmore, Suite 600 Amarillo, Texas 79105 Eric A. Bayley 224,490 (10) * 1004 N. Big Spring, Suite 400 Midland, Texas 79701 John S. Rutherford 166,300 (11) * 1004 N. Big Spring, Suite 400 Midland, Texas 79701 Donald E. Tiffin 35,415 (12) * 1004 N. Big Spring, Suite 400 Midland, Texas 79701 Wes-Tex Drilling Company, L.P. 1,246,773 (13) 4.88% 519 First National Bank Building West Abilene, Texas 79601 Crestview Capital Fund II, L.P. 1,323,000 5.24% 95 Revere Drive, Suite F Northbrook, Illinois 60062 Julia Jones Matthews 1,942,856 (14) 7.36% 400 Pine, Suite 900 Abilene, Texas 79601 Dodge Jones Foundation 1,371,428 (15) 5.23% 400 Pine, Suite 900 Abilene, Texas 79601 All Executive Officers and Directors as a Group (11 persons) 4,537,058 (16) 16.55% ------------------ *Less than one percent. -83- (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 upon exercise of outstanding stock options and warrants or upon conversion of preferred stock are deemed to be outstanding. (3) Includes 757,045 shares of common stock held indirectly through Cambridge Collateral Services, Ltd., a limited partnership of which Mr. Cambridge and his wife are the general partners. Also included are 300,000 shares of common stock underlying presently exercisable stock options held by Mr. Cambridge. (4) Includes 932,488 shares of common stock held directly by Wes-Tex Drilling Company, L.P., a limited partnership, and 314,285 shares of common stock that may be acquired by Wes-Tex Drilling Company, L.P. upon conversion of 110,000 shares of preferred stock. In his capacity as president, chief executive officer and a manager of Wes-Tex Holdings, LLC, the general partner of Wes-Tex Drilling Company, L.P., Mr. Chitwood may be deemed to have shared voting and investment powers with respect to such shares. See note 13 below. Also included are 20,000 shares of common stock held by the Estate of Myrle Greathouse (the "Estate"); 157,142 shares that may be acquired by the Greathouse Charitable Remainder Trust (the "Trust") upon conversion of 55,000 shares of preferred stock; and 157,142 shares of common stock that may be acquired by the Greathouse Foundation (the "Foundation") upon conversion of 55,000 shares of preferred stock. Mr. Chitwood is the executor (but not a beneficiary) of the Estate, the trustee (but not a beneficiary) of the Trust and the executive director and a director of the Foundation. In these capacities, Mr. Chitwood may also be deemed to have shared voting and investment powers with respect to the shares of common stock beneficially owned by the Estate, the Trust and the Foundation. However, Mr. Chitwood disclaims beneficial ownership of all shares of common stock held by Wes-Tex Drilling Company, L.P., the Estate, Trust and Foundation. Also included are 75,000 shares of common stock underlying presently exercisable stock options held by Mr. Chitwood. (5) Includes 200,000 shares of common stock held indirectly through Oldham Properties, Ltd., a limited partnership of which Mr. Oldham is the general partner and he and his wife are the limited partners. Also included are 350,000 shares of common stock underlying presently exercisable stock options held by Mr. Oldham. (6) Of the total number of shares shown, 24,000 shares are held directly by Mr. Oring's wife; 75,000 shares may be acquired by Mr. Oring upon exercise of stock options held by Mr. Oring; and 91,666 shares may be acquired upon exercise of a stock purchase warrant. (7) Includes 135,000 shares of common stock underlying presently exercisable stock options. Also included are 1,300 shares held by Mr. Pannill as custodian for the benefit of two minor grandchildren and as to which Mr. Pannill disclaims beneficial ownership. (8) All of such shares may be acquired upon exercise of presently exercisable stock options. (9) Includes 75,000 shares of common stock underlying presently exercisable stock options. (10) Includes 205,000 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 individual retirement accounts and Parallel's 408(K) Plan. (11) Includes 158,750 shares of common stock underlying presently exercisable stock options. Also included are 7,550 shares held indirectly by Mr. Rutherford through his 408(k) Plan. (12) Of the total number of shares shown 6,500 shares are held indirectly through Mr. Tiffin's individual retirement account. Includes 25,000 shares of common stock underlying presently exercisable stock options. (13) Includes 314,285 shares of common stock that may be acquired upon conversion of 110,000 shares of preferred stock. See note 4 above. (14) Includes 400,000 shares of common stock owned directly by the Julia Jones Matthews Family Trust and 171,428 shares of common stock that may be acquired by the Trust upon conversion of 60,000 shares of preferred stock held directly by the Trust. By virtue of her position as the President and a Director of the Dodge Jones Foundation, Matthews has shared voting and investment powers with respect to, and may also be deemed to be the beneficial owner of, 971,428 shares of common stock that may be acquired by the Dodge Jones Foundation upon conversion of 340,000 shares of preferred stock held by it, and 400,000 shares of common stock that are owned directly by the Dodge Jones Foundation. Matthews disclaims beneficial ownership of all shares of common stock beneficially owned by the Dodge Jones Foundation. See note 15. -84- (15) Includes 971,428 shares that may be acquired upon conversion of 340,000 shares of preferred stock. The Dodge Jones Foundation has shared voting and investment powers with respect to such shares of common stock. See note 14. (16) Includes 1,579,416 shares of common stock underlying stock options that are presently exercisable or that become exercisable within sixty days and 628,569 shares of common stock that may be acquired upon conversion of 220,000 shares of preferred stock. Section 16(a) Beneficial Ownership Reporting Compliance Section 16(a) of the Securities Exchange Act of 1934 requires Parallel's Directors and officers to file periodic reports with the SEC. These reports show the Directors' and officers' ownership and the changes in ownership, of Parallel's common stock and other equity securities. To our knowledge, all Section 16(a) filing requirements were complied with during 2003, except that Mr. Tiffin filed one Form 4 report two days late which reported his purchase of 6,200 shares of Parallel's common stock. ------------------------------------------------------------------------------- ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ------------------------------------------------------------------------------- Mr. Chitwood, a director of Parallel, has been the Chief Executive Officer of Wes-Tex Drilling Company, L.P. since January 30, 2001. He was appointed to Parallel's Board on December 19, 2000 to fill a vacancy created by the death of a former director of Parallel. The former director was also the sole owner of Wes-Tex Drilling Company, L.P. In 1994, the predecessor of Wes-Tex Drilling Company, L.P. acquired an undivided working interest from Parallel in an oil and gas prospect located in Howard County, Texas. Since then, Wes-Tex has participated with us and other interest owners in the drilling and development of this prospect. Wes-Tex has participated in these operations under standard form operating agreements on the same or similar terms afforded by Parallel to nonaffiliated third parties. We invoice all working interest owners, including Wes-Tex, on a monthly basis, without interest, for their pro rata share of lease acquisition, drilling and operating expenses. During 2003, we billed Wes-Tex approximately $23,000 for its proportionate share of lease operating expenses incurred on properties we operate. The largest amount owed to us by Wes-Tex at any one time during 2003 for its share of lease operating expenses was approximately $6,000. At December 31, 2003, Wes-Tex owed us approximately $3,800 for these expenses. During 2003, we disbursed approximately $74,000 to Wes-Tex in payment of revenues attributable to Wes-Tex's pro rata share of the proceeds from sales of oil and gas produced from properties in which Wes-Tex and Parallel owned interests. Mr. Chitwood is not an owner of Wes-Tex and has no interest in these transactions other than in his capacity as an officer of Wes-Tex. During 2003, Cambridge Production, Inc., a corporation owned by Mr. Cambridge, served as operator of 2 wells on oil and 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 gas contracts, joint interest billings, revenue distribution, making various regulatory filings, reporting to working -85- interest owners and other matters. During 2003, Cambridge Production billed us approximately $51,000 for our pro rata share of lease operating expenses and drilling and workover expenses all of which we paid in 2003. The largest amount we owed Cambridge Production at any one time during 2003 was approximately $20,000. At December 31, 2003, no amounts were owed by us to Cambridge Production. Our pro rata share of oil and gas sales during 2003 from the wells operated by Cambridge Production was $198,000. Cambridge Production's billings to Parallel are made monthly on the same basis as all other working interest owners in the wells. Cambridge Production, Inc. maintains an office in Amarillo, Texas from which Mr. Cambridge performs his duties and services as Chairman of the Board and as geological consultant to Parallel. We reimburse Cambridge Production, Inc. $3,000 per month for office and administrative expenses incurred on behalf of Parallel. During 2003 we reimbursed Cambridge Production, Inc. a total of $36,000. 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. ------------------------------------------------------------------------------- ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES ------------------------------------------------------------------------------- KPMG LLP audited our financial statements for the year ended December 31, 2002 and for the prior eighteen years. However, as described under Item 9 of this Annual Report on Form 10-K, KPMG resigned in December 2003. Prior to KPMG's resignation, KPMG provided audit and tax services in 2003. In January 2004, we engaged BDO Seidman, LLP as our independent auditors. 