e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OR THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2006 or
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 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)
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DELAWARE
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75-1971716 |
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(State of other jurisdiction of
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(I.R.S. Employer Identification No.) |
incorporation or organization) |
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1004 N. Big Spring, Suite 400, |
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Midland, Texas
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79701 |
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(Address of principal executive offices)
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(Zip Code) |
(432) 684-3727
(Registrants telephone number, including area code)
Not Applicable
(Former name, former address and former fiscal year,
if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, or a non-accelerated filer. See definition of accelerated filer and large accelerated
filer in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o Accelerated filer þ Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes o No þ
At May 4, 2006, 34,916,545 shares of the registrants common stock, $0.01 par value, were
outstanding.
Part I. Financial Information
Item 1. Financial Statements
PARALLEL PETROLEUM CORPORATION
Consolidated Balance Sheets
(dollars in thousands, except per share amounts)
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March 31, |
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December 31, |
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2006 |
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2005 |
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(unaudited) |
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Assets |
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Current assets: |
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Cash and cash equivalents |
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$ |
4,895 |
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$ |
6,418 |
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Accounts receivable: |
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Oil and natural gas |
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11,481 |
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13,183 |
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Other, net of allowance for doubtful account of $9 |
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2,155 |
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877 |
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Affiliates |
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9 |
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12 |
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13,645 |
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14,072 |
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Other current assets |
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3,467 |
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2,364 |
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Deferred tax asset |
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5,592 |
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5,241 |
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Total current assets |
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27,599 |
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28,095 |
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Property and equipment, at cost: |
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Oil and natural gas properties, full cost method (including $22,953 and $19,869 not
subject to depletion) |
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360,565 |
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303,819 |
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Other |
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3,865 |
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2,404 |
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364,430 |
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306,223 |
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Less accumulated depreciation, depletion and amortization |
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(95,114 |
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(90,826 |
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Net property and equipment |
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269,316 |
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215,397 |
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Restricted cash |
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274 |
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2,640 |
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Investment in Westfork Pipeline Companies |
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5,331 |
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3,326 |
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Other assets, net of accumulated amortization of $1,026 and $901 |
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3,252 |
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3,550 |
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$ |
305,772 |
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$ |
253,008 |
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Liabilities and Stockholders Equity |
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Current liabilities: |
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Accounts payable and accrued liabilities |
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$ |
12,512 |
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$ |
10,841 |
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Asset retirement obligations |
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332 |
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214 |
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Derivative obligations |
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18,655 |
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16,607 |
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Total current liabilities |
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31,499 |
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27,662 |
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Revolving credit facility |
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91,500 |
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50,000 |
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Term Loan |
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50,000 |
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50,000 |
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Asset retirement obligations |
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3,947 |
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2,281 |
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Derivative obligations |
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26,304 |
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25,527 |
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Deferred tax liability |
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9,667 |
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8,036 |
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Total long-term liabilities |
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181,418 |
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135,844 |
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Commitments and contingencies |
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Stockholders equity: |
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Series A preferred stock par value $0.10 per share, authorized 50,000 shares |
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Preferred stock 6% convertible preferred stock par value of $0.10 per share
(liquidation preference of $10 per share), authorized 10,000,000 shares, |
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Common stock par value $0.01 per share, authorized 60,000,000 shares,
issued and outstanding 34,891,545 and 34,748,916 |
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348 |
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347 |
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Additional paid-in capital |
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79,502 |
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78,699 |
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Retained earnings |
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18,510 |
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16,899 |
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Accumulated other comprehensive loss |
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(5,505 |
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(6,443 |
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Total stockholders equity |
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92,855 |
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89,502 |
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$ |
305,772 |
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$ |
253,008 |
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The accompanying notes are an integral part of these Consolidated Financial Statements.
(1)
PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Operations
For three months ended March 31, 2006 and 2005
(unaudited)
(dollars in thousands, except per share data)
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2006 |
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2005 |
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Oil and natural gas revenues: |
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Oil and natural gas sales |
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$ |
23,276 |
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$ |
12,969 |
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Loss on hedging |
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(2,733 |
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(2,555 |
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Total revenues |
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20,543 |
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10,414 |
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Cost and expenses: |
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Lease operating expense |
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3,575 |
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2,558 |
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Production taxes |
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1,110 |
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580 |
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General and administrative |
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2,129 |
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1,628 |
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Depreciation, depletion and amortization |
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4,288 |
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2,282 |
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Total costs and expenses |
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11,102 |
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7,048 |
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Operating income |
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9,441 |
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3,366 |
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Other income (expense), net: |
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Change in fair market value of derivative instruments |
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(4,714 |
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(17,633 |
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Gain (loss) on ineffective portion of hedges |
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143 |
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(710 |
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Interest and other income |
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68 |
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19 |
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Interest expense |
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(2,441 |
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(1,173 |
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Other expense |
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(29 |
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(1 |
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Equity in loss of Westfork Pipeline Companies |
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(19 |
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(79 |
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Total other income (expense), net |
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(6,992 |
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(19,577 |
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Income (loss) before income taxes |
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2,449 |
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(16,211 |
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Income tax benefit (expense), deferred |
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(838 |
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5,507 |
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Net income (loss) |
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1,611 |
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(10,704 |
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Cumulative preferred stock dividend |
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(143 |
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Net income (loss) available to common stockholders |
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$ |
1,611 |
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$ |
(10,847 |
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Net income (loss) per common share: |
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Basic |
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$ |
0.05 |
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$ |
(0.38 |
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Diluted |
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$ |
0.05 |
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$ |
(0.38 |
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Weighted average common share outstanding: |
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Basic |
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34,850 |
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28,698 |
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Diluted |
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35,547 |
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28,698 |
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The accompanying notes are an integral part of these Consolidated Financial Statements.
(2)
PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Cash Flows
Three Months Ended March 31, 2006 and 2005
(unaudited)
(dollars in thousands)
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2006 |
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2005 |
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Cash flows from operating activities: |
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Net income (loss) |
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$ |
1,611 |
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$ |
(10,704 |
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Adjustments to reconcile net income (loss) to net cash
provided by operating activities: |
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Depreciation, depletion and amortization |
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4,288 |
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2,282 |
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Accretion of asset retirement obligation |
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31 |
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26 |
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Deferred income tax |
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838 |
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(5,507 |
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Change in fair value of derivative instruments |
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4,714 |
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17,633 |
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(Gain) loss on ineffective portion of hedges |
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(143 |
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710 |
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Stock option expense |
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388 |
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42 |
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Equity in loss of Westfork Pipeline Companies |
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19 |
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79 |
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Changes in assets and liabilities: |
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Other assets, net |
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311 |
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48 |
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Decrease (increase) in accounts receivable |
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427 |
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(504 |
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Decrease in other current assets |
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107 |
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75 |
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Increase in accounts payable and accrued liabilities |
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1,671 |
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277 |
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Federal tax deposit |
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(40 |
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Net cash provided by operating activities |
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14,222 |
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4,457 |
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Cash flows from investing activities: |
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Additions to oil and natural gas properties |
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(55,035 |
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(8,596 |
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Use of restricted cash for acquisition of oil and natural gas properties |
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2,366 |
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2,287 |
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Proceeds from disposition of oil and natural gas properties |
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41 |
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2,539 |
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Additions to other property and equipment |
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(1,461 |
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(383 |
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Settlements on derivative instruments |
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(1,548 |
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(682 |
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Investment in Westfork Pipeline Companies |
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(2,024 |
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(245 |
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Net cash used in investing activities |
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(57,661 |
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(5,080 |
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Cash flows from financing activities: |
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Net borrowing (payments) on revolving line of credit |
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41,500 |
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(29,000 |
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Proceeds (net) from common stock issued |
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27,994 |
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Proceeds from exercise of stock options |
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416 |
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Net cash provided by (used in) financing activities |
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41,916 |
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(1,006 |
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Net decrease in cash and cash equivalents |
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(1,523 |
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(1,629 |
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Cash and cash equivalents at beginning of period |
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6,418 |
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4,781 |
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Cash and cash equivalents at end of period |
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$ |
4,895 |
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$ |
3,152 |
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Non-cash financing and investing activities: |
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Oil and natural gas properties asset retirement obligation |
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$ |
1,752 |
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$ |
(46 |
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Accrued preferred stock dividend |
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$ |
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$ |
143 |
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Other transactions: |
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Interest paid |
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$ |
2,082 |
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$ |
1,589 |
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The accompanying notes are an integral part of these Consolidated Financial Statements.
(3)
PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Comprehensive Income (Loss)
Three Months Ended March 31, 2006 and 2005
(unaudited)
(dollars in thousands)
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2006 |
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2005 |
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Net income (loss) |
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$ |
1,611 |
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$ |
(10,704 |
) |
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Other comprehensive loss: |
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Unrealized gains (losses) on derivatives |
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4,142 |
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(7,413 |
) |
Reclassification adjustments for (gains) losses |
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Change in fair value of derivatives |
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(2,721 |
) |
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2,630 |
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Change in fair value of derivatives |
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1,421 |
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(4,783 |
) |
Income tax benefit (expense) |
|
|
(483 |
) |
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1,626 |
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Total other comprehensive income (loss) |
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938 |
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(3,157 |
) |
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Total comprehensive income (loss) |
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$ |
2,549 |
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$ |
(13,861 |
) |
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The accompanying notes are an integral part of these Consolidated Financial Statements.
(4)
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. DESCRIPTION OF BUSINESS NATURE OF OPERATIONS AND BASIS OF PRESENTATION
Parallel was incorporated in Texas on November 26, 1979, and reincorporated in the State of
Delaware on December 18, 1984.
We are engaged in the acquisition, development and exploitation of long life oil and natural
gas reserves and, to a lesser extent, the exploration for new oil and natural gas reserves. Our
activities are focused in the Permian Basin of west Texas and New Mexico, the Fort Worth Basin of
north Texas and the onshore Gulf Coast area of south Texas. We are actively evaluating, leasing
and drilling new projects located in the Cotton Valley Reef trend of east Texas and the Uinta Basin
of Utah.
The financial information included herein is unaudited, except the balance sheet as of
December 31, 2005 which has been derived from our audited Consolidated Financial Statements as of
December 31, 2005. However, such information includes all adjustments (consisting solely of normal
recurring adjustments), which are, in the opinion of management, necessary for a fair statement of
the results of operations for the interim periods. The results of operations for the interim period
are not necessarily indicative of the results to be expected for an entire year. Certain 2005
amounts have been conformed to the 2006 financial statement presentation.
Certain information, accounting policies and footnote disclosures normally included in
financial statements prepared in accordance with accounting principles generally accepted in the
United States of America have been condensed or omitted in this Form 10-Q Report pursuant to
certain rules and regulations of the Securities and Exchange Commission. These financial statements
should be read in conjunction with the audited consolidated financial statements and notes included
in our Annual Report on Form 10-K for the year ended December 31, 2005.
Unless otherwise indicated or unless the context otherwise requires, all references to
Parallel, we, us, and our are to Parallel Petroleum Corporation and its consolidated
subsidiaries, Parallel L.P. and Parallel, L.L.C.
NOTE 2. STOCKHOLDERS EQUITY
Options
In September, 2003, Parallel adopted the provisions of Statement of Financial Accounting
Standards No. 148, Accounting for Stock-Based 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 used the prospective method which applied 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 was adopted..
In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment (SFAS 123(R)). The
standard amends SFAS 123 Accounting for Stock Based Compensation and concludes that services
received from employees in exchange for stock-based compensation results is a cost the employer
that
(5)
must be recognized in the financial statements. The cost of such awards should be measured at
fair value at grant date.
Parallel adopted SFAS 123(R) effective January 1, 2006, and is applying the modified
prospective method, whereby compensation cost will be recognized for the unvested portion of awards
granted during the period of June 2001 to August 2005. No options that were granted prior to June
2001 remain unvested at January 1, 2006. Such costs will be recognized in the financial statements
of Parallel over the remaining vesting periods. Under this method, prior periods are not revised
for comparative purposes.
For the three months ended March 31, 2006 and 2005, Parallel recognized compensation expense
of approximately $388,000 and $42,000, with a tax benefit of $132,000 and $14,000, respectively,
associated with its stock option grants.
The following table presents the future stock-based compensation expense expected to be
recognized over the vesting period of:
|
|
|
|
|
|
|
(in thousands) |
|
Second quarter 2006 |
|
$ |
196 |
|
Third quarter 2006 |
|
|
159 |
|
Fourth quarter 2006 |
|
|
105 |
|
2007 |
|
|
357 |
|
2008 through 2011 |
|
|
371 |
|
|
|
|
|
Total |
|
$ |
1,188 |
|
|
|
|
|
Non vested options were 237,500 for the three months ending March 31, 2006. During the
three months ending March 31, 2006, options to purchase 107,500 shares of common stock were
exercised; however, no options were granted, expired or forfeited.
The fair value of each option award is estimated on the date of grant. The fair value of
stock options granted prior to and remaining outstanding at January 1, 2006 and that had option
shares subject to future vesting at that date was determined using the Black-Scholes option
valuation method assumptions noted in the following table. Expected volatilities are based on
historical volatility of the stock. The expected term of the options granted used in the model
represent the period of time that options granted are expected to be outstanding.
|
|
|
|
|
|
|
|
|
|
|
2001 |
|
2005 |
Expected volatility |
|
|
57.95 |
% |
|
|
54.20 |
% |
Expected dividends |
|
|
0.00 |
|
|
|
0.00 |
|
Expected term (in years) |
|
|
8 |
|
|
|
8 |
|
Risk-free rate |
|
|
5.050 |
% |
|
|
4.200 |
% |
(6)
The following table illustrates the effect on net income and earnings per share if we had
applied the fair value recognition provisions of Statement No 123(R) to options under our
stock-based compensation plans in all periods presented.
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2005 |
|
Net loss, as reported |
|
$ |
(10,704 |
) |
Add: |
|
|
|
|
Expense recorded in 2005, net of related tax effects |
|
|
28 |
|
Deduct: |
|
|
|
|
Total stock-based employee compensation expense
determined under fair value based method for all awards,
net of related tax effects |
|
|
(48 |
) |
|
|
|
|
Pro forma net loss |
|
$ |
(10,724 |
) |
|
|
|
|
Loss per share: |
|
|
|
|
Basic as reported |
|
$ |
(0.38 |
) |
|
|
|
|
Basic pro forma |
|
$ |
(0.38 |
) |
|
|
|
|
|
|
|
|
|
Diluted as reported |
|
$ |
(0.38 |
) |
|
|
|
|
Diluted pro forma |
|
$ |
(0.38 |
) |
|
|
|
|
We have outstanding stock options granted under three separate plans. Options expire 10 years
from the date of grant and become exercisable at a rate of 10% each year on the first plan and
exercisable at a rate of 20% each year for the second and third plan. The exercise price cannot be
less than the fair market value per share of common stock on the date of grant.
Sale of Equity Securities
On February 9, 2005, we sold 5,750,000 shares of our common stock, $.01 par value per share,
pursuant to a public offering at a price of $5.27 per share. Gross cash proceeds were $30.3
million, and net proceeds were approximately $28.0 million. The common shares were issued under
Parallels $100.0 million Universal Shelf Registration Statement on Form S-3 which became effective
in November 2004. The proceeds were used to reduce the revolving credit facility.
Preferred Stock
On June 6, 2005, outstanding shares of Parallels 6% Convertible Preferred Stock, $0.10 par
value per share, were converted to common stock. Under terms of the preferred stock, all of the
holders of the preferred stock elected to convert their shares into shares of Parallel common stock
based on a conversion rate of $10.00 divided by $3.50. The holders of the preferred stock received
approximately 2.8571 shares of common stock of Parallel for each share of preferred stock.
Dividends on the preferred stock ceased to accrue, and as of June 6, 2005 the preferred stock was
no longer outstanding.
NOTE 3. CREDIT FACILITIES
We have two separate credit facilities. Our Third Amended and Restated Credit Agreement or the
Revolving Credit Agreement, dated as of December 23, 2005, with a group of bank lenders provides
a revolving line of credit having a borrowing base limitation of $125.0 million at March 31,
2006. The total amount that we can borrow and have outstanding at any one time is limited to the
lesser of $350.0 million or the borrowing base established by the lenders. At March 31, 2006, the
principal amount outstanding under our revolving credit facility was $91.5 million, excluding
$490,000 reserved for our
(7)
letters of credit. The second credit facility is a five year term loan
facility provided to us under a Second Lien Term Loan Agreement (the Second Lien Agreement),
dated as of November 15, 2005, with a group of banks and other lenders. At March 31, 2006, our term
loan under this facility was fully funded in the principal amount of $50.0 million, which was
outstanding on that same date.
Revolving Credit Facility
The Revolving Credit Agreement provides for a credit facility that allows us to borrow, repay
and reborrow amounts available under the revolving credit facility. The amount of the borrowing
base is based primarily upon the estimated value of our oil and natural gas reserves. The borrowing
base amount
is redetermined by the lenders semi-annually on or about April 1 and October 1 of each year or
at other times required by the lenders or at our request. If, as a result of the lenders
redetermination of the borrowing base, the outstanding principal amount of our loans exceeds the
borrowing base, we must either provide additional collateral to the lenders or repay the
outstanding principal of our loans in an amount equal to the excess. Except for the principal
payments that may be required because of our outstanding loans being in excess of the borrowing
base, interest only is payable monthly.
Loans made to us under this revolving credit facility bear interest at the base rate of
Citibank, N.A. or the LIBOR rate, at our election. Generally, Citibanks base rate is equal to its
prime rate as announced from time to time by Citibank.
The LIBOR rate is generally equal to the sum of (a) the rate designated as British Bankers
Association Interest Settlement Rates and offered on one, two, three, six or twelve month interest
periods for deposits of $1.0 million, and (b) a margin ranging from 2.00% to 2.50%, depending upon
the outstanding principal amount of the loans. If the principal amount outstanding is equal to or
greater than 75% of the borrowing base, the margin is 2.50%. If the principal amount outstanding is
equal to or greater than 50%, but less than 75% of the borrowing base, the margin is 2.25%. If the
principal amount outstanding is less than 50% of the borrowing base, the margin is 2.00%.
The interest rate we are required to pay on our borrowings, including the applicable margin,
may never be less than 5.00%. At March 31, 2006, our weighted average base and LIBOR rates, plus
margin, were 6.61% on $91.5 million.
In the case of base rate loans, interest is payable on the last day of each month. In the case
of LIBOR loans, interest is payable on the last day of each applicable interest period.
If the total outstanding borrowings under the revolving credit facility are less than the
borrowing base, an unused commitment fee is required to be paid to the lenders. The amount of the
fee is .25% of the daily average of the unadvanced amount of the borrowing base. The fee is payable
quarterly.
If the borrowing base is increased, we are required to pay a fee of .375% on the amount of any
increase in the borrowing base.