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 has pre-approved 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 Committee's responsibilities to Parallel's management. -86- The aggregate fees for professional services by BDO and KPMG in 2003 and 2002 were: BDO KPMG ------------------ ----------------------------------- Types of Fees 2003 2003 2002 ------------------------ ------------------ ----------------- ----------------- (dollars in thousands) Audit fees $ 140 $ 120 $ 113 Audit-related fees - 61 2 Tax fees - 28 43 All other fees - - - ------------------ ----------------- ----------------- Total $ 140 $ 209 $ 158 ================== ================= ================= In the above table, "audit fees" are fees we paid for professional services for the audit of our financial statements included in Form 10-K and review of financial statements included in Form 10-Qs, or for services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements; "audit-related fees" are fees billed for assurance and related services (such as due diligence services) that are reasonably related to the performance of the audit or review of our financial statements; "tax fees" are fees for tax compliance, advice and planning; and "all other fees" are fees billed to Parallel for any services not included in the first three categories. PART IV ------------------------------------------------------------------------------- ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K ------------------------------------------------------------------------------- (a) The following documents are filed as part of this report: For a list of Financial Statements and Schedules, see "Index to the Financial Statements" on page F-1, and incorporated herein by reference. (b) We filed the following Current Reports on Form 8-K during the fiscal quarter ended December 31, 2003: Form 8-K on October 29, 2003 pursuant to Item 7 (Financial Statements and Exhibits), Item 9 (Regulation FD Disclosure) and Item 12 (Results of Operations and Financial Condition) announcing Parallel's results of operations and financial condition for the third fiscal quarter ended September 30, 2003. Form 8-K on December 9, 2003 pursuant to Item 4 (Changes in Registrant's Certifying Accountant), announcing the resignation of KPMG LLP. -87- Form 8-K on December 24, 2003 pursuant to Item 5 (Other Events), announcing the completion of Parallel's private placement of common stock. (c) Exhibits: No. Description of Exhibit ----- ----------------------- 3.1 Certificate of Incorporation of Registrant (Incorporated by reference to Exhibit 3.1 to Form 10-K of the Registrant for the fiscal year ended December 31, 1998) 3.2 Bylaws of Registrant (Incorporated by reference to Exhibit 3 to the Registrant's Form 8-K, dated October 9, 2000, as filed with the Securities and Exchange Commission on October 10, 2000) 4.1 Certificate of Designations, Preferences and Rights of Serial Preferred Stock - 6% Convertible Preferred Stock (Incorporated by reference to Exhibit 4.1 to Form 10-Q of the Registrant for the fiscal quarter ended September 30, 1998) 4.2 Certificate of Designation, Preferences and Rights of Series A Preferred Stock (Incorporated by reference to Exhibit 4.2 to 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 4.3 to Form 10-K of the Registrant for the fiscal year ended December 31, 2000) Executive Compensation Plans and Arrangements (Exhibit No.'s 10.1 through 10.9): 10.1 1983 Incentive Stock Option Plan (Incorporated by reference to Exhibit 10.2 to Form S-l of the Registrant (File No. 2-92397) as filed with the Securities and Exchange Commission on July 26, 1984, as amended by Amendments No. 1 and 2 on October 5, 1984, and October 25, 1984, respectively) 10.2 1992 Stock Option Plan (Incorporated by reference to Exhibit 28.1 to Form S-8 of the Registrant (File No. 33-57348) as filed with the Securities and Exchange Commission on January 25, 1993) -88- 10.3 Stock Option Agreement between the Registrant and Thomas R. Cambridge dated December 11, 1991 (Incorporated by reference to Exhibit 10.4 of Form 10-K of the Registrant for the fiscal year ended December 31, 1992) 10.4 Stock Option Agreement between the Registrant and Thomas R. Cambridge dated October 18, 1993 (Incorporated by reference to Exhibit 10.4(e) of Form 10-K of the Registrant for the fiscal year ended December 31, 1993) 10.5 Merrill Lynch, Pierce, Fenner & Smith Incorporated Prototype Simplified Employee Pension Plan (Incorporated by reference to Exhibit 10.6 of the Registrant's Form 10-K for the fiscal year ended December 31, 1995) 10.6 Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.6 of the Registrant's Form 10-K Report for the fiscal year ended December 31, 1997) 10.7 1998 Stock Option Plan (Incorporated by reference to Exhibit 10.7 of Form 10-K of the Registrant for the fiscal year ended December 31, 1998) 10.8 Form of Incentive Award Agreements, dated December 12, 2001, between the Registrant and Thomas R. Cambridge, Larry C. Oldham, Eric A. Bayley and John S. Rutherford granting 2,394 Unit Equivalent Rights to Mr. Cambridge; 9,564 Unit Equivalent Rights to Mr. Oldham; 2,869 Unit Equivalent Rights to Mr. Bayley; and 7,173 Unit Equivalent Rights to Mr. Rutherford (Incorporated by reference to Exhibit 10.8 of Form 10-K of the Registrant for the fiscal year ended December 31, 2001) 10.9 Form of Change of Control Agreements, dated June 1, 2001, between the Registrant and Thomas R. Cambridge, Larry C. Oldham, Eric A. Bayley and John S. Rutherford (Incorporated by reference to Exhibit 10.9 of Form 10-K of the Registrant for the fiscal year ended December 31, 2001) 10.10 Restated Loan Agreement, dated December 27, 1999, between the Registrant and Bank One, Texas, N.A. (Incorporated by reference to Exhibit 10.8 of Form 10-K of the Registrant for the fiscal year ended December 31, 1999) 10.11 Loan Agreement, dated December 18, 2000, between the Registrant and Bank United (Incorporated by reference to Exhibit 10.9 of Form 10-K of the Registrant for the fiscal year ended December 31, 2000) 10.12 Letter agreement, dated March 24, 1999, between the Registrant and Bank One, Texas, N.A. (Incorporated by reference to Exhibit 10.9 of Form 10-K of the Registrant for the fiscal year ended December 31, 1998) -89- 10.13 Certificate of Formation of First Permian, L.L.C. (Incorporated by reference to Exhibit 10.1 of the Registrant's Form 8-K Report dated June 30, 1999) 10.14 Limited Liability Company Agreement of First Permian, L.L.C. (Incorporated by reference to Exhibit 10.2 of the Registrant's Form 8-K Report dated June 30, 1999) 10.15 Merger Agreement, dated June 25, 1999 (Incorporated by reference to Exhibit 10.3 of the Registrant's Form 8-K Report dated June 30, 1999) 10.16 Agreement and Plan of Merger of First Permian, L.L.C. and Nash Oil Company, L.L.C. (Incorporated by reference to Exhibit 10.4 of the Registrant's Form 8-K Report dated June 30, 1999) 10.17 Certificate of Merger of First Permian, L.L.C. and Nash Oil Company, L.L.C. (Incorporated by reference to Exhibit 10.5 of the Registrant's Form 8-K Report dated June 30, 1999) 10.18 Amended and Restated Limited Liability Company Agreement of First Permian, L.L.C. dated as of May 31, 2000 (Incorporated by reference to Exhibit 10.16 of Form 10-K of the Registrant for the fiscal year ended December 31, 2000) 10.19 Credit Agreement, dated June 30, 1999, by and among First Permian, L.L.C., Parallel Petroleum Corporation, Baytech, Inc., and Bank One, Texas, N.A. (Incorporated by reference to Exhibit 10.6 of the Registrant's Form 8-K Report dated June 30, 1999) 10.20 Limited Guaranty, dated June 30, 1999, by and among First Permian, L.L.C., parallel Petroleum Corporation and Bank One, Texas, N.A. (Incorporated by reference to Exhibit 10.7 of the Registrant's Form 8-K Report dated June 30, 1999) 10.21 Intercreditor Agreement, dated as of June 30, 1999, among First Permian, L.L.C., Bank One, Texas, N.A., Tejon Exploration Company, and Mansefeldt Investment Corporation (Incorporated by reference to Exhibit 10.8 of the Registrant's Form 8-K Report dated June 30, 1999) 10.22 Subordinated Promissory Note, dated June 30, 1999, in the original principal amount of $8.0 million made by First Permian, L.L.C. payable to the order of Tejon Exploration Company (Incorporated by reference to Exhibit 10.9 of the Registrant's Form 8-K Report dated June 30, 1999) -90- 10.23 Subordinated Promissory Note, dated June 30, 1999, in the original principal amount of $8.0 million made by First Permian, L.L.C. payable to the order of Mansefeldt Investment Corporation (Incorporated by reference to Exhibit 10.10 of the Registrant's Form 8-K Report dated June 30, 1999) 10.24 Second Restated Credit Agreement, dated October 25, 2000, among First Permian, L.L.C., Bank One, Texas, N.A., and Bank One Capital Markets, Inc. (Incorporated by reference to Exhibit 10.22 of Form 10-K of the Registrant for the fiscal year ended December 31, 2000) 10.25 Loan Agreement, dated as of January 25, 2002, between the Registrant and First American Bank, SSB (Incorporated by reference to Exhibit 10.25 of Form 10-K of the Registrant for the fiscal year ended December 31, 2001) 10.26 Purchase and Sale Agreement, dated as of November 27, 2002, among JMC Exploration, Inc., Arkoma Star L.L.C., Parallel, L.P. and Texland Petroleum, Inc. (Incorporated by reference to Exhibit 10.1 of Form 8-K of the Registrant, dated December 20, 2002) 10.27 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) 10.28 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) *14 Code of Ethics *21 Subsidiaries *23.1 Consent of KPMG LLP *23.2 Consent of BDO Seidman, LLP *23.3 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 -91- *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. --------------- * Filed herewith. -92- PARALLEL PETROLEUM CORPORATION Index to the Financial Statements Page Independent Auditors' Report - BDO Seidman, LLP F-2 Independent Auditors' Report - KPMG LLP F-3 Financial Statements: Consolidated Balance Sheets at December 31, 2003 and 2002 F-4 Consolidated Statements of Operations for the years ended December 31, 2003, 2002, and 2001 F-5 Consolidated Statements of Stockholders' Equity for the years ended December 31, 2003, 2002, and 2001 F-6 Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002, and 2001 F-7 Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2003, 2002, and 2001 F-8 Notes to Consolidated Financial Statements F-9 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 The Board of Directors and Stockholders Parallel Petroleum Corporation: We have audited the accompanying consolidated balance sheet of Parallel Petroleum Corporation and subsidiaries (the Company) as of December 31, 2003, and the related consolidated statements of operations, stockholders' equity, cash flows and comprehensive income (loss) for the year then ended. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides 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 and subsidiaries as of December 31, 2003, and the results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 4 to the financial statements, effective January 1, 2003, the Company changed its method for accounting for asset retirement obligations. As discussed in Note 1(g), to the financial statements, effective January 1, 2003 the Company changed its method of accounting for stock based employee compensation. /s/ BDO Seidman, LLP Houston, Texas March 5, 2004 F-2 The Board of Directors and Stockholders Parallel Petroleum Corporation: We have audited the accompanying consolidated balance sheet of Parallel Petroleum Corporation and subsidiaries (the Company) as of December 31, 2002, and the related consolidated statements of operations, stockholders' equity, cash flows and comprehensive income (loss) for each of the years in the two-year period ended December 31, 2002. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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. An audit also includes 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 and subsidiaries as of December 31, 2002, and the results of their operations and their cash flows for each of the years in the two-year period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. /s/ KPMG LLP Midland, Texas March 14, 2003 F-3 PARALLEL PETROLEUM CORPORATION Consolidated Balance Sheets December 31, 2003 and 2002 (dollars in thousands) Assets 2003 2002 -------------- -------------- Current assets: Cash and cash equivalents $ 17,378 $ 11,812 Accounts receivable: Oil and gas 4,610 3,071 Others, net of allowance for doubtful account of $9 and $13 316 236 Affiliate - 2 -------------- -------------- 4,926 3,309 Income tax receivable - 833 Other assets 210 79 Fair value of derivative instruments - 22 Deferred tax asset 1,098 - -------------- -------------- Total current assets 23,612 16,055 -------------- -------------- Property and equipment, at cost: Oil and gas properties, full cost method 162,621 146,680 Other 1,414 1,083 -------------- -------------- 164,035 147,763 Less accumulated depreciation and depletion (70,070) (62,075) -------------- -------------- Net property and equipment 93,965 85,688 -------------- -------------- Other assets, net of accumulated amortization of $182 and $79 766 608 -------------- -------------- $ 118,343 $ 102,351 ============== ============== Liabilities and Stockholders' Equity Current liabilities: Accounts payable and accrued liabilities $ 3,965 $ 3,034 Current maturities of long-term debt - 4,146 Derivative obligations 3,231 336 -------------- -------------- Total current liabilities 7,196 7,516 -------------- -------------- Long-term debt, excluding current maturities 39,750 45,604 Asset retirement obligation 1,701 - Derivative obligations 2,655 104 Deferred tax liability 5,809 3,628 -------------- -------------- Total long-term liabilties 49,915 49,336 -------------- -------------- Commitments and contingencies Stockholders' equity: Series A preferred stock -- par value $0.10 per share, authorized 50,000 shares - - Preferred stock -- $0.60 cumulative convertible preferred stock -- par value of $0.10 per share, (aggregate liquidation preference of $10) authorized 10,000,000 shares, issued and outstanding 959,500 and 974,500 96 97 Common stock -- par value $0.01 per share, authorized 60,000,000 shares, issued and outstanding 25,216,863 and 21,143,406 253 211 Additional paid-in capital 47,544 35,153 Retained earnings 17,060 10,038 Accumulated comprehensive loss (3,721) - -------------- -------------- Total stockholders' equity 61,232 45,499 -------------- -------------- $ 118,343 $ 102,351 ============== ============== See accompanying Notes to Consolidated Financial Statements. F-4 PARALLEL PETROLEUM CORPORATION Consolidated Statements of Operations Years ended December 31, 2003, 2002, 2001 (dollars in thousands, except per share data) 2003 2002 2001 --------------- ---------------- -------------- Oil and gas revenues $ 33,855 $ 12,106 $ 17,840 -------- -------- -------- Cost and expenses: Lease operating expense 6,458 2,081 2,737 Production taxes 1,946 796 1,184 General and administrative 4,344 2,153 1,346 Depreciation and depletion 8,390 6,220 6,318 Impairment of oil and gas properties - - 16,820 ------- -------- -------- Total costs and expenses 21,138 11,250 28,405 ------- -------- -------- Operating income (loss) 12,717 856 (10,565) ------- -------- -------- Other income (expense), net: Equity in income of First Permian, L.P. - 31,044 840 Incentive awards attributable to the sale of First Permian, L.P. - (1,382) - Loss on sale of marketable securities - (717) - Change in fair market value of derivatives (22) (948) - Gain (loss) on ineffective portion of hedges 191 - - Interest and other income 116 93 237 Dividend income - 371 - Interest expense (2,048) (601) (802) Other expense (259) (332) (529) ------- -------- -------- Total other income (expense), net (2,022) 27,528 (254) ------- -------- -------- Income (loss) before income taxes 10,695 28,384 (10,819) Income tax benefit (expense), deferred (3,031) (9,683) 6,111 ------- -------- -------- Income (loss) before cumulative effect of change in accounting principle 7,664 18,701 (4,708) Cumulative effect on prior years of a change in accounting principle, net of tax of $32 (62) - - ------- -------- -------- Net income (loss) 7,602 18,701 (4,708) ------- -------- -------- Cumulative preferred stock dividend (580) (585) (585) ------- -------- -------- Net income (loss) available to common stockholders $ 7,022 $ 18,116 $ (5,293) ======= ======== ======== Net income (loss) per common share: Basic - before cumulative effect of a change in accounting principle $ 0.33 $ 0.88 $ (0.26) Cumulative effect of a change in accounting principle, net of tax - - - ------- -------- -------- Basic - after cumulative effect of a change in accounting principle $ 0.33 $ 0.88 $ (0.26) ======= ======== ======== Diluted - before cumulative effect of a change in accounting principle $ 0.31 $ 0.79 $ (0.26) Cumulative effect of a change in accounting principle, net of tax - - - ------- -------- -------- Diluted - after cumulative effect of a change in accounting principle $ 0.31 $ 0.79 $ (0.26) ======= ======== ======== See accompanying Notes to Consolidated Financial Statements. F-5 PARALLEL PETROLEUM CORPORATION Consolidated Statements of Stockholders' Equity Years ended December 31, 2003, 2002 and 2001 (amounts in thousands) Preferred stock Common stock ------------------ ------------------ Additional Accumulated Total Number of Number of paid-in Retained Comprehensive stockholders' shares Amount shares Amount capital earnings (deficit) Loss equity --------- -------- --------- -------- ---------- ----------------- -------------- ------------- Balance, January 1, 2001 975 $ 97 20,332 $ 203 $ 34,238 $ (3,370) $ - $ 31,168 Options issued - - - - 99 - - 99 Options exercised, including income tax benefit of $123 - - 332 4 359 - - 363 Net loss - - - - - (4,708) - (4,708) Dividends on preferred stock ($0.60 per share) - - - - (585) - - (585) -------- -------- ------- -------- -------- -------- -------- -------- Balance December 31, 2001 975 97 20,664 207 34,111 (8,078) - 26,337 Common stock issued as part of asset purchase - - 454 5 995 - - 1,000 Options exercised, including income tax benefit of $16 - - 25 - 46 - - 46 Net income - - - - - 18,701 - 18,701 Dividends on preferred stock ($0.60 per share) - - - - - (585) - (585) -------- -------- -------- ------- ------- -------- ------- ------- Balance, December 31, 2002 975 97 21,143 212 35,152 10,038 - 45,499 Common stock issued - - 4,000 40 12,080 - - 12,120 Preferred stock converted (15) (1) 43 1 - - - - Warrants issued - - - - 157 - - 157 Options exercised, including income tax benefit of $19 - - 31 - 57 - - 57 Stock option expense - - - - 98 - - 98 Decrease in value of cash flow hedges - - - - - - (3,721) (3,721) Net income - - - - - 7,602 - 7,602 Dividends on preferred stock - - - - - - - - ($0.60 per share) - - - - - (580) - (580) -------- -------- -------- -------- -------- -------- -------- --------- Balance December 31, 2003 960 $ 96 25,217 $ 253 $ 47,544 $ 17,060 $ (3,721) $ 61,232 ======== ======= ======== ======== ======== ======== ======== ======== See accompanying Notes to Consolidated Financial Statements. F-6 PARALLEL PETROLEUM CORPORATION Consolidated Statements of Cash Flows Years ended December 31, 2003, 2002 and 2001 (in thousands) 2003 2002 2001 ------------ ----------- ------------ Cash flows from operating activities: Net income (loss) $ 7,602 $ 18,701 $ (4,708) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation and depletion 8,390 6,220 6,318 Accretion of asset retirement obligation 139 - - Equity in income of First Permian, L.P. - (31,044) (840) Loss on sale of marketable securities - 717 - Deferred income taxes 3,031 9,683 (6,111) Change in fair value of derivative instruments 22 508 - (Gain) loss on ineffective portion of hedges (191) 440 - Stock option expense 98 - - Loss on disposal of equipment - - (9) Impairment of oil and gas properties - - 16,820 Stock-based financial advisory services 157 - 99 Cumulative effect on prior years of a change in accounting principle, net of tax 62 - - Changes in assets and liabilities: Other, net 139 (549) 25 (Increase) decrease in receivables (783) (1,608) 2,696 Increase in prepaid expenses (132) (621) (180) Increase (decrease) in accounts payable and accrued liabilities 931 (388) (727) Purchase of derivative instruments - (531) - ----------- --------- --------- Net cash provided by operating activities 19,465 1,528 13,383 ----------- --------- --------- Cash flows from investing activities: Additions to oil and gas property (14,930) (61,240) (13,126) Proceeds from disposition of oil and gas property 64 693 1,965 Proceeds from disposition of Energen Stock - 24,863 - Additions to other property and equipment (331) (531) (211) Proceeds from disposition of other property and equipment - - 15 Distribution received from investment of First Permian, LLC - 5,938 - Investment in limited Partnership (297) - - ----------- --------- --------- Net cash used in investing activities (15,494) (30,277) (11,357) ----------- --------- --------- Cash flows from financing activities: Borrowings from bank line of credit 3,174 53,436 2,000 Payments on bank line of credit (13,174) (15,686) (2,428) Proceeds from exercise of options and warrants 55 45 337 Proceeds (net) from private placement 12,120 - - Payment of preferred stock dividend (580) (585) (585) ----------- --------- --------- Cash provided by (used in) financing activities 1,595 37,210 (676) ----------- --------- --------- Net increase in cash and cash equivalents 5,566 8,461 1,350 Cash and cash equivalents at beginning of year 11,812 3,351 2,001 ----------- --------- --------- Cash and cash equivalents at end of year $ 17,378 $ 11,812 $ 3,351 =========== ========= ========= Non-cash financing and investing activities: Oil and gas properties asset retirement obligation $ 1,075 $ - $ - (Non-cash) proceeds from sale of investment of First Permian, L.P. $ - $ (25,580) $ - Accrued preferred stock dividend $ - $ 24 $ 24 Issuance of stock for purchase of oil and gas property $ - $ 1,000 $ - See accompanying Notes to Consolidated Financial Statements. F-7 PARALLEL PETROLEUM CORPORATION Consolidated Statements of Comprehensive Income (Loss) Years ended December 31, 2003, 2002 and 2001 (dollars in thousands) 2003 2002 2001 ------------ ------------- ------------ Net income (loss) $ 7,602 $ 18,701 $ (4,708) Other comprehensive loss: Unrealized losses on derivatives (8,336) - - Reclassification adjustment for losses on derivatives included in net income 2,699 - - -------- -------- -------- Change in fair value of derivatives (5,637) - - Income tax benefit 1,916 - - -------- -------- -------- Total other comprehensive loss (3,721) - - -------- -------- -------- Total comprehensive incomes (loss) $ 3,881 $ 18,701 $ (4,708) ======== ======== ======== See accompanying notes to Consolidated Financial Statements F-8 PARALLEL PETROLEUM CORPORATION Notes to Consolidated Financial Statements December 31, 2003, 2002 and 2001 (1) Organization, Business and Summary of Significant Accounting Policies (a) Nature of Operations Parallel Petroleum Corporation (the Company), a Delaware corporation, is primarily engaged in the acquisition of, and the exploration for, development, production and sale of, crude oil and natural gas. The Company's business activities are carried out primarily in Texas. The Company's activities are focused in the onshore Gulf Coast area of south Texas, East Texas and in the Permian Basin of West Texas and New Mexico. (b) Basis of Consolidation The Company's financial statements present the consolidated results of Parallel Petroleum Corporation, and its wholly owned subsidiaries, Parallel L.P. and Parallel, L.L.C. All significant inter-company account balances and transactions have been eliminated. (c) Concentration of Credit Risk and Geographic Area Financial instruments that potentially expose the Company to concentrations of credit risk consist primarily of unsecured accounts receivable from unaffiliated working interest owners and crude oil and natural gas purchasers. A substantial portion of our oil and natural gas reserves are located in the Permian Basin and we 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, significant governmental regulation, including any curtailment of production or interruption of transportation of oil or gas produced from the wells. (d) Property and Equipment Oil and gas properties: The Company uses the full cost method of accounting for its oil and gas producing activities. Accordingly, all costs associated with acquisition, exploration, and development of oil and gas reserves, including directly related overhead costs, are capitalized. Management and service fees received for contractual arrangements, if any, are treated as reimbursement of costs, offsetting the costs incurred to provide those services. Depletion is provided using the unit-of-production method based upon estimates of proved oil and gas reserves with oil and 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. If the net investment in oil and gas properties in a cost center, as adjusted for asset retirement obligations, exceeds an amount equal to the sum of (1) the standardized measure of discounted future net cash flows from proved reserves (see Note 15) 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. The standardized measure is calculated using a 10% discount rate and is based F-9 on unescalated prices in effect at year-end with effect given to the Company's cash flow hedge positions. For 2001, the Company recognized an impairment of approximately $16.8 million. There was no impairment recorded for 2003 and 2002. 