All outstanding principal under the revolving credit facility is due and payable on October
31, 2010. The maturity date of our outstanding loans may be accelerated by the lenders upon the
occurrence of an event of default under the Revolving Credit Agreement.
As of March 31, 2006 we were in compliance with our debt covenants.
Second Lien Term Loan Facility
The Second Lien Agreement provides a $50.0 million term loan. Loans made to us under this
credit facility bear interest at an alternate base
rate or the LIBOR rate, at our election. The
alternate base
(8)
rate is the greater of (a) the prime rate in effect on such day and (b) the Federal
Funds Effective Rate in effect on such day plus 1/2 of 1%, plus a margin of 3.50% per annum.
The LIBOR rate is generally equal to the sum of a (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) an applicable margin rate per annum equal to 4.50%.
At March 31, 2006, our Libor interest rate, plus the applicable margin, was 9.5% on $50.0
million.
In the case of alternate base rate loans, interest is payable the last day of each March,
June, September and December. In the case of LIBOR loans, interest is payable the last day of the
tranche period not to exceed a three month period.
All outstanding principal under the Second Lien Agreement is due and payable on November 15,
2010. The maturity date may be accelerated by the lenders upon the occurrence of an event of
default under the Second Lien Agreement.
Prepayments in whole or in part if made prior to the first anniversary date will bear a
premium of 1% of the amount prepaid. There is no premium after the first anniversary date.
As of March 31, 2006 we were in compliance with our debt covenants.
Interest expense for the three months ending March 31, 2006, for both facilities, was
approximately $2.5 million not including approximately $97,000 for interest capitalized associated
with drilling projects.
NOTE 4. ACQUISITIONS
In October and December 2004, we purchased properties in the Carm-Ann San Andres and North
Means Queen Unit located in Andrews and Gaines counties, Texas. The combined net purchase price
was approximately $16.5 million. In the first quarter of 2005, we acquired additional interest in
these properties for a net purchase price of approximately $2.3 million.
In November 2005 and January 2006, we purchased properties in the Harris San Andres located in
Andrews and Gaines County, Texas. The combined net purchase price was approximately $44.2 million.
In March 2006, we purchased additional interests in our Barnett Shale Gas Project located in
Tarrant County, Texas. The additional interests were acquired from five unaffiliated parties for a
total cash purchase price of approximately $5.5 million.
In a subsequent closing in April 2006, we acquired an additional interest in the Barnett Shale
Gas Project located in Tarrant County, Texas from one other unaffiliated third party for
approximately $573,000.
(9)
The table below reflects our consolidated pro forma results of operations for the three months
ended March 31, 2006, compared to the actual consolidated results of operations for the three
months ended March 31, 2005, assuming the 2006 acquisitions were consummated on January 1, 2005.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
Pro Forma |
|
|
Pro Forma |
|
|
|
2006 |
|
|
2005 |
|
|
|
(in thousands, except per share data) |
|
Oil and natural gas sales, net of hedge losses |
|
$ |
21,056 |
|
|
$ |
12,152 |
|
Operating income |
|
$ |
9,764 |
|
|
$ |
4,579 |
|
Net income (loss) available to common stockholder |
|
$ |
1,743 |
|
|
$ |
(10,633 |
) |
|
|
|
|
|
|
|
|
|
Net income (loss) per common share: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.05 |
|
|
$ |
(0.37 |
) |
Diluted |
|
$ |
0.05 |
|
|
$ |
(0.37 |
) |
NOTE 5. PREFERRED STOCK
At March 31, 2005, we had outstanding 950,000 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 preferred stock was entitled to 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 preferred stock has a liquidation
preference of $10 per share and had no voting rights, except as required by law.
On May 4, 2005, we notified the holders of the preferred stock that all 950,000 outstanding
shares of our 6% preferred stock would be redeemed on June 6, 2005. All of the holders of the
preferred stock elected to convert their shares of preferred stock into shares of Parallel common
stock based on a conversion rate of $10 divided by $3.50. The holders of the preferred stock
received approximately 2.8571 shares of common stock of Parallel for each share of preferred stock.
Dividends on the preferred stock ceased to accrue, and as of June 6, 2005 the preferred stock was
no longer outstanding.
NOTE 6. FULL COST CEILING TEST
We use the full cost method to account for our oil and natural gas producing activities. Under
the full cost method of accounting, the net book value of oil and natural gas properties, less
related deferred income taxes and asset retirement obligations, may not exceed a calculated
ceiling. The ceiling limitation is the discounted estimated after-tax future net cash flows from
proved oil and natural gas properties. In calculating future net cash flows, current prices and
costs are generally held constant indefinitely as adjusted for qualifying cash flow hedges. The
net book value of oil and natural gas properties, less related deferred income taxes over the
ceiling, is compared to the ceiling on a quarterly and annual basis. Any excess of the net book
value, less related deferred income taxes, is generally written off as an expense. Under rules and
regulations of the SEC, the excess above the ceiling is not written off if, subsequent to the end
of the quarter or year but prior to the release of the financial results, prices have increased
sufficiently that such excess above the ceiling would not have existed if the increased prices were
used in the calculations.
(10)
At March 31, 2006, we had a cushion (i.e. the excess of the ceiling over our capitalized cost)
in excess of $233.0 million. As a result, we were not required to record a reduction of our oil and
natural gas properties under the full cost method of accounting at that time.
Under the full cost method of accounting, all costs incurred in the acquisition, exploration
and development of oil and natural gas properties, including a portion of our overhead, are
capitalized. In the three month periods ended March 31, 2006 and 2005, overhead costs capitalized
were approximately $440,000 and $286,000, respectively.
NOTE 7. DERIVATIVE INSTRUMENTS
General
We enter into derivative contracts to provide a measure of stability in the cash flows
associated with our oil and natural gas production 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
natural gas prices and to limit variability in our cash interest payments. Our line of credit
agreement as of March 31, 2006, required us to maintain derivative financial instruments which
limit our exposure to fluctuating commodity prices covering at least 50% of our estimated monthly
production of oil and natural gas extending 24 months into the future.
We designated all of our interest rate swaps, collars, puts and commodity swaps entered into
in 2002 through June 30, 2004 as cash flow hedges (hedges). The effective portion of the
unrealized gain or loss on cash flow hedges is recorded in other comprehensive income (loss) until
the forecasted transaction occurs. During the term of a cash flow hedge, the effective portion of
the 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 natural gas revenues when the
production is sold and interest expense as the interest accrues. Ineffective portions of hedges
(changes in fair value resulting from changes in realized prices that do not match the changes in
the hedge or reference price) are recognized in gain (loss) on ineffective portion of hedges as
they occur.
As of March 31, 2006, we have recorded unrealized losses of $8.3 million ($5.5 million, net of
tax) related to our derivative instruments designated as hedges, which represented the estimated
aggregate fair values of our open hedge contracts as of that date. These unrealized losses are
presented in stockholders equity in the Consolidated Balance Sheet as accumulated other
comprehensive loss.
Derivative contracts not designated as hedges are marked-to-market at each period end and
the increases or decreases in fair values recorded to earnings. No derivative instruments entered
into subsequent to June 30, 2004 have been designated as cash flow hedges.
We are exposed to credit risk in the event of nonperformance by the counterparty to these
contracts, BNP Paribas and Citibank, N.A. However, we periodically assess the creditworthiness of
the counterparty to mitigate this credit risk.
Interest Rate Sensitivity
We entered into fixed interest rate swap contracts with BNP Paribas, based on the 90-day LIBOR
rates at the time of the contracts. These interest rate swaps are treated as cash flow hedges as
defined by Statement of Financial Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities, as amended (SFAS 133), and are on $10.0 million of our
variable rate debt for all of 2006. We will continue to pay the variable interest rates for this
portion of our borrowing under the
(11)
Credit Agreement, but due to the interest rate swaps, we have
fixed the rate at 4.05%. As of March 31, 2006, the fair market value of these interest rate swaps
was $78,000.
As of March 31, 2006, we had also employed additional fixed interest rate swap contracts with
BNP Paribas and Citibank, N.A. based on the 90-day LIBOR rates at the time of the contracts.
However, these contracts are accounted for by mark-to-market accounting as prescribed in SFAS
133. Nonetheless, we view these contracts as additional protection against future interest rate
volatility.
The table below recaps the nature of these interest rate swaps and the fair market value of
these contracts as of March 31, 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional |
|
|
|
|
|
|
Fair |
|
Period of Time |
|
Amounts |
|
|
Fixed Interest Rates |
|
|
Market Value |
|
|
|
($ in millions) |
|
|
|
|
|
|
($ in thousands) |
|
April 1, 2006 thru December 31, 2006(1) |
|
$ |
10 |
|
|
|
4.05 |
% |
|
|
78 |
|
April 1, 2006 thru December 31, 2006 |
|
$ |
90 |
|
|
|
4.41 |
% |
|
|
480 |
|
January 1, 2007 thru December 31, 2007 |
|
$ |
100 |
|
|
|
4.62 |
% |
|
|
534 |
|
January 1, 2008 thru December 31, 2008 |
|
$ |
100 |
|
|
|
4.86 |
% |
|
|
264 |
|
January 1, 2009 thru December 31, 2009 |
|
$ |
50 |
|
|
|
5.06 |
% |
|
|
64 |
|
January 1, 2010 thru October 31, 2010 |
|
$ |
50 |
|
|
|
5.15 |
% |
|
|
38 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
$ |
1,458 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Designated as cash flow hedge. |
Commodity Price Sensitivity
Except for the one commodity swap noted in the table below under Commodity Swaps that is
designated as a hedge, all of our commodity derivatives are accounted for using mark-to-market
accounting as prescribed in SFAS 133.