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 gas reserves, in which case the gain or loss is recognized in income. Abandonments of properties are accounted for as adjustments of capitalized costs subject to amortization. Other: 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 gas properties, the cost and related accumulated depreciation are removed from the accounts with the resulting gains or losses, if any, recognized in income. Depreciation of other property and equipment is computed using the straight-line method based on the estimated useful lives of the property and equipment. (d) Income Taxes The Company accounts for federal 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. (e) Investments Investments in affiliated companies with a 20% to 50% ownership interest are accounted for on the equity basis and, accordingly, net income includes the Company's share of their income or loss. (f) Gas Balancing Deferred income associated with gas balancing is accounted for on the entitlements method and represents amounts received for gas sold under gas balancing arrangements in excess of the Company's interest in properties covered by such agreements. The Company currently has no significant amounts outstanding under gas balancing arrangements. (g) Stock-Based Compensation Prior to 2003, Parallel accounted for stock-based compensation utilizing the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25 "Accounting for Stock Issued to Employees" ("APB 25") and related interpretations. In September, 2003, Parallel adopted the provisions of Statement of Financial Accounting Standards No. 148, Accounting for Stock-Based F-10 Compensation - Transition and Disclosure, an amendment to SFAS No. 123, whereby certain transitional alternatives are available for a voluntary change to the fair value based method of accounting for stock-based employee compensation. Parallel uses the prospective method which applies prospectively the fair value recognition method to all employee and director awards granted, modified or settled after the beginning of the fiscal year in which the fair value based method of accounting for stock-based compensation is adopted. The potential impact of using the fair value method, on a pro forma basis, is presented in the table that follows. As Parallel adopted the fair value recognition provisions of SFAS No. 123 prospectively for all employee awards granted, modified or settled after January 1, 2003, the charge for stock-based compensation included in the determination of income in 2003 and 2002 is less than that which would have been recognized if the fair value method had been applied to all awards since the original effective date of SFAS No. 123. In 2003, Parallel recognized compensation expense of $98,000 associated with its stock option grants. The total number of options granted during 2003 was 180,000. The following table illustrates the effect on net income and earnings per share as if the fair value based method had been applied to all outstanding and unvested awards in each period. The fair value of each grant is estimated on the date of grant using the Black-Scholes option-pricing model. Year Ended December 31, ------------------------------------------------- 2003 2002 2001 ---------------- ---------------- ---------------- (in thousands, except per share data) Net income (loss) as reported $ 7,602 $ 18,701 $ (4,708) Add: Expense recorded in 2003 98 - - Deduct: Total stock-based employee compensation expense determined under fair value method for all awards, net of related tax effects (587) (757) (239) ------- ------- -------- Pro forma net income (loss) $ 7,113 $ 17,944 $ (4,947) ======= ======== ======== Earnings per share: Basic -- as reported $ 0.33 $ 0.88 $ (0.26) ======= ======== ======== Basic -- pro forma $ 0.33 $ 0.87 $ (0.26) ======= ======== ======== Diluted -- as reported $ 0.31 $ 0.79 $ (0.26) ======= ======== ======== Diluted -- pro forma $ 0.29 $ 0.74 $ (0.26) ======= ======== ======== (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 F-11 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 (loss) Per Share Basic earnings (loss) per share excludes any dilutive effects of option, warrants and convertible securities and is computed by dividing income (loss) available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted earnings (loss) per share are computed similar to basic earnings per share, however diluted earnings per share reflects the assumed conversion of all potentially dilutive securities. The following table provides the computation of basic and diluted earnings (loss) per share for the year ended December 31: 2003 2002 2001 ------------- ------------- -------------- (in thousands except per share data) Basic EPS Computation: Numerator- Net income (loss) before cumulative effect of a change in accounting principle $ 7,664 $ 18,701 $ (4,708) Cumulative effect of a change in accounting principle, net of tax (62) - - -------- -------- -------- 7,602 18,701 (4,708) Preferred stock dividend (580) (585) (585) -------- --------- --------- Net income (loss) available to common stockholders $ 7,022 $ 18,116 $ (5,293) ======== ========= ========= Denominator- Weighted average common shares outstanding 21,264 20,680 20,458 ======== ========= ========= Basic EPS: Net income before cumulative effect of a change in accounting principle $ 0.33 $ 0.88 $ (0.26) Cumulative effect of a change in accounting principle, net of tax - - - -------- --------- --------- Basic net earnings (loss) per share $ 0.33 $ 0.88 $ (0.26) ======== ========= ========= Diluted EPS Computation: Numerator- Net income (loss) before cumulative effect of a change in accounting principle $ 7,664 $ 18,701 $ (4,708) Cumulative effect of a change in accounting principle, net of tax (62) - - -------- --------- --------- 7,602 18,701 (4,708) Preferred stock dividend - - (585) -------- --------- --------- Net income (loss) available to common stockholders $ 7,602 $ 18,701 $ (5,293) ======== ========= ========= Denominator - Weighted average common shares outstanding 21,264 20,680 20,458 Employee stock options 150 85 - Warrants 20 - - Preferred stock 2,741 2,784 - -------- --------- --------- Weighted average common shares for diluted earnings per share assuming conversion 24,175 23,549 20,458 ======== ========= ========= Diluted EPS: Net income (loss) before cumulative effect of a change in accounting principle $ 0.31 $ 0.79 $ (0.26) Cumulative effect of a change in accounting principle, net of tax - - - -------- --------- --------- Diluted net earnings (loss) per share $ 0.31 $ 0.79 $ (0.26) ======== ========= ========= F-12 Some stock options and the convertible preferred stock outstanding during 2003, 2002 and 2001 were not included in the computation of diluted net earnings (loss) per share because either (i) the stock options' exercise price was greater than the average market price of common stock of the Company, (ii) the effect of the assumed conversion of the Company's preferred stock to common stock would be antidilutive, or (iii) the Company had a net loss from continuing operations and, therefore, the effect would be antidilutive. (j) Use of Estimates in the Preparation of Financial Statements Preparation of the accompanying 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 financial statements and the reported amounts of revenues and expenses during the reporting period. The oil and 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. (l) Reclassifications Certain reclassifications have been made to 2002 amounts to conform to the 2003 presentation. (m) Derivative Financial Instruments Derivative financial instruments, utilized to manage or reduce commodity price risk related to the Company's production and interest rate risk related to the Company's long-term debt, are accounted for under the provisions of SFAS No. 133, "Accounting for Derivative Instruments and for Hedging Activities", and related interpretations. Under this statement, all 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. If the derivative is not designated as a hedge, changes in the fair value are recognized in other expense. Ineffective portions of changes in the fair value of cash flow hedges are recognized in other expense. (n) 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 gas sold to purchasers. F-13 The following summarizes our revenue for each of the three years ended December 31 by product sold. 2003 2002 2001 ------------ ------------ ------------ (in thousands) Oil revenue $ 18,300 $ 3,217 $ 3,429 Oil hedge (1,659) - - Gas revenue 18,121 8,889 14,411 Gas hedge (907) - - -------- ------- -------- $ 33,855 $ 12,106 $ 17,840 ======== ======== ======== (o) Recent Accounting Pronouncements FIN No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Other. FIN No. 45 requires that a liability be recorded in the guarantor's balance sheet upon issuance of certain guarantees. Initial recognition and measurement of the liability will be applied on a prospective basis to guarantees issued or modified after December 31, 2002. FIN No. 45 also requires disclosures about guarantees in financial statements for interim or annual periods ending after December 15, 2002. The adoption had no impact on the Company's consolidated financial statements. FIN No. 46, Consolidation of Variable Interest Entities. In December 2003, the FASB issued Interpretation No. 46R, which requires the consolidation of certain entities that are determined to be variable interest entities ("VIE"). An entity is considered to be a VIE when either (i) the entity lacks sufficient equity to carry on its principal operations, (ii) the equity owners of the entity cannot make decisions about the entity's activities or (iii) the entity's equity neither absorbs losses or benefits from gains. The Company owns no interests in variable interest entities, and therefore this new interpretation has not affected the Company's consolidated financial statements. In April, 2003, the Financial Accounting Standards Board issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, which clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. The Statement is effective for contracts entered into or modified after June 20, 2003. The adoption of SFAS 149 did not have a material impact on the Company's consolidated financial statements. In May, 2003, the Financial Accounting Standards Board issued SFAS No. 150 "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. This statement was effective for financial instruments entered into or modified after May 31, 2003, and otherwise was effective at the beginning of the first F-14 interim period beginning after June 15, 2003. The adoption of SFAS 150 did not have a material impact on the Company's consolidated financial statements. A reporting issue has arisen regarding the application of certain provisions of SFAS No. 141 and SFAS No. 142 to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS No. 142 requires registrants to classify the costs of mineral rights held under lease or other contractual arrangements associated with extracting oil and gas as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. Historically, Parallel has included the costs of such mineral rights associated with extracting oil and gas as a component of oil and gas properties. If it is ultimately determined that SFAS No. 142 requires oil and gas companies to classify costs of mineral rights held under lease or other contractual arrangement associated with extracting oil and gas as a separate intangible assets line item on the balance sheet, the Company would be required to reclassify approximately $17.3 million at December 31, 2003 and $13.5 million at December 31, 2002 out of Oil and Gas Properties and into a separate intangible assets line item. Parallel's cash flows and results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with full cost accounting rules. (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 approximates fair value because the Company's current borrowing rate is based on a variable market rate of interest. (3) Oil and Gas Properties The following table reflects capitalized costs related to the oil and gas properties as of December 31: 2003 2002 ------------------ ------------------- (in thousands) Proved properties $ 160,287 $ 144,787 Unproved properties, not subject to depletion 2,334 1,893 ---------- --------- 162,621 146,680 Accumulated depletion (69,726) (61,614) ---------- --------- $ 92,895 $ 85,066 ========= ========= Certain directly identifiable internal costs of property acquisition, exploration, and development activities are capitalized. Such costs capitalized in 2003, 2002 and 2001 totaled $915,000, $1.3 million and $782,000, respectively. Depletion per equivalent unit of production (BOE) was $6.83, $10.52 and $9.13 for 2003, 2002, and 2001, respectively. F-15 The following table reflects costs incurred in oil and gas property acquisition, exploration, and development activities for each of the years in the three year period ended December 31: 2003 2002 2001 -------------- --------------- -------------- (in thousands) Proved property acquisition costs $ 2,209 $ 48,044 $ 27 Unproved property acquisitions costs 3,831 2,295 3,420 Exploration 3,240 1,291 6,821 Development 5,650 9,308 1,203 ------- -------- -------- $14,930 $ 60,938 $ 11,471 ======= ======== ======== On December 20, 2002, we purchased, through our subsidiary, Parallel, L.P., a majority non-operated interest in producing oil and gas properties located in the Fullerton Field of Andrews County, Texas in the Permian Basin of west Texas. The total purchase price for our interest in the Fullerton properties was $46.0 million. (4) Asset Retirement Obligation On January 1, 2003 the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations "SFAS 143". 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 gas properties. The adoption of this statement required the Company to record a non-cash expense, net of tax, of approximately $62,000 as a cumulative effect of change in accounting principle in the first quarter of 2003, as well as a non-current liability of approximately $1.7 million and an addition to oil and gas properties of approximately $1.5 million. The following table summarizes the Company's asset retirement obligation transactions as if SFAS No. 143 had been applied during all periods presented. 2003 2002 2001 ----------------- ------------- ------------ (in thousands) Pro Forma -------------------------- Beginning asset retirement obligation $ 1,469 $ 897 $ 793 Additions related to new properties 345 498 39 Deletions related to property disposals (252) - - Accretion expense 139 74 65 ------- ------- ------- Ending asset retirement obligation $ 1,701 $ 1,469 $ 897 ======= ======= ======= Applying the provisions of SFAS No. 143 reduced 2003 income before cumulative effect of changes in accounting principle by $139,000 ($92,000, or $0.00 per share, net of income taxes). F-16 The table below reflects, on a pro forma basis, the net income (loss) and net income (loss) per share amounts as if the provisions of SFAS No. 143 had been applied during all the periods presented. Year 2003 is presented to show the effect on net income had the provisions of SFAS No. 143 been adopted at the beginning of 2001. 2003 2002 2001 --------------- ---------------- --------------- (dollars in thousands except per share data) Net income (loss), as reported $ 7,602 $ 18,701 $ (4,708) Accretion of asset retirement obligation, net of tax - (39) (13) Cumulative effect of change in accounting principle, net of tax 62 - - -------- -------- -------- Pro forma net income (loss) $ 7,664 $ 18,662 $ (4,721) ======== ========= ========= Basic net income (loss) per share, as reported $ 0.33 $ 0.88 $ (0.26) ======== ========= ========= Basic net income (loss) per share, pro forma $ 0.34 $ 0.88 $ (0.26) ======== ========= ========= Diluted net income (loss) per share, as reported $ 0.31 $ 0.79 $ (0.26) ======== ========= ========= Diluted net income (loss) per share, pro forma $ 0.32 $ 0.79 $ (0.26) ======== ========= ========= (5) Derivative Instruments In 2002, the Company began entering into derivative contracts to provide a measure of stability in the Company's oil and gas revenues and interest rate payments and to manage exposure to commodity price and interest rate risk. The Company's objective is to lock in a range of oil and gas prices and a fixed interest rate for certain notional amounts. For the year ended December 31, 2002, the Company did not designate derivative contracts as hedges. Accordingly, unrealized gains or losses on these contracts were recorded through income. As of January 1, 2003 the Company designated its interest rate swaps, costless collars and the commodity swaps as cash flow hedges (see below). The effective portion of the unrealized gain or loss on cash flow hedges is recorded in other comprehensive income until the forecasted transaction occurs. The Company continued to record the unrealized gains or losses on put contracts to income. During the terms of a cash flow hedge, the effective portion of the quarterly change in the fair value of the derivatives is recorded in stockholders' equity as other comprehensive income (loss) and then transferred to oil and gas revenues when the production is sold and interest expense when the interest payment is made. Ineffective portions of hedges (changes in realized prices that do not match the changes in the hedge price) are recognized in other expense as they occur. While the hedge contract is open, the ineffective gain or loss may increase or decrease until settlement of the contract. As of December 31, 2003, the Company had recorded unrealized losses of $5.9 ($3.7 million, net of tax) related to its derivative instruments, which represented the estimated aggregate fair values of the Company's open derivative contracts as of that date. These unrealized losses are presented on the Consolidated Balance Sheet as a current liability of $3.2 million and long-term liabilities of $2.7 million. During the twelve month period ending December 31, 2004 the Company expects approximately $2.1 million, net of tax, to be transferred out of other comprehensive income (loss) and charged to earnings. F-17- The Company is exposed to credit risk in the event of nonperformance by BNP Paribas in its derivative instruments. However, the Company periodically assesses its credit worthiness to mitigate this credit risk. Interest Rate Sensitivity Swaps. In January, 2003, the Company entered into a 45-month libor fixed interest rate swap contract with BNP Paribas. The Company will receive a fixed interest rate, as noted in the table below, for the 45-month period beginning March 31, 2003 through December 20, 2006. Prior to January 2003, the Company did not hedge its interest rate risk. In 2002, the decrease in fair value of the swaps of $440,000 was recognized in the Consolidated Statements of Operations. Under the Company's revolving credit facility, the Company may elect an interest rate based upon the agent lender's base lending rate, or the libor rate, plus a margin ranging from 2.25% to 2.75% per annum, depending on the Company's borrowing base usage. The interest rate the Company is required to pay, including the applicable margin, may never be less than 4.50%. A recap for the period of time, notional amounts, libor fixed interest rates, expected margin rates and expected fixed interest rates for the contract are as follows: Libor Expected Expected Period of Time Notional Amounts(1) Fixed Interest Rates(2) Margin Rates(3) Fixed Interest Rates(4) ------------------------------- ----------------------- ------------------------ ------------------ ------------------------ Dec 31, 2003 thru Dec 31, 2004 $ 30,000,000 2.660% 2.500% 5.160% Dec 31, 2004 thru Dec 31, 2005 $ 20,000,000 4.050% 2.250% 6.300% Dec 31, 2005 thru Dec 20, 2006 $ 10,000,000 4.050% 2.250% 6.300% --------------------- (1) Based on the anticipated principal reductions under the Company's credit facility. (2) The Company's swap contract with BNP Paribas. (3) Based on the anticipated borrowing base usage under the Company's credit facility. (4) Total of the libor fixed interest rate plus the expected margin rate under the Company's credit facility. The Company's credit agreement requires the interest rate to not be below 4.50%. Commodity Price Sensitivity Puts. On May 24, 2002 the Company purchased put floors on volumes of 100,000 Mcf per month for a total of 700,000 Mcf during the seven month period from April, 2003 through October, 2003 at a floor price of $3.00 per Mcf for a total consideration of approximately $139,500. These derivatives were not held for trading purposes. A decrease in fair value of the put floors of $22,000 and $508,000 was recognized in the Consolidated Statements of Operations for the years ended 2003 and 2002, respectively. Costless Collars. Collars are created by purchasing puts to establish a floor price and then selling a call which establishes a maximum amount the producer will receive for the oil or gas hedged. Calls are sold to offset the premium paid for buying the put. In 2003, the Company entered into several costless, seven-month Houston ship channel gas collars. A majority of the Company's natural gas production is sold based F-18 on Houston ship channel prices. A recap for the period of time, number of MMBtu's and average gas prices is as follows: Houston Ship Channel gas prices MMBtu of --------------------------------- Period of Time Natural Gas Floor Cap --------------------------------------------- ------------- ------------ ------------------- January 1, 2004 thru March 31, 2004 273,000 $ 5.43 $ 6.58 April 1 2004 thru October 31, 2004 214,000 $ 4.40 $ 5.50 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 price into a fixed price. For any particular swap transaction, the counterparty is required to make a payment to the hedge party if the reference price for any settlement period is less than the swap price for such hedge, and the hedge party is required to make a payment to the counterparty if the reference price for any settlement period is greater than the swap price for such hedge. In 2003, the Company entered into additional oil and gas swap contracts with BNP Paribas. A recap for the period of time, number of MMBtu's, number of barrels, and swap prices are as follows: Barrels Houston Ship of Nymex Oil MMBtu of Channel Period of Time Oil Swap Price Natural Gas Gas Swap Price -------------------------------------------------- ------------- -------------- --------------- ------------------- January 1, 2004 thru December 31, 2004 439,200 $ 24.45 - $ - April 1, 2004 thru December 31, 2004 - $ - 764,000 $ 4.692 January 1, 2005 thru December 31, 2005 365,000 $ 23.35 - $ - January 1, 2005 thru March 31, 2005 - $ - 180,000 $ 4.705 January 1, 2006 thru December 20, 2006 265,500 $ 23.04 - $ - (6) Equity Investment and Business Acquisition During 2003, the Company invested $290,000 in a partnership to construct a pipeline on its leaseholds in the Barnett Shale area, which is recorded in other long term assets in the accompanying consolidated balance sheet. The total commitment of the Company is approximately $350,000, resulting in a 28% interest in the partnership, which mirrors the Company's working interest in the leaseholds in the area. The Company intends to develop those leaseholds and utilize the pipeline to transport the resulting production to market. The partnership is currently acquiring the necessary easements and permits for the pipeline. Upon successful completion of the acquisition of the easements, construction of the pipeline and development of the leasehold will commence. The partnership had no operations in 2003. F-19 On March 7, 2002, First Permian entered into an Agreement of Sale and Purchase with Energen Resources Corporation, a wholly owned subsidiary of Energen Corporation (Energen), to sell all of First Permian's oil and gas properties for