Put Options. In 2005 we purchased put options or floors on volumes of 3,000 MMBtu
per day for a total of 642,000 MMBtu during the seven month period from April 1, 2006 through
October 31, 2006 at an average floor price of $7.17 per MMBtu for a total consideration of
approximately $230,000. The puts have fair market value of $514,000 as of March 31, 2006.
Collars. Collars are contracts which combine both a put option or floor and a call
option or ceiling. These contracts may or may not involve payment or receipt of cash at
inception, depending on the ceiling and floor pricing.
(12)
A summary of our collar positions at March 31, 2006 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Houston Ship |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Channel Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
NyMex Oil Prices |
|
|
|
|
|
|
Prices |
|
|
WAHA Gas Prices |
|
|
Fair |
|
|
|
Barrels of |
|
|
|
|
|
|
|
|
|
|
MMBtu of |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market |
|
Period of Time |
|
Oil |
|
|
Floor |
|
|
Cap |
|
|
Natural Gas |
|
|
Floor |
|
|
Cap |
|
|
Floor |
|
|
Cap |
|
|
Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
|
April 1, 2006 thru December 31, 2006 |
|
|
217,800 |
|
|
$ |
48.26 |
|
|
$ |
75.91 |
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(1,342 |
) |
April 1, 2006 thru October 31, 2006 |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
|
428,000 |
|
|
$ |
7.50 |
|
|
$ |
13.90 |
|
|
$ |
|
|
|
$ |
|
|
|
|
442 |
|
April 1, 2006 thru October 31, 2006 |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
|
214,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
9.00 |
|
|
$ |
14.55 |
|
|
|
546 |
|
January 1, 2007 thru December 31, 2007 |
|
|
219,000 |
|
|
$ |
52.50 |
|
|
$ |
83.00 |
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
(276 |
) |
April 1, 2007 thru October 31, 2007 |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
|
214,000 |
|
|
$ |
6.00 |
|
|
$ |
11.05 |
|
|
$ |
|
|
|
$ |
|
|
|
|
(100 |
) |
January 1, 2008 thru December 31, 2008 |
|
|
109,800 |
|
|
$ |
55.00 |
|
|
$ |
76.50 |
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
(196 |
) |
January 1, 2009 thru December 31, 2009 |
|
|
91,250 |
|
|
$ |
55.00 |
|
|
$ |
73.00 |
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
(207 |
) |
January 1, 2010 thru December 31, 2010 |
|
|
76,000 |
|
|
$ |
55.00 |
|
|
$ |
71.00 |
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
(176 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(1,309 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Swaps. Generally, swaps are an agreement to buy or sell a specified
commodity for delivery in the future, at an agreed fixed price. Swap transactions convert a
floating or market price into a fixed price. For any particular swap transaction, the counterparty
is required to make a payment to the Company if the reference price for any settlement period is
less than the swap or fixed price for such contract, and the Company is required to make a payment
to the counterparty if the reference price for any settlement period is greater than the swap or
fixed price for such contract.
We have entered into oil swap contracts with BNP Paribas. A recap for the period of time,
number of barrels and swap prices are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nymex Oil |
|
|
Fair Market |
|
Period of Time |
|
Barrels of Oil |
|
|
Swap Price |
|
|
Value |
|
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
|
April 1, 2006 thru December 20, 2006(1) |
|
|
198,000 |
|
|
$ |
23.04 |
|
|
$ |
(8,903 |
) |
April 1, 2006 thru December 31, 2006 |
|
|
137,500 |
|
|
$ |
36.35 |
|
|
|
(4,391 |
) |
January 1, 2007 thru December 31, 2007 |
|
|
474,500 |
|
|
$ |
34.36 |
|
|
|
(15,645 |
) |
January 1, 2008 thru December 31, 2008 |
|
|
439,200 |
|
|
$ |
33.37 |
|
|
|
(13,723 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total fair market value |
|
|
|
|
|
|
|
|
|
$ |
(42,662 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Designated as a cash flow hedge. |
(13)
NOTE 8. NET INCOME (LOSS) PER COMMON SHARE
Basic earnings per share (EPS) exclude any dilutive effects of option, warrants and
convertible securities and is computed by dividing income available to common stockholders by the
weighted average number of common shares outstanding for the period. Diluted earnings per share are
computed similar to basic earnings per share. However, diluted earnings per share reflect the
assumed conversion of all potentially dilutive securities.
The following table provides the computation of basic and diluted earnings per share for the
three months ended March 31, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2006 |
|
|
2005 |
|
|
|
(in thousands except per share data) |
|
Basic EPS Computation: |
|
|
|
|
|
|
|
|
Numerator- |
|
|
|
|
|
|
|
|
Income (loss) |
|
$ |
1,611 |
|
|
$ |
(10,704 |
) |
Preferred stock dividend |
|
|
|
|
|
|
(143 |
) |
|
|
|
|
|
|
|
Income (loss) available to common stockholders |
|
$ |
1,611 |
|
|
$ |
(10,847 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator- |
|
|
|
|
|
|
|
|
Weighted average common shares outstanding |
|
|
34,850 |
|
|
|
28,698 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic EPS: |
|
|
|
|
|
|
|
|
Income (loss) per share |
|
$ |
0.05 |
|
|
$ |
(0.38 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS Computation: |
|
|
|
|
|
|
|
|
Numerator- |
|
|
|
|
|
|
|
|
Income (loss) |
|
$ |
1,611 |
|
|
$ |
(10,704 |
) |
Preferred stock dividend |
|
|
|
|
|
|
(143 |
) |
|
|
|
|
|
|
|
|
Income (loss) available to common stockholders |
|
$ |
1,611 |
|
|
$ |
(10,847 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator - |
|
|
|
|
|
|
|
|
Weighted average common shares outstanding |
|
|
34,850 |
|
|
|
28,698 |
|
Employee stock options |
|
|
594 |
|
|
|
|
|
Warrants |
|
|
103 |
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares for diluted earnings
per share assuming conversion |
|
|
35,547 |
|
|
|
28,698 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS: |
|
|
|
|
|
|
|
|
Income (loss) per share |
|
$ |
0.05 |
|
|
$ |
(0.38 |
) |
|
|
|
|
|
|
|
Some stock options and the convertible preferred stock outstanding were not included in
the computation of diluted net income (loss) per share for the three months ended March 31, 2005
because Parallel had a net loss from continuing operations and, therefore, the effect would be
antidilutive.
(14)
NOTE 9. ASSET RETIREMENT OBLIGATIONS
On January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143, Accounting
for Asset Retirement Obligations SFAS 143. SFAS 143 requires us to recognize a liability for
the present value of all obligations associated with the retirement of tangible long-lived assets
and to capitalize an equal amount as a cost of the related oil and natural gas properties.
The following table summarizes our asset retirement obligation transactions:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2006 |
|
|
2005 |
|
|
|
(dollars in thousands) |
|
Beginning asset retirement obligation |
|
$ |
2,495 |
|
|
$ |
2,132 |
|
Additions related to new properties |
|
|
107 |
|
|
|
19 |
|
Revisions in estimated cash flows |
|
|
1,665 |
|
|
|
(2 |
) |
Deletions related to property disposals |
|
|
(20 |
) |
|
|
(63 |
) |
Accretion expense |
|
|
32 |
|
|
|
26 |
|
|
|
|
|
|
|
|
Ending asset retirement obligation |
|
$ |
4,279 |
|
|
$ |
2,112 |
|
|
|
|
|
|
|
|
NOTE 10. COMMITMENTS AND CONTINGENCIES
On December 30, 2005, Parallel was named as a defendant in a lawsuit filed in the 352nd
Judicial District Court of Tarrant County, Texas, Cause No. 352-215616-05, AFE Oil and Gas, L.L.C.
(aka AFE Oil and Gas, LLC) v. Premium Resources II, L.P., Premium Resources, Inc., Danay Covert,
Nick Morris, William D. Middleton, Dale Resources, L.L.C., and Parallel Petroleum, Inc.
In this suit, the plaintiff alleges breach of fiduciary duty, fraud and conspiracy to defraud,
breach of contract, constructive trust, suit to remove cloud from title, declaratory judgment,
alter ego, and statutory fraud and seeks recovery of an unspecified amount of actual damages,
special damages, consequential damages, exemplary damages, attorneys fees, pre-judgment and
post-judgment interest and costs. Generally, the plaintiff alleges that it owns a 5.5% overriding
royalty interest in certain oil and gas properties known as the Square Top LP and the West Fork
LP leases located in Tarrant County, Texas. The plaintiff alleges that the defendants (other than
Dale Resources and Parallel) wrongfully and intentionally allowed these original oil and gas leases
to terminate, causing the termination of plaintiffs overriding royalty interest in each lease. The
plaintiff further alleges that the defendants (other than Dale Resources and Parallel) failed to
drill wells necessary to maintain the original leases in force and that after the original leases
were allowed to terminate, the defendants (other than Dale Resources and Parallel) then acquired
new oil and gas leases covering these same oil and gas properties, which were subsequently assigned
to Dale Resources. Thereafter, Dale Resources allegedly assigned a portion of these new leases to
Parallel.