a gross consideration of $120.0 million in cash and 3.0 million shares in Energen stock approximating $70.0 million in value. Energen is a publicly traded company listed on the NYSE. The transaction closed on April 8, 2002. As a 30.675% interest owner in First Permian, the Company received its prorata share of the net proceeds, $5.5 million in cash and 933,589 shares of Energen common stock. All shares of Energen stock were sold prior to December 31, 2002 for $24.9 million; resulting in the total proceeds from the sale of First Permian in the amount of $30.4 million. On December 20, 2002 the Company purchased through the Company's subsidiary, Parallel, L.P., a majority of non-operated interest in producing oil and gas properties located in the Fullerton Field of Andrews County, Texas in the Permian Basin of west Texas. The total purchase price for the Company's interest in the Fullerton properties was $46.0 million. The following table presents unaudited pro forma operating results as if the purchase was effective on January 1, 2002. Pro forma ---------------------------------------------- 2002 2001 ---------------------- ---------------------- (in thousands, except per share data) Revenues $ 22,236 $ 27,474 Operating income $ 7,292 $ (4,552) Net income available to common stockholders $ 22,364 $ (1,325) Net income per common share: Basic $ 1.09 $ (0.06) Diluted $ 0.97 $ (0.06) The pro forma results have been prepared for comparative purposes only. The pro forma results do not purport to present actual results that would have been achieved or to be indicative of future results. (7) Long-Term Debt Long-term debt consists of the following at December 31: 2003 2002 --------------- ----------------- (in thousands) Revolving Facility note payable to banks, at the agent bank's base lending rate (4.5% at December 31, 2003) $ 39,750 $ 49,750 Less: current maturities - 4,146 --------------- ----------------- $ 39,750 $ 45,604 =============== ================= On July 19, 2002, the Company entered into a loan agreement ("the Facility") to refinance its outstanding indebtedness. Under the facility, the Company may borrow the lesser of $100.0 million or the "borrowing base" then in effect. The borrowing base calculation is based upon the estimated value of the Company's oil and gas reserves. The credit agreement was amended in September, 2003. The amendment included the F-20 deletion of the monthly commitment reduction, a provision that would have had the Company begin amortizing its loan beginning August 31, 2003; the modification of certain financial ratio tests; changes in certain reporting requirements to the banks; and the revision of covenants in the credit agreement governing the Company's hedging activities. The borrowing base at December 31, 2003 was $50.0 million. All borrowings are collateralized by the Company's oil and gas reserves. The total outstanding principal amount of the Company's bank indebtedness at December 31, 2003 and 2002 was $39.8 million and $49.8 million, respectively, excluding $250,000 for Letters of Credit. The borrowing base is subject to redetermination semi-annually, on or about April 1 and October 1 or at times required by the banks or at the Company's request. All indebtedness matures December 20, 2006. Unpaid principal balances under the Facility bear interest at the election of the Company at a rate equal to (i) the bank's base lending rate, or (ii) the libor rate plus a libor margin of 2.25% to 2.75%. However, the interest rate may never be less than 4.50%. Interest is due and payable on the day which the related libor interest period ends. The Company is required to pay a commitment fee of .25% times the daily average of the unadvanced amount of the commitment. The loan agreement includes various restrictive covenants and compliance requirements. Among these covenants and restrictions are: . dispose of assets; . incur additional indebtedness; . restrictions on all the retained earnings and net income for payment of dividends on the Company's common stock; . create liens on our assets; . enter into specified investments or acquisitions; . repurchase, redeem or retire our capital stock or other securities; . merge or consolidate, or transfer all or substantially all of our assets and the assets of our subsidiaries; . engage in specified transactions with subsidiaries and affiliates; or . engage in other specified corporate activities. As of December 31, 2003 the Company was in compliance with all covenants. F-21 (8) Income Taxes The Company's income tax provision is attributable to the following items: Years ended December 31, --------------------------------------- 2003 2002 2001 ------------ ------------- ------------ (dollars in thousands) Income before cumulative effect of change in accounting principle $ 3,031 $ 9,683 $ (6,111) Cumulative effect of change in accounting principle (32) - - Losses on derivatives recognized in other comprehensive income (1,916) - - ------- ------- -------- Total income tax provision $ 1,083 $ 9,683 $ (6,111) ======= ======= ======== Federal income tax expense (benefit) applicable to income before cumulative effect of change in accounting principle differs from the amount computed at the Federal statutory rate as follows: Year ended December 31, --------------------------------------------- 2003 2002 2001 -------------- --------------- -------------- (in thousands) Income tax expense (benefit) at statutory rate $ 3,700 $ 9,651 $ (3,678) Change in valuation allowance for deferred tax assets - - (2,063) Statutory depletion (96) (360) (389) State tax, net of federal benefit(1) (594) 370 - Nondeductible expenses and other 21 22 19 ------- ------- -------- Income tax expense (benefit) $ 3,031 $ 9,683 $ (6,111) ======= ======= ======== --------------- (1) The state tax benefit resulted from the Company reducing its estimate of State income tax liability. F-22 The tax effect of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31 are as follows: 2003 2002 -------- --------- (in thousands) Current: Deferred tax assets: Losses on derivatives recognized in other comprehensive income $ 1,098 $ - ======== ======= Noncurrent: Deferred tax assets: Net operating loss carryforwards, state and federal $ 3,104 $ 4,264 Statutory depletion carryforwards 1,724 1,418 Alternative minimum tax credit carryforward 118 118 Equity investment in First Permian, LLC 16 59 Allowance for accounts receivable - 5 Losses on derivatives recognized in other comprehensive income 818 - Other 169 163 -------- ------- Total noncurrent deferred tax assets 5,949 6,027 -------- ------- Deferred tax liabilities: Property and equipment, principally due to differences in basis, expensing of intangible drilling costs for tax purposes and depletion (11,758) (9,655) -------- ------- Total deferred tax liabilities (11,758) (9,655) -------- ------- Net noncurrent deferred income tax liability $ (5,809) $ (3,628) ======== ======== As of December 31, 2003, the Company had net operating loss carryforwards for regular tax and alternative minimum taxable income (AMT) purposes available to reduce future taxable income. These carryforwards expire as follows: Net operating AMT loss operating loss ----------------- ----------------- (in thousands) 2019 $ 4,510 $ 4,869 2021 4,576 4,498 2022 44 44 ------- ------- $ 9,130 $ 9,411 ======= ======= As of December 31, 2003, the Company had approximately $118,000 of alternative minimum tax (credit carryover that does not expire. F-23 (9) Equity Transactions Preferred Stock As of December 31, 2003 the Company had outstanding 959,500 shares of 6% Convertible Preferred Stock, $0.10 par value per share. Cumulative annual dividends of $0.60 per share are payable semi-annually on June 15 and December 15 of each year. Each share of Convertible Preferred Stock may be converted, at the option of the holder, into 2.8571 shares of common stock at an initial conversion price of $3.50 per share, subject to adjustment in certain events. The Convertible Preferred Stock has a liquidation preference of $10 per share and has no voting rights, except as required by law. The Company may redeem the preferred stock, in whole or part, for $10 per share plus accrued and unpaid dividends. On October 5, 2000, the Company authorized 50,000 shares of $0.10 par Series A Preferred Stock. These shares will be issued upon the exercise of the Company's Preferred Stock Purchase Rights. Subject to the rights of the holders of any series of preferred stock ranking prior and superior to the Series A preferred stock with respect to dividends, the holders of shares of the Series A Preferred Stock shall be entitled to receive, when, and if declared by the board of directors, quarterly dividends payable in cash on the first day of July, October, January and April, in each year, commencing on the first quarterly dividend payment Date after the first issuance of a fraction of a share of Series A Preferred Stock. Each share of Series A Preferred Stock shall entitle the holder to one one-thousandth of a vote on all matters submitted to a vote of the stockholders of the Company. Sale of Equity Securities On December 23, 2003, the Company privately placed a total of 4.0 million shares of common stock, $.01 par value per share, at a price of $3.25 per share. Gross cash proceeds from the placement were $13.0 million, and net proceeds were $12.1 million. The shares were subsequently registered for resale under the Securities Act of 1933, as amended. (10) Stock Options, Warrants and Rights At the election of the board of directors, the Company awards both incentive stock options and nonqualified stock options to selected key employees and officers. The options are awarded at an exercise price equal to the closing price of the Company's 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, 2003, options expire beginning in the current year and extending through 2013. Options to purchase a total of 192,500 shares of common stock remain available for grant. Under FAS 123, the fair value of each stock option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for grants in 2003 and 2002. 2003 2002 2001 ------------ ------------ ------------ Risk-free interest rate 3.7% 2.5% 4.49% Expected life 8 years 8 years 8 years Expected volatility 45.3% 45.2% 56.0% F-24 A summary of the Company's employee stock options as of December 31, 2003, 2002 and 2001, and changes during the years ended on those dates is presented below: Year ended Year ended Year ended December 31, 2003 December 31, 2002 December 31, 2001 --------------------------- -------------------------- --------------------------- Number of Weighted Number of Weighted Number of Weighted shares average price shares average price shares average price ------------ ------------- ------------ ------------- ------------ ------------- Stock options: Outstanding at beginning of year 2,338,750 $ 2.71 2,103,750 $ 3.74 1,951,750 $ 3.13 Options granted 180,000 2.96 345,000 2.54 700,000 4.87 Options exercised (30,600) (1.82) (25,000) (1.82) (325,500) (1.03) Options cancelled (100,000) (4.97) Options expired (250,000) (3.94) (85,000) (1.75) (222,500) 3.80 ------------ ---------- ---------- Outstanding at end of year 2,138,150 $ 3.65 2,338,750 $ 2.71 2,103,750 $ 3.74 ============ =========== ========== ========== ========== ========== Exercisable at end of year 1,785,650 $ 3.85 1,656,250 $ 2.82 1,451,250 $ 3.54 ============ =========== ========== ========== ========== ========== Weighted average fair value of options granted during the year $ 1.64 $ 1.66 $ 3.18 The following table summarizes information about the Company's employee stock options outstanding at December 31, 2003: Options outstanding Options exercisable ---------------------------------------------- ----------------------------- Number Weighted Number Outstanding at average Weighted exercisable at Weighted Range of December 31, remaining average December 31, average exercise prices 2003 contractual life exercise price 2003 exercise price ---------------- --------------- ----------------- -------------- -------------- -------------- $1.81 - $3.94 1,149,400 8 years $ 2.69 796,900 $ 2.66 $4.09 - $5.50 988,750 6 years $ 4.81 988,750 $ 4.81 --------------- -------------- 2,138,150 1,785,650 =============== ============== (a) Stock Warrants The Company has outstanding at December 31, 2003 and 2002, 300,000 warrants which were issued as part of the Company's 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 and in the event of liquidation, dissolution, or winding up of the Company, the holders are not entitled to participate in the assets of the Company. The Company also has outstanding at December 31, 2003 and 2002; an additional 275,000 warrants issued as partial payment for services rendered for financial and investment advice in 2001. The warrants have an exercise price equal to the average of the last bid and asked price of the Company's common stock on the F-25 effective date of the issuance of the warrants and have a term of five years from date of issuance and a vesting period of one year. The exercise price for the warrants is $2.95. The expense related to these warrants in the amount of $99,000 was recorded in other expenses in 2001 and is based on the estimated fair value on the date of grant using the Black-Scholes option pricing model. The Company has outstanding at December 31, 2003, 100,000 warrants which were issued as partial payment for services rendered for financial and investment advice for the Company's private placement offering in December, 2003. The warrants have an exercise price equal to the average of the last bid and last asked price of the Company's common stock on the effective date of the issuance of the warrants and have a term of five years from date of issuance and a vesting period of one year. The exercise price for the warrants is $3.98. The fair value related to these warrants in the amount of $157,000 was recorded in other expenses in 2003 and is based on the estimated fair value on the date of grant using the Black-Scholes option pricing model. (b) Stock Rights On October 5, 2000, the board of directors declared a dividend of one Right for each outstanding share of the Company's common stock. If a public announcement that a person has acquired 15% or more of the Company's common stock or a tender offer or exchange offer is made for 15% or more of the common stock, each 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 Rights attach to all common stock certificates representing shares then outstanding, and no separate rights certificates will be distributed. The 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 Rights separate is referred to as the "distribution date". Under certain circumstances the rights entitle the holders to buy the Company's stock at a 50% discount. In the event that (1) the Company is the surviving corporation in a merger or other business combination with an entity that owns 15% or more of the Company's outstanding stock; (2) any person shall acquire beneficial ownership of 15% of the Company's outstanding stock; or (3) there is any type of recapitalization of the Company that results in an increase by more than 1% the proportionate share of equity securities of the Company owned by a person who owns 15% or more of the Company's outstanding stock, each right holder will have the option to buy for the purchase price common stock of the Company having a value equal to two times the purchase price of the right. Under certain circumstances the rights entitle the holders to buy shares of the acquirer's common stock at a 50% discount. In the event that, at any time after a person has acquired 15% or more of the Company's 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 right. F-26 The 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 right. (11) Related Party Transactions An entity in which Thomas R. Cambridge, the Chairman of the Board, is the owner acted as the Company's agent in performing the routine day to day operations on 2 wells. In 2003, 2002 and 2001 the Company was billed approximately $51,000, $85,000 and $115,000 respectively, for the Company's pro rata share of lease operating and drilling expenses and received $198,000, $187,000 and $319,000 in 2003, 2002, and 2001 respectively, in oil and gas revenues related to these wells. These 2 wells were acquired in 1984. Dewayne E. Chitwood, a Director of the Company, also serves as director of an entity which owns 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, owns a total of 55,000 shares each of preferred stock of the Company. All of the 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. 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 2003, 2002 and 2001 the Company charged approximately $23,000 and $34,000 and $264,000 respectively, for lease operating expenses and paid $74,000, $69,000 and $176,000 respectively, in oil and gas revenues related to these wells. In 2001, Martin B. Oring, a Director of the Company, acquired an interest in a portion of the warrants awarded to the Company's investment advisor (see note 10(a)) whereby the director acted as a consultant for the investment advisor. The fair value of the warrants was estimated on the date of grant to be $33,000 using the Black-Scholes Option Pricing model. (12) Statements of Cash Flows No Federal income taxes were paid in 2003, 2002 and 2001. The Company made interest payments of approximately $2.0 million, $601,000 and $802,000 in 2003, 2002 and 2001, respectively. At December 31, 2003 and 2002, there were $600,000 and $301,000, respectively, of property additions accrued in accounts payable. F-27 (13) Major Customers The following purchasers accounted for 10% or more of the Company's oil and gas sales for the years ended December 31: 2003 2002 2001 --------------- -------------- --------------- Company A 30% 31% 38% Company B - 16% 23% Company C - 10% 25% Company D 33% - - (14) Commitments and Contingencies At December 31, 2003, the Company was involved in one lawsuit incidental to the Company's business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. The Company does not believe the ultimate outcome of this lawsuit will have a material adverse effect on the Company's financial position or results of operations, therefore no amount has been accrued. The Company is not aware of any threatened litigation. The Company has not been a party to any bankruptcy, receivership, reorganization, adjustment or similar proceeding. The Company established a simplified employee pension plan "SEP" covering all salaried employees of the Company. The employees voluntarily contribute a portion of their eligible compensation, not to exceed $12,000, to the plan. In addition to the annual salary deferral limit stated above, employees who reach age 50 or older during a calendar year can elect to take advantage of a catch-up salary deferral contribution; eligible participants can increase their salary deferral by $2,000 for the year 2003. The Company may make discretionary contributions to the plan; however, total contributions cannot exceed $40,000 per employee. During 2003, 2002 and 2001, the Company contributed an aggregate of approximately $106,000, $56,000, and $40,000, respectively, to the Plan. On November 25, 2003, the Company's Board of Directors approved in principle the adoption of an employee retention/severance plan that would be effective January 1, 2004. Although specific details of the plan have not been determined and the plan is not in final written form, the Company expects that the significant provisions of the plan will provide for a one-time payment of all officers and employees of the Company upon the occurrence of a change of control. The aggregate payments of all officers and employees will generally be 5% of an amount equal to the positive difference between the amount by which the Company's net asset value per share at the time of the occurrence of a change of control exceeds the net asset value per share as of January 1, 2004, compounded annually at a rate equal to the annual industry average growth rate, plus 2.00%. Generally the Company contemplates that a "change of control" will include events such as a merger, reorganization, liquidation or sale of substantially all of the asset of the Company, or the acquisition by a third party of 50% or more of our outstanding voting securities. The Company leases office space under a non-cancelable operating lease expiring in 2006. Future annual payments under this operating lease are $128,000, $157,000 and $105,000 for the years ended December 31, 2004, 2005 and 2006, respectively. Rental expense under our current and former lease totaled $130,000, $84,000 and $54,000 for the years ended December 31, 2003, 2002 and 2001, respectively. F-28 (15) Supplemental Oil and Gas Reserve Data (Unaudited) The Company has presented the reserve estimates utilizing an oil price of $30.63, $29.21 and $18.98 per Bbl and a gas price of $5.45, $4.40 and $2.72 per Mcf as of December 31, 2003, 2002 and 2001, respectively. Information for oil is presented in barrels (BBL) and for gas in thousands of cubic feet (MCF). The estimates of the Company's proved 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 Company's reserve information was prepared as of December 31, 2003, 2002 and 2001. 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 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. A summary of changes in reserve balances is presented below: Total proved Proved developed -------------------------- -------------------------- BBL MCF BBL MCF ------------ ------------- ------------ ------------- (in thousands) Reserves as of December 31, 2000 974 15,686 572 11,576 Sales of reserves in place (1) - (1) - Extensions and discoveries 78 1,737 78 1,737 Revisions of previous estimates 4 (210) (20) (473) Production (139) (3,266) (139) (3,266) ------------ ------------- ------------ ------------- Reserves as of December 31, 2001 916 13,947 490 9,574 Purchase of reserves in place 9,119 1,931 7,513 1,609 Sales of reserves in place - - - - Extensions and discoveries 323 2,048 323 2,048 Revisions of previous estimates 43 376 67 640 Production (130) (2,669) (130) (2,669) ------------ ------------- ------------ ------------- Reserves as of December 31, 2002 10,271 15,633 8,263 11,202 Extensions and discoveries 1,412 1,811 283 1,811 Revisions of previous estimates 1,030 2,183 1,027 2,409 Production (629) (3,356) (629) (3,356) ------------ ------------- ------------ ------------- Reserves as of December 31, 2003 12,084 16,271 8,944 12,066 ============ ============= ============ ============= The following is a standardized measure of the discounted net future cash flows and changes applicable to proved oil and gas reserves required by SFAS No. 69. The future cash flows are based on estimated oil and F-29 gas reserves utilizing prices and costs in effect as of year end, discounted at 10% per year and assuming continuation of existing economic conditions. During 2003, the average sales price received by the Company for its oil was approximately $29.11 (unhedged) per Bbl, as compared to $24.59 in 2002, while the average sales price for the Company's gas was approximately $5.40 (unhedged) per Mcf in 2003, as compared to $3.33 per Mcf in 2002. The standardized measure of discounted future net cash flows, in management's opinion, should be examined with caution. The basis for this table is the reserve studies prepared by independent petroleum 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 Company's proved oil and gas properties. F-30 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 Company's 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, --------------------------------------------- 2003 2002 2001 -------------- --------------- -------------- Future cash inflows $ 458,723 $ 368,835 $ 47,648 Future costs: Production (149,548) (103,924) (17,353) Development (15,485) (9,440) (4,874) --------- --------- -------- Future net cash flows before income taxes 293,690 255,471 25,421 Future income taxes (66,757) (58,622) (34) --------- --------- -------- Future net cash flows 226,933 196,850 25,387 10% annual discount for estimated timing of cash flows (110,667) (97,233) (8,312) --------- --------- -------- Standardized measure of discounted future net cash flows $ 116,266 $ 99,616 $ 17,075 ========= ========= ======== Changes in Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves (in thousands) December 31, ----------------------------------------- 2003 2002 2001 ------------- ------------- ------------- Increase (decrease): Sales of minerals in place $ - $ - $ (4) Purchases of minerals in place - 85,075 - Extensions and discoveries and improved recovery, net of future production and development costs 9,556 10,790 3,831 Accretion of discount 12,293 1,707 9,095 Net change in sales prices net of production costs 10,832 16,619 (68,367) Changes in estimated future development costs (6,948) (512) 5 Revisions of quantity estimates 13,520 1,218 (172) Net change in income taxes (8,204) (23,318) 9,662 Sales, net of production costs (25,451) (9,170) (13,919) Changes of production rates (timing) and other 11,052 132 (4,344) --------- -------- -------- Net increase (decrease) 16,650 82,541 (64,213) Standardized measure of discounted future net cash flows: Beginning of year 99,616 17,075 81,288 --------- -------- -------- End of year $ 116,266 $ 99,616 $ 17,075 ========= ======== ======== F-31 (16) Selected Quarterly Financial Results (Unaudited) Quarter ---------------------------------------------------- First Second Third Fourth ------------ ------------ ------------- ------------ (in thousands, except per share data) 2003 Oil and gas revenues $ 8,493 $ 8,532 $ 8,732 $ 8,098 Total costs and expenses 4,323 5,143 5,329 6,343 ------- ------- -------- ------- Operating income 4,170 3,389 3,403 1,755 ------- ------- -------- ------- Income before cumulative effect of change in accounting principle 2,313 2,671 1,695 985 Cumulative effect of change in accounting principle, net of tax (62) - - - ------- ------- -------- ------- Net income $ 2,251 $ 2,671 $ 1,695 $ 985 ======= ======= ======== ======= Net income after preferred stock dividend $ 2,105 $ 2,525 $ 1,549 $ 843 ======= ======= ======== ======= Net income per share: Basic: Income before cumulative effect of change in accounting principle $ 0.10 $ 0.12 $ 0.07 $ 0.04 Cumulative effect of change in accounting principle, net of tax - - - - ------- ------- ------- ------- Net income per common share $ 0.10 $ 0.12 $ 0.07 $ 0.04 ======= ======= ======= ======= Diluted: Income before cumulative effect of change in accounting principle $ 0.09 $ 0.11 $ 0.07 $ 0.04 Cumulative effect of change in accounting principle, net of tax - - - - ------- ------- -------- ------- Net income per common share $ 0.09 $ 0.11 $ 0.07 $ 0.04 ======= ======= ======== ======= During the fourth quarter of 2003, the Company reduced its estimate of State income tax liability by $907,000. 2002 Oil and gas revenues $ 1,971 $ 2,809 $ 2,710 $ 4,616 Total costs and expenses 2,254 4,029 2,319 4,030 Net income (769) 19,662 (398) 206 Net income (loss) after preferred stock dividend (915) 19,515 (544) 60 Net income per common share - basic $ (0.04) $ 0.94 $ (0.03) $ 0.02 Net income per common share - diluted $ (0.04) $ 0.84 $ (0.03) $ 0.01 2002 results include a gain of $31.1 million in the second quarter related to the sale of First Permian assets. F-32 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 March 22, 2004 By: /s/ Larry C. Oldham -------------------------- Larry C. Oldham, President and Chief Executive Officer 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/ Thomas R. Cambridge Chairman of the Board of Directors March 22, 2004 ------------------------ Thomas R. Cambridge /s/ Larry C. Oldham President and Chief Executive Officer March 22, 2004 ------------------------ (Principal Executive Officer) /s/ Steven D. Foster Chief Financial Officer March 22, 2004 ------------------------ (Principal Financial and Steven D. Foster Accounting Officer) /s/ Dewayne E. Chitwood Director March 22, 2004 ------------------------ Dewayne E. Chitwood /s/ Martin B. Oring Director March 22, 2004 ------------------------ Martin B. Oring /s/ Charles R. Pannill Director March 22, 2004 ------------------------ Charles R. Pannill /s/ Ray M. Poage Director March 22, 2004 ------------------------ Ray M. Poage /s/ Jeffrey G. Shrader Director March 22, 2004 ------------------------ Jeffrey G. Shrader S-1 INDEX TO EXHIBITS Exhibit No. Description of Exhibit ------- ---------------------- 3.1 Certificate of Incorporation of Registrant (Incorporated by reference to Exhibit 3.1 to Form 10-K of the Registrant for the fiscal year ended December 31, 1998) 3.2 Bylaws of Registrant (Incorporated by reference to Exhibit 3 to the Registrant's Form 8-K, dated October 9, 2000, as filed with the Securities and Exchange Commission on October 10, 2000) 4.1 Certificate of Designations, Preferences and Rights of Serial Preferred Stock - 6% Convertible Preferred Stock (Incorporated by reference to Exhibit 4.1 to Form 10-Q of the Registrant for the fiscal quarter ended September 30, 1998) 4.2 Certificate of Designation, Preferences and Rights of Series A Preferred Stock (Incorporated by reference to Exhibit 4.2 to 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 4.3 to Form 10-K of the Registrant for the fiscal year ended December 31, 2000) Executive Compensation Plans and Arrangements (Exhibit No.'s 10.1 through 10.9): 10.1 1983 Incentive Stock Option Plan (Incorporated by reference to Exhibit 10.2 to Form S-l of the Registrant (File No. 2-92397) as filed with the Securities and Exchange Commission on July 26, 1984, as amended by Amendments No. 1 and 2 on October 5, 1984, and October 25, 1984, respectively) 10.2 1992 Stock Option Plan (Incorporated by reference to Exhibit 28.1 to Form S-8 of the Registrant (File No. 33-57348) as filed with the Securities and Exchange Commission on January 25, 1993) 10.3 Stock Option Agreement between the Registrant and Thomas R. Cambridge dated December 11, 1991 (Incorporated by reference to Exhibit 10.4 of Form 10-K of the Registrant for the fiscal year ended December 31, 1992) 10.4 Stock Option Agreement between the Registrant and Thomas R. Cambridge dated October 18, 1993 (Incorporated by reference to Exhibit 10.4(e) of Form 10-K of the Registrant for the fiscal year ended December 31, 1993) 10.5 Merrill Lynch, Pierce, Fenner & Smith Incorporated Prototype Simplified Employee Pension Plan (Incorporated by reference to Exhibit 10.6 of the Registrant's Form 10-K for the fiscal year ended December 31, 1995) 10.6 Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.6 of the Registrant's Form 10-K Report for the fiscal year ended December 31, 1997) 1 Exhibit No. Description of Exhibit ------- ---------------------- 10.7 1998 Stock Option Plan (Incorporated by reference to Exhibit 10.7 of Form 10-K of the Registrant for the fiscal year ended December 31, 1998) 10.8 Form of Incentive Award Agreements, dated December 12, 2001, between the Registrant and Thomas R. Cambridge, Larry C. Oldham, Eric A. Bayley and John S. Rutherford granting 2,394 Unit Equivalent Rights to Mr. Cambridge; 9,564 Unit Equivalent Rights to Mr. Oldham; 2,869 Unit Equivalent Rights to Mr. Bayley; and 7,173 Unit Equivalent Rights to Mr. Rutherford (Incorporated by reference to Exhibit 10.8 of Form 10-K of the Registrant for the fiscal year ended December 31, 2001) 10.9 Form of Change of Control Agreements, dated June 1, 2001, between the Registrant and Thomas R. Cambridge, Larry C. Oldham, Eric A. Bayley and John S. Rutherford (Incorporated by reference to Exhibit 10.9 of Form 10-K of the Registrant for the fiscal year ended December 31, 2001) 10.10 Restated Loan Agreement, dated December 27, 1999, between the Registrant and Bank One, Texas, N.A. (Incorporated by reference to Exhibit 10.8 of Form 10-K of the Registrant for the fiscal year ended December 31, 1999) 10.11 Loan Agreement, dated December 18, 2000, between the Registrant and Bank United (Incorporated by reference to Exhibit 10.9 of Form 10-K of the Registrant for the fiscal year ended December 31, 2000) 10.12 Letter agreement, dated March 24, 1999, between the Registrant and Bank One, Texas, N.A. (Incorporated by reference to Exhibit 10.9 of Form 10-K of the Registrant for the fiscal year ended December 31, 1998) 10.13 Certificate of Formation of First Permian, L.L.C. (Incorporated by reference to Exhibit 10.1 of the Registrant's Form 8-K Report dated June 30, 1999) 10.14 Limited Liability Company Agreement of First Permian, L.L.C. (Incorporated by reference to Exhibit 10.2 of the Registrant's Form 8-K Report dated June 30, 1999) 10.15 Merger Agreement, dated June 25, 1999 (Incorporated by reference to Exhibit 10.3 of the Registrant's Form 8-K Report dated June 30, 1999) 10.16 Agreement and Plan of Merger of First Permian, L.L.C. and Nash Oil Company, L.L.C. (Incorporated by reference to Exhibit 10.4 of the Registrant's Form 8-K Report dated June 30, 1999) 10.17 Certificate of Merger of First Permian, L.L.C. and Nash Oil Company, L.L.C. (Incorporated by reference to Exhibit 10.5 of the Registrant's Form 8-K Report dated June 30, 1999) 10.18 Amended and Restated Limited Liability Company Agreement of First Permian, L.L.C. dated as of May 31, 2000 (Incorporated by reference to Exhibit 10.16 of Form 10-K of the Registrant for the fiscal year ended December 31, 2000) 2 Exhibit No. Description of Exhibit ------- ---------------------- 10.19 Credit Agreement, dated June 30, 1999, by and among First Permian, L.L.C., Parallel Petroleum Corporation, Baytech, Inc., and Bank One, Texas, N.A. (Incorporated by reference to Exhibit 10.6 of the Registrant's Form 8-K Report dated June 30, 1999) 10.20 Limited Guaranty, dated June 30, 1999, by and among First Permian, L.L.C., parallel Petroleum Corporation and Bank One, Texas, N.A. (Incorporated by reference to Exhibit 10.7 of the Registrant's Form 8-K Report dated June 30, 1999) 10.21 Intercreditor Agreement, dated as of June 30, 1999, among First Permian, L.L.C., Bank One, Texas, N.A., Tejon Exploration Company, and Mansefeldt Investment Corporation (Incorporated by reference to Exhibit 10.8 of the Registrant's Form 8-K Report dated June 30, 1999) 10.22 Subordinated Promissory Note, dated June 30, 1999, in the original principal amount of $8.0 million made by First Permian, L.L.C. payable to the order of Tejon Exploration Company (Incorporated by reference to Exhibit 10.9 of the Registrant's Form 8-K Report dated June 30, 1999) 10.23 Subordinated Promissory Note, dated June 30, 1999, in the original principal amount of $8.0 million made by First Permian, L.L.C. payable to the order of Mansefeldt Investment Corporation (Incorporated by reference to Exhibit 10.10 of the Registrant's Form 8-K Report dated June 30, 1999) 10.24 Second Restated Credit Agreement, dated October 25, 2000, among First Permian, L.L.C., Bank One, Texas, N.A., and Bank One Capital Markets, Inc. (Incorporated by reference to Exhibit 10.22 of Form 10-K of the Registrant for the fiscal year ended December 31, 2000) 10.25 Loan Agreement, dated as of January 25, 2002, between the Registrant and First American Bank, SSB (Incorporated by reference to Exhibit 10.25 of Form 10-K of the Registrant for the fiscal year ended December 31, 2001) 10.26 Purchase and Sale Agreement, dated as of November 27, 2002, among JMC Exploration, Inc., Arkoma Star L.L.C., Parallel, L.P. and Texland Petroleum, Inc. (Incorporated by reference to Exhibit 10.1 of Form 8-K of the Registrant, dated December 20, 2002) 10.27 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) 10.28 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) *14 Code of Ethics *21 Subsidiaries 3 Exhibit No. Description of Exhibit ------- ---------------------- *23.1 Consent of KPMG LLP *23.2 Consent of BDO Seidman, LLP *23.3 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. _______________ * Filed herewith. 4