In addition to seeking unspecified monetary damages, the plaintiff also seeks to impose a
constructive trust for its benefit on the new oil and natural gas leases and seeks a judicial
declaration that either (1) the plaintiff is the owner of an overriding royalty interest in the new
leases or that (2) the original leases and plaintiffs interest in the original leases are still in
effect. The plaintiff also claims that the new leases constitute a cloud on plaintiffs title and
seeks to have that cloud removed. Based on Parallels present understanding of this case, Parallel
believes that it has substantial defenses to the plaintiffs claims and intends to vigorously
assert these defenses. However, if the plaintiff is awarded an interest in the new leases, then
Parallel could potentially become liable for the payment to plaintiff of the
(15)
portion of production
proceeds attributable to plaintiffs interest received by Parallel. On the other hand,
if the plaintiff prevails on its claim that the original leases are still in effect,
Parallels interest in the new leases could become subject to forfeiture. Based on the information
known to date, Parallel has not established a reserve for this matter.
From time to time, we are party to ordinary routine litigation incidental to our business. We
are currently a defendant in one other lawsuit. We do not believe the ultimate outcome of this
lawsuit will have a material adverse effect on our financial condition or results of options. We
are not aware of any other threatened litigation and we have not been a party to any bankruptcy,
receivership, reorganization, adjustment or similar proceeding.
Effective January 1, 2005, we established a 401(k) Plan and Trust for eligible employees.
Employees may not participate in the former SEP plan with the establishment of the 401(k) Plan and
Trust. As of the quarter ended March 31, 2006 and 2005 Parallel had made contributions to the
401(k) Plan and Trust of approximately $56,000 and $38,000, respectively.
|
|
|
ITEM 2. |
|
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. |
The following discussion and analysis should be read in conjunction with managements
discussion and analysis contained in our 2005 Annual Report on Form 10-K, as well as the unaudited
consolidated financial statements and notes thereto included in this quarterly report on Form 10-Q.
OVERVIEW
Strategy
Our primary objective is to increase shareholder value of our common stock through increasing
reserves, production, cash flow and earnings. We have shifted the balance of our investments from
properties having high rates of production in early years to properties expected to produce more
consistently over a longer term. We attempt to reduce our financial risks by dedicating a smaller
portion of our capital to high risk projects, while reserving the majority of our available capital
for exploitation and development drilling opportunities. Obtaining positions in long-lived oil and
natural gas reserves are given priority over properties that might provide more cash flow in the
early years of production, but which have shorter reserve lives. We also attempt to further reduce
risk by emphasizing acquisition possibilities over high risk exploration projects.
Since the latter part of 2002, we have reduced our emphasis on high risk exploration efforts
and focused on established geologic trends where we 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. |
(16)
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 natural gas we produce; |
|
|
|
|
the results of reprocessing and reinterpreting our 3-D seismic data; |
|
|
|
|
the results of our drilling activities; |
|
|
|
|
the costs of obtaining high quality field services; |
|
|
|
|
our ability to find and consummate acquisition opportunities; and |
|
|
|
|
our ability to negotiate and enter into work to earn arrangements, joint venture or
other similar agreements on terms acceptable to us. |
Significant changes in the prices we receive for the oil and natural gas, or the occurrence of
unanticipated events beyond our control may cause us to defer or deviate from our business plan,
including the amounts we have budgeted for our activities.
Operating Performance
Our operating performance is influenced by several factors, the most significant of which are
the prices we receive for our oil and natural gas and 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. Natural gas prices we receive are influenced by:
|
|
|
seasonal demand; |
|
|
|
|
weather; |
|
|
|
|
hurricane conditions in the Gulf of Mexico; |
|
|
|
|
availability of pipeline transportation to end users; |
|
|
|
|
proximity of our wells to major transportation pipeline infrastructures; and |
|
|
|
|
to a lesser extent, world oil prices. |
(17)
Additional factors influencing our overall operating performance include:
|
|
|
production expenses; |
|
|
|
|
overhead requirements; and |
|
|
|
|
costs of capital. |
Our oil and natural 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. |
For the three months ended March 31, 2006, the sale price we received for our crude oil
production (excluding hedges) averaged $57.66 per barrel compared with $54.31 per barrel for the
three months ended December 31, 2005 and $45.29 per barrel for the three months ended March 31,
2005. The average sales price we received for natural gas for the three months ended March 31,
2006 (excluding hedges), was $6.68 per Mcf compared with $9.64 per Mcf for the three months ended
December 31, 2005 and $6.00 per Mcf for the three months ended March 31, 2005. For information
regarding prices received including our hedges, refer to the selected operating data table in the
Results of Operations on page 19. Hedge costs for oil and natural gas were $2.7 million, $3.4
million and $2.6 million for the three months ended March 31, 2006, December 31, 2005 and March 31,
2005, respectively. The hedge gain (loss) associated with the ineffective portion of our hedges
increased $853,000 to a gain of approximately $143,000 in the three months ended March 31, 2006
compared to a loss of approximately $710,000 for the three months ended March 31, 2005. The
reduction in ineffectiveness is caused by a reduction of the differential price of West Texas
Intermediate Light and current designated sales of West Texas Sour barrels. U. S. refineries are
currently paying a premium for West Texas Intermediate, which is the NyMex benchmark. The majority
of our oil is West Texas Sour. Actual gains or losses may increase or decrease until settlement of
these contracts.
Our oil and natural 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 natural gas properties and the exploration for and development of oil and
natural gas reserves. 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 natural 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 natural gas properties, including estimated
future development costs, is provided using the equivalent unit-of-production method based upon
estimates of proved oil and natural gas reserves and production, which are converted to a common
unit of measure based upon their relative energy content. Unproved oil and natural gas properties
are not amortized, but
(18)
are individually assessed for impairment. The cost of any impaired property is transferred to
the balance of oil and natural gas properties being depleted. Depletion per BOE at March 31, 2006
and 2005 was $9.02 and $7.06 respectively.
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 natural gas production. |
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 months ended March 31, 2006, December 31, 2005, and March 31,
2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
3/31/2006 |
|
|
12/31/2005 |
|
|
3/31/2005 |
|
|
|
(in thousands, except per unit data) |
|
Production Volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
268 |
|
|
|
251 |
|
|
|
207 |
|
Natural gas (Mcf) |
|
|
1,167 |
|
|
|
1,181 |
|
|
|
602 |
|
BOE(1) |
|
|
463 |
|
|
|
448 |
|
|
|
307 |
|
BOE per day |
|
|
5.1 |
|
|
|
4.9 |
|
|
|
3.4 |
|
|
Sales Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)(2) |
|
$ |
57.66 |
|
|
$ |
54.31 |
|
|
$ |
45.29 |
|
Natural gas (per Mcf)(2) |
|
$ |
6.68 |
|
|
$ |
9.64 |
|
|
$ |
6.00 |
|
BOE price(2) |
|
$ |
50.27 |
|
|
$ |
55.86 |
|
|
$ |
42.25 |
|
BOE price(3) |
|
$ |
44.37 |
|
|
$ |
48.31 |
|
|
$ |
33.93 |
|
|
Operating Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
15,482 |
|
|
$ |
13,632 |
|
|
$ |
9,359 |
|
Oil hedge |
|
|
(2,733 |
) |
|
|
(3,380 |
) |
|
|
(2,354 |
) |
Natural gas |
|
|
7,794 |
|
|
|
11,384 |
|
|
|
3,610 |
|
Natural gas hedge |
|
|
|
|
|
|
|
|
|
|
(201 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
20,543 |
|
|
$ |
21,636 |
|
|
$ |
10,414 |
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
|
$ |
3,575 |
|
|
$ |
2,548 |
|
|
$ |
2,558 |
|
Production taxes |
|
|
1,110 |
|
|
|
1,487 |
|
|
|
580 |
|
General and administrative: |
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative |
|
|
1,134 |
|
|
|
1,348 |
|
|
|
969 |
|
Public reporting |
|
|
995 |
|
|
|
593 |
|
|
|
659 |
|
Depreciation, depletion and amortization |
|
|
4,288 |
|
|
|
3,885 |
|
|
|
2,282 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
11,102 |
|
|
$ |
9,861 |
|
|
$ |
7,048 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
9,441 |
|
|
$ |
11,775 |
|
|
$ |
3,366 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
A BOE means one barrel of oil equivalent using the ratio of six Mcf of gas
to one barrel of oil. |
|
(2) |
|
Excludes hedge transactions. |
|
(3) |
|
Includes hedge transactions. |
(19)
RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2006 AND 2005:
Our oil and natural gas revenues and production product mix are displayed in the following
table for the three months ended March 31, 2006 and March 31, 2005.
Oil and Gas Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues (1) |
|
Production |
|
|
2006 |
|
2005 |
|
2006 |
|
2005 |
Oil (Bbls) |
|
|
62 |
% |
|
|
67 |
% |
|
|
58 |
% |
|
|
67 |
% |
Natural gas (Mcf) |
|
|
38 |
% |
|
|
33 |
% |
|
|
42 |
% |
|
|
33 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes hedge transactions |
The following table outlines the detail of our operating revenues for the following periods.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
Increase |
|
|
% Increase |
|
|
|
2006 |
|
|
2005 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
(in thousands except per unit data) |
|
Production Volumes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
268 |
|
|
|
207 |
|
|
|
61 |
|
|
|
29 |
% |
Natural gas (Mcf) |
|
|
1,167 |
|
|
|
602 |
|
|
|
565 |
|
|
|
94 |
% |
BOE |
|
|
463 |
|
|
|
307 |
|
|
|
156 |
|
|
|
51 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)(1) |
|
$ |
57.66 |
|
|
$ |
45.29 |
|
|
$ |
12.37 |
|
|
|
27 |
% |
Natural gas (per Mcf)(1) |
|
$ |
6.68 |
|
|
$ |
6.00 |
|
|
$ |
0.68 |
|
|
|
11 |
% |
BOE price(1) |
|
$ |
50.27 |
|
|
$ |
42.25 |
|
|
$ |
8.02 |
|
|
|
19 |
% |
BOE price(2) |
|
$ |
44.37 |
|
|
$ |
33.93 |
|
|
$ |
10.44 |
|
|
|
31 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
15,482 |
|
|
$ |
9,359 |
|
|
|
6,123 |
|
|
|
65 |
% |
Oil hedges |
|
$ |
(2,733 |
) |
|
$ |
(2,354 |
) |
|
|
379 |
|
|
|
16 |
% |
Natural gas |
|
$ |
7,794 |
|
|
$ |
3,610 |
|
|
|
4,184 |
|
|
|
116 |
% |
Natural gas hedges |
|
$ |
|
|
|
$ |
(201 |
) |
|
|
201 |
|
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
20,543 |
|
|
$ |
10,414 |
|
|
|
10,129 |
|
|
|
97 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Excludes hedge transactions. |
|
(2) |
|
Includes hedge transactions. |
Oil revenues, excluding hedges, increased $6.1 million or 65% for the three months ended
March 31, 2006 compared to the same period of 2005. Oil production volumes increased 29%
attributable to acquisitions in the Carm-Ann San Andres Field/N. Means Queen Unit, Harris San
Andres and the drilling of producing wells on our Diamond M Property. The increase in oil
production increased revenue approximately $2.8 million for 2006. Wellhead average realized crude
oil prices increased $12.37 per Bbl or 27% to $57.66 per Bbl for 2006 compared to 2005. The
increase in oil price increased revenue approximately $3.3 million for 2006.
(20)
Natural gas revenues, excluding hedges, increased $4.2 million or 116% for the three months
ended March 31, 2006 compared to the same period of 2005. Natural gas production volumes increased
94% due to the Barnett Shale and a Wilcox gas discovery in our onshore Gulf Coast property offset
by
natural production declines in our south Texas Yegua/Frio and Cook Mountain projects. The
increase in natural gas volumes increased revenue approximately $3.4 million for 2006. Average
realized wellhead natural gas prices increased 11% or $0.68 per Mcf to $6.68 per Mcf. The increase
in natural gas prices had a positive effect on revenues of approximately $794,000 for the three
months ending March 31, 2006.
Losses on oil hedges increased $379,000 or 16% for 2006 compared to 2005 due to the increase
in oil prices. Natural gas hedge losses were $0 in 2006 compared to
a loss of $201,000 in 2005.
On a BOE basis, hedges accounted for a realized loss of $5.90 per BOE in 2006 compared to $8.32 per
BOE in 2005. We have hedged certain oil and natural gas volumes to try and mitigate price changes
in our oil and natural gas movements and to meet the requirements under our loan facility.
With our recently announced results in the Diamond M Canyon Reef Unit, Carm-Ann, the New
Mexico Gas Project and Barnett Shale, we expect increased production volumes over the first quarter
2006 if initial rates are maintained.
Cost and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31, |
|
|
Increase |
|
|
% Increase |
|
|
|
2006 |
|
|
2005 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
(dollars in thousands) |
|
Lease operating expense |
|
$ |
3,575 |
|
|
$ |
2,558 |
|
|
$ |
1,017 |
|
|
|
40 |
% |
Production taxes |
|
|
1,110 |
|
|
|
580 |
|
|
|
530 |
|
|
|
91 |
% |
General and administrative: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative |
|
|
1,134 |
|
|
|
969 |
|
|
|
165 |
|
|
|
17 |
% |
Public reporting |
|
|
995 |
|
|
|
659 |
|
|
|
336 |
|
|
|
51 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative |
|
|
2,129 |
|
|
|
1,628 |
|
|
|
501 |
|
|
|
31 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
4,288 |
|
|
|
2,282 |
|
|
|
2,006 |
|
|
|
88 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
11,102 |
|
|
$ |
7,048 |
|
|
$ |
4,054 |
|
|
|
58 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating costs increased approximately $1.0 million, or 40%, to $3.6 million
during the three months ended March 31, 2006 compared with $2.6 million for the same period of
2005. The increase in lease operating expense is primarily due to our acquisitions in the Carm-Ann
San Andres Field/N. Means Queen Unit and Harris San Andres, increased ad valorem taxes and
increased utility costs on our oil properties. Lifting costs were
$7.72 per BOE in 2006 compared
to $8.33 per BOE in 2005. As we continue to exploit and develop our long-life
Permian Basin oil properties (Fullerton, Carm-Ann and Diamond M), we expect that lifting costs will
continue around the same level or decline due to increased activity. The lifting costs are also
expected to be reduced with continued development of natural gas properties in south Texas, Barnett
Shale and New Mexico.
Production taxes increased 91% or $530,000 in 2006, associated with a net wellhead
increase in revenues of $10.3 million. Production taxes in future periods will be a function of
product mix, production volumes and product prices.
General and administrative expenses in total increased 31% or $501,000 in 2006 compared to
2005. Included in our total general and administrative expenses is public reporting cost which
increased 51% or $336,000 for 2006. The increase in general and administrative costs is due to
salaries and benefits related to additional staffing with our accelerated business plan. Public
reporting cost increased with stock option expense pertaining to option grants in 2005 to the Board
of Directors and road shows during
(21)
the first three months of 2006. General and administrative
expenses capitalized to the full cost pool were $440,000 for 2006 and $300,000 for 2005. On a BOE
basis, general and administrative costs were $2.45 per BOE in 2006 compared to $3.16 per BOE in
2005, while public reporting costs were $2.15 per BOE and $2.14 per BOE for the same period.
General and administrative expenses will increase in 2006 in association with reporting
requirements and operational support.
Depreciation, depletion and amortization expense increased 88% or $2.0 million for 2006
compared to 2005. Depletion per BOE was $9.26 for 2006 and $7.43 for 2005. This increase is
attributable to increased drilling costs and producing property purchases. Depletion costs are
highly correlated with production volumes and capital expenditures. Fiscal year 2006 depletion
costs will increase with increased production volumes.
Other income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31, |
|
|
Increase |
|
|
% Increase |
|
|
|
2006 |
|
|
2005 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
(dollars in thousands) |
|
Change in fair market value of derivatives |
|
$ |
(4,714 |
) |
|
$ |
(17,633 |
) |
|
$ |
(12,919 |
) |
|
|
(73 |
)% |
Gain (loss) on ineffective portion of hedges |
|
|
143 |
|
|
|
(710 |
) |
|
|
853 |
|
|
|
120 |
% |
Interest and other income |
|
|
68 |
|
|
|
19 |
|
|
|
49 |
|
|
|
258 |
% |
Interest expense |
|
|
(2,441 |
) |
|
|
(1,173 |
) |
|
|
1,268 |
|
|
|
108 |
% |
Other expense |
|
|
(29 |
) |
|
|
(1 |
) |
|
|
28 |
|
|
|
2800 |
% |
Equity loss in Westfork Pipeline Company LP |
|
|
(19 |
) |
|
|
(79 |
) |
|
|
(60 |
) |
|
|
(76 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(6,992 |
) |
|
$ |
(19,577 |
) |
|
|
(12,585 |
) |
|
|
(64 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The loss associated with the ineffective portion of our cash flow hedges decreased
$853,000 to a gain of $143,000 for 2006 compared to 2005. Commodity prices continued to increase
into the first quarter of 2006. The spread between sweet and sour crude narrowed for the first
quarter of 2006 as compared to the same period of 2005 resulting in a decreased ineffectiveness.
The actual gain or loss may increase or decrease until settlement of these contracts. Interest
expense increased with the increase of debt from approximately $50.0 million at March 31, 2005 to
$141.5 million at March 31, 2006 along with an increase of our loan interest rate for 2006.
Overhead expenses related to our equity investment in the construction phase of the Westfork
Pipeline Companies, resulted in a loss for the first quarter of $19,000 and $79,000, respectively,
for 2006 and 2005.
Income tax expense was $838,000 in 2006 compared to a benefit of $5.5 million in 2005. Income
tax expense for 2006 will be dependent on our earnings and is expected to be approximately 34% of
income before income taxes.
We had basic net income per share of $0.05 and net loss of $0.38 and diluted net income per
share of $0.05 and net loss of $0.38 for 2006 and 2005, respectively. Basic weighted average
common shares outstanding increased from 28.7 million shares in 2005 to 34.9 million shares in
2006. The increase in common shares is due to the redeemed preferred shares to common shares in
June, 2005 and our sale of common stock in February 2005. The stock options and the convertible
preferred stock outstanding were not included in the computation of diluted net earnings (loss) per
share for the first quarter 2005 because we had a net loss and the effect would be antidilutive.
(22)
LIQUIDITY AND CAPITAL RESOURCES
Our capital resources consist primarily of cash flows from our oil and natural gas properties
and bank borrowings supported by our oil and natural 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 decreased approximately $4.3 million as of March 31, 2006 compared with
December 31, 2005. Current liabilities exceeded current assets by $3.9 million at March 31, 2006.
The working capital decrease was due to the increased current maturity of derivative obligations of
approximately $2.0 million and increased payables associated with our accelerated drilling program
for 2006.
We incurred net property costs of $55.0 million for the three months ended March 31, 2006
compared to $8.6 million for the same period in 2005. The increase is primarily related to our
accelerated budget. Our property expenditures for the first quarter of 2006 were partially offset
by restricted cash utilized for property purchases. Included in our increased property basis for
the first quarter of 2006 and 2005 were net asset retirement costs of approximately $1.7 million
and ($46,000), respectively (see Note 9 to Consolidated Financial Statements). Our property
leasehold acquisition, development and enhancement activities were financed by our revolving credit
facility, the utilization of cash flows provided by operations, cash on hand and bank borrowings.
Stockholders equity is $92.9 million for March 31, 2006 compared to $89.5 million at December
31, 2005, an increase of 4%. The increase is primarily attributable to a reduction in accumulated
comprehensive loss of $900,000 related to our derivative instruments (see Note 7 to Consolidated
Financial Statements) and net income of $1.6 million.
Based on our projected oil and natural 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.
We continually review and consider alternative methods of financing.
Bank Borrowings
We have two separate credit facilities. Our Third Amended and Restated Credit Agreement (or
the Revolving Credit Agreement), dated as of December 23, 2005, with a group of bank lenders
provides a revolving line of credit having a borrowing base limitation of $125.0 million at March
31, 2006. The total amount that we can borrow and have outstanding at any one time is limited to
the lesser of $350.0 million or the borrowing base established by the lenders. At March 31, 2006,
the principal amount outstanding under our revolving credit facility was $91.5 million, excluding
$490,000 reserved for our letters of credit. The second credit facility is a five year term loan
facility provided to us under a Second Lien Term Loan Agreement (the Second Lien Agreement),
dated as of November 15, 2005, with a group of banks and other lenders. At March 31, 2006, our term
loan under this facility was fully funded in the principal amount of $50.0 million, which was
outstanding on that same date.
Revolving Credit Facility
The Revolving Credit Agreement provides for a credit facility that allows us to borrow, repay
and reborrow amounts available under the revolving credit facility. The amount of the borrowing
base is based primarily upon the estimated value of our oil and natural gas reserves. The borrowing
base amount is redetermined by the lenders semi-annually on or about April 1 and October 1 of each
year or at other times required by the lenders or at our request. If, as a result of the lenders
redetermination of the borrowing base, the outstanding principal amount of our loans exceeds the
borrowing base, we must
(23)
either provide additional collateral to the lenders or repay the
outstanding principal of our loans in an
amount equal to the excess. Except for the principal payments that may be required because of
our outstanding loans being in excess of the borrowing base, interest only is payable monthly.
Loans made to us under this revolving credit facility bear interest at the base rate of
Citibank, N.A. or the LIBOR rate, at our election. Generally, Citibanks base rate is equal to its
prime rate as announced from time to time by Citibank.
The LIBOR rate is generally equal to the sum of (a) the rate designated as British Bankers
Association Interest Settlement Rates and offered on one, two, three, six or twelve month interest
periods for deposits of $1.0 million, and (b) a margin ranging from 2.00% to 2.50%, depending upon
the outstanding principal amount of the loans. If the principal amount outstanding is equal to or
greater than 75% of the borrowing base, the margin is 2.50%. If the principal amount outstanding is
equal to or greater than 50%, but less than 75% of the borrowing base, the margin is 2.25%. If the
principal amount outstanding is less than 50% of the borrowing base, the margin is 2.00%.
The interest rate we are required to pay on our borrowings, including the applicable margin,
may never be less than 5.00%. At March 31, 2006, our weighted average base and LIBOR rates, plus
margin, were 6.61% on $91.5 million.
In the case of base rate loans, interest is payable on the last day of each month. In the case
of LIBOR loans, interest is payable on the last day of each applicable interest period.
If the total outstanding borrowings under the revolving credit facility are less than the
borrowing base, an unused commitment fee is required to be paid to the lenders. The amount of the
fee is .25% of the daily average of the unadvanced amount of the borrowing base. The fee is payable
quarterly.
If the borrowing base is increased, we are required to pay a fee of .375% on the amount of any
increase in the borrowing base.
All outstanding principal under the revolving credit facility is due and payable on October
31, 2010. The maturity date of our outstanding loans may be accelerated by the lenders upon the
occurrence of an event of default under the Revolving Credit Agreement.
As of March 31, 2006, we were in compliance with our debt covenants.
Second Lien Term Loan Facility
The Second Lien Agreement provides a $50.0 million term loan. Loans made to us under this
credit facility bear interest at an alternate base rate or the LIBOR rate, at our election. The
alternate base rate is the greater of (a) the prime rate in effect on such day and (b) the Federal
Funds Effective Rate in effect on such day plus 1/2 of 1%, plus a margin of 3.50% per annum.
The LIBOR rate is generally equal to the sum of a (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) an applicable margin rate per annum equal to 4.50%.
At March 31, 2006, our Libor interest rate, plus the applicable margin, was 9.5% on $50.0
million.
In the case of alternate base rate loans, interest is payable the last day of each March,
June, September and December. In the case of LIBOR loans, interest is payable the last day of the
tranche period not to exceed a three month period.
(24)
All outstanding principal under the Second Lien Agreement is due and payable on November 15,
2010. The maturity date may be accelerated by the lenders upon the occurrence of an event of
default under the Second Lien Agreement.
Prepayments in whole or in part if made prior to the first anniversary date will bear a
premium of 1% of the amount prepaid. There is no premium after the first anniversary date.
As of March 31, 2006 we were in compliance with our debt covenants.
Interest expense for the three months ending March 31, 2006, for both facilities, was
approximately $2.5 million not including approximately $97,000 for interest capitalized associated
with drilling projects.
Preferred Stock
On June 6, 2005, outstanding shares of Parallels 6% Convertible Preferred Stock, $0.10 par
value per share, were converted to common stock. Under terms of the preferred stock, all of the
holders of the preferred stock elected to convert their shares into shares of Parallel common stock
based on a conversion rate of $10.00 divided by $3.50. The holders of the preferred stock received
approximately 2.8571 shares of common stock of Parallel for each share of preferred stock.
Dividends on the preferred stock ceased to accrue, and as of June 6, 2005 the preferred stock was
no longer outstanding.
Sale of Equity Securities
On February 9, 2005, we sold 5,750,000 shares of our common stock, $.01 par value per share,
pursuant to a public offering at a price of $5.27 per share. Gross cash proceeds were $30.3
million, and net proceeds were approximately $28.0 million. The common shares were issued under
Parallels $100.0 million Universal Shelf Registration Statement on Form S-3 which became effective
in November 2004. The proceeds were used to reduce the revolving credit facility.
Commodity Price Risk Management Transactions and Effects of Derivative Instruments
The purpose of all of our derivative trades is to provide a measure of stability in cash flow
as a result of our daily activities associated with the selling of oil and natural gas production
and expenditures associated with the borrowings that we have secured through our Bank Borrowings.
The derivative trade arrangements we have employed include collars, costless collars, floors or
purchased puts, oil and natural gas swaps and interest rate swaps. In 2003, we designated our
derivative trades as cash flow hedges under the provisions of SFAS 133, as amended. Although our
purpose for entering into derivative trades has remained the same, contracts entered into after
June 30, 2004 were not designated as cash flow hedges.
Under cash flow hedge accounting for oil and natural gas production, the quarterly effective
portion of the change in fair value of the commodity derivatives is recorded in stockholders
equity as other comprehensive income (loss) and then transferred to revenue in the period the
related oil and natural gas production is sold. Ineffective portions of cash flow hedges (changes
in the fair value of derivative instruments due to changes in realized prices that do not match the
changes in the hedge price) are recognized in gain (loss) on ineffective portion of hedges as they
occur. While the cash flow hedge contract is open, the ineffective gain or loss may increase or
decrease until settlement of the contract. As of March 31, 2006, we had designated as cash flow
hedges of 750 Bbls per day of production from April 1, 2006 through December 20, 2006. All other
commodity derivative trades are accounted for by mark-to-market accounting whereby changes in
fair value are charged to earnings. Changes in the fair value of derivatives are recorded in our
Consolidated Statements of Operations as these changes occur in the
(25)
Other income (expense), net
section of this statement. To the extent these trades relate to production in 2006 and beyond and
oil prices increase, we report a loss currently, but if there is no further change in prices, our
net earnings will be correspondingly higher (than if there had been no price increase) when the
production is sold.
Under cash flow hedge accounting for interest rates, the quarterly change in the fair value of
the derivative is recorded in stockholders equity as other comprehensive income (loss). The gain
or loss is transferred, on a contract by contract basis, to interest expense as the interest
accrues. Ineffective portions of cash flow hedges are recognized in other expense as they occur.
As of March 31, 2006, the floating interest rate on $10.0 million of the Bank Borrowings in 2006
was hedged. All other interest rate swaps that have been entered into are accounted for by
mark-to-market accounting as prescribed by SFAS 133.
We are exposed to credit risk in the event of nonperformance by the counterparty in our
derivative trade 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.
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 as of March 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Obligation Due in Period |
|
|
|
Periods ended December 31, |
|
|
After |
|
|
|
|
Contractual Cash Obligations |
|
2006 |
|
|
2007 |
|
|
2008 |
|
|
2009 |
|
|
2010 |
|
|
5 years |
|
|
Total |
|
|
|
(in thousands) |
|
|
|
|
|
|
|
|
|
Revolving Credit Facility (secured)(1) |
|
$ |
4,557 |
|
|
$ |
6,048 |
|
|
$ |
6,065 |
|
|
$ |
6,048 |
|
|
$ |
96,537 |
|
|
$ |
|
|
|
$ |
119,255 |
|
Second Lien Term Loan Agreement(2) |
|
|
3,579 |
|
|
|
4,750 |
|
|
|
4,763 |
|
|
|
4,750 |
|
|
|
54,151 |
|
|
|
|
|
|
|
71,993 |
|
Office Lease (Dinero Plaza) |
|
|
145 |
|
|
|
204 |
|
|
|
210 |
|
|
|
216 |
|
|
|
36 |
|
|
|
|
|
|
|
811 |
|
Andrews and Snyder Field Offices(3) |
|
|
17 |
|
|
|
23 |
|
|
|
14 |
|
|
|
14 |
|
|
|
14 |
|
|
|
|
|
|
|
82 |
|
Asset retirement obligations(4) |
|
|
305 |
|
|
|
80 |
|
|
|
58 |
|
|
|
246 |
|
|
|
555 |
|
|
|
3,035 |
|
|
|
4,279 |
|
Derivative Obligations |
|
|
14,736 |
|
|
|
15,921 |
|
|
|
13,920 |
|
|
|
207 |
|
|
|
175 |
|
|
|
|
|
|
|
44,959 |
|
Drilling Contract |
|
|
672 |
|
|
|
613 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,285 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
24,011 |
|
|
$ |
27,639 |
|
|
$ |
25,030 |
|
|
$ |
11,481 |
|
|
$ |
151,468 |
|
|
$ |
3,035 |
|
|
$ |
242,664 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Outstanding principal of $91.5 million due October 31, 2010 and estimated interest obligation calculated using the
weighted average rate at March 31, 2006 of 6.61% |
|
(2) |
|
Outstanding principal of $50.0 million due November 15, 2010 and estimated interest obligation calculated using the
rate at March 31, 2006 of 9.50% |
|
(3) |
|
The Snyder field office lease remains in effect until the termination of our trade agreement with a third party working
owner in the Diamond M project. The Andrews field office lease expires in December 2007. The lease cost for these
office facilities are billed to nonaffiliated third party working interest owners under our joint operating agreements
with these third parties. |
|
(4) |
|
Assets retirement obligations of oil and natural gas assets, excluding salvage value and accretion. |
(26)
Outlook
The oil and natural gas industry is capital intensive. We make, and anticipate that we will
continue to make, substantial capital expenditures in the exploration for, development and
acquisition of oil and natural gas reserves. Historically, our capital expenditures have been
financed primarily with:
|
|
|
internally generated cash from operations; |
|
|
|
|
proceeds from bank borrowings; and |
|
|
|
|
proceeds from sales of equity securities. |
The continued availability of these capital sources depends upon a number of variables,
including:
|
|
|
our proved reserves; |
|
|
|
|
the volumes of oil and natural gas we produce from existing wells; |
|
|
|
|
the prices at which we sell oil and natural gas; and |
|
|
|
|
our ability to acquire, locate and produce new reserves. |
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 Parallels securities; |
|
|
|
|
sales of non-core properties; or |
|
|
|
|
other forms of financing. |
Except for the revolving credit facility we have with our bank lenders, 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.
Inflation
Our drilling costs have escalated and we would expect this trend to continue, but our
commodity prices have also increased at the same time.
Critical Accounting Policies
This discussion should be read in conjunction with the financial statements and the
accompanying notes and Managements Discussion and Analysis of Financial Condition and Results of
Operations
(27)
included in our Annual Report or Form 10-K for the year ended December 31, 2005, filed with the
Securities and Exchange Commission on March 16, 2006.
TRENDS AND PRICES
Changes in oil and natural gas prices significantly affect our revenues, cash flows and
borrowing capacity. Markets for oil and natural gas have historically been, and will continue to
be, volatile. Prices for oil and natural gas typically fluctuate in response to relatively minor
changes in supply and demand, market uncertainty, seasonal, political and other factors beyond our
control. We are unable to accurately predict domestic or worldwide political events or the effects
of other such factors on the prices we receive for our oil and natural gas.
Our capital expenditure budgets are highly dependent on future oil and natural gas prices and
will be consistent with internally generated cash flows.
During fiscal year 2005 the average realized sales price for our oil and natural gas was
$51.57 (unhedged) per BOE. For the three months ended March 31, 2006, our average realized price
was $50.27 (unhedged) per BOE.
FORWARD-LOOKING STATEMENTS
Cautionary Statement Regarding Forward-Looking Statements
Some statements contained in this Quarterly Report on Form 10-Q are forward-looking
statements. These forward looking statements relate to, among others, the following:
|
|
|
our future financial and operating performance and results; |
|
|
|
|
the drilling plans and ability to secure drilling rigs to effectuate plans; |
|
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|
|
production volumes; |
|
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|
our business strategy; |
|
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|
|
market prices; |
|
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|
|
sources of funds necessary to conduct operations and complete acquisitions; |
|
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|
|
development costs; |
|
|
|
|
number and location of planned wells; |
|
|
|
|
our future commodity price risk management activities; and |
|
|
|
|
our plans and forecasts. |
We have based these forward-looking statements on our current assumptions, expectations and
projections about future events.
(28)
We use the words may, will, expect, anticipate, estimate, believe, continue,
intend, plan, budget, present value, future or reserves or other similar words to
identify forward-looking statements. These statements also involve risks and uncertainties that
could cause our actual results or financial condition to materially differ for our expectations.
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 natural gas; |
|
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|
|
dependent on key personnel; |
|
|
|
|
reliance on technological development and technology development programs; |
|
|
|
|
demand for oil and natural gas; |
|
|
|
|
losses due to potential or future litigation; |
|
|
|
|
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 and liability for environmental matters; |
|
|
|
|
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 believe it is important to communicate our expectations of future performance to our
investors. However, events may occur in the future that we are unable to accurately predict, or
over which we have no control. We caution you against putting undue reliance on forward-looking
statements or projecting any future results based on such statements.
(29)
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 under Risks Related to Our
Business beginning on page 19 of our Form 10-K for the year ended December 31, 2005.
ITEM 3. 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 March 31, 2006, 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 March 31, 2006
Our only financial instruments sensitive to changes in interest rates are our bank debt and
interest rate swaps. As the interest rate is variable and reflects current market conditions, the
carrying value of our bank debt 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 March, 2006.
You should read Note 3 to the Consolidated Financial Statements for further discussion of our debt
that is sensitive to interest rates.
|
|
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|
|
|
|
|
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2007 |
|
2008 |
|
2009 |
|
2010 |
|
Total |
|
|
(in thousands, except interest rates) |
Revolving Facility (secured) |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
91,500 |
|
|
$ |
91,500 |
|
Average interest rate |
|
|
6.61 |
% |
|
|
6.61 |
% |
|
|
6.61 |
% |
|
|
6.61 |
% |
|
|
6.61 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Term Loan (Second Lien) |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
50,000 |
|
|
$ |
50,000 |
|
Average interest rate |
|
|
9.50 |
% |
|
|
9.50 |
% |
|
|
9.50 |
% |
|
|
9.50 |
% |
|
|
9.50 |
% |
|
|
|
|
At March 31, 2006, we had bank loans in the amount of approximately $91.5 million
outstanding on our revolving credit facility at a weighted average interest rate of 6.61% and
approximately $50.0 million outstanding on our term loan at an interest rate of 9.5%. Under our
revolving credit facility, we may elect an interest rate based upon the agent banks base lending
rate or the LIBOR rate, plus a margin ranging from 2.25% to 2.75% per annum, 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 5.00%.
As of March 31, 2006, we employed fixed interest rate swap contracts with BNP Paribas, based
on the 90-day LIBOR rates at the time of the contract. These interest rate swaps are treated as a
cash flow hedge as defined in SFAS 133, and are on $10.0 million of our variable rate debt for all
of 2006. We will continue to pay the variable interest rates for this portion of our Bank
Borrowings, but due to the interest rate swaps, we have fixed the rate at 4.05%. Under the terms
of these contracts, in periods during which the fixed interest rate stated in the agreement exceeds
the variable rate (which is based on the 90-day LIBOR rate), we pay to the counterparty an amount
determined by applying this excess fixed rate to the notional amount of the contract. In periods
when the variable rate exceeds the fixed rate stated in the respective swap contract, the
counterparty pays an amount to us determined by applying the excess of the variable rate over the
stated fixed rate. As of March 31, 2006, the fair market value of these interest rate swaps was a
gain of $78,000.
As of March 31, 2006, we had also employed additional fixed interest rate swap contracts with
BNP Paribas and Citibank, N.A. based on the 90-day LIBOR rates at the time of the contracts.
However, these contracts are accounted for by mark-to-market accounting as prescribed in SFAS
133. Nonetheless, we view these contracts as additional protection against future interest rate
volatility.
(30)
A recap for the period of time, notional amounts, fixed interest rates, and fair market value
of these contracts at March 31, 2006 follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional |
|
|
|
|
|
Fair |
Period of Time |
|
|
Amounts |
|
Fixed Interest Rates |
|
Market Value |
|
|
|
($ in millions) |
|
|
|
|
|
($ in thousands) |
April 1, 2006 thru December 31, 2006(1) |
|
|
$ |
10 |
|
|
|
4.05 |
% |
|
|
78 |
|
April 1, 2006 thru December 31, 2006 |
|
|
$ |
90 |
|
|
|
4.41 |
% |
|
|
480 |
|
January 1, 2007 thru December 31, 2007 |
|
|
$ |
100 |
|
|
|
4.62 |
% |
|
|
534 |
|
January 1, 2008 thru December 31, 2008 |
|
|
$ |
100 |
|
|
|
4.86 |
% |
|
|
264 |
|
January 1, 2009 thru December 31, 2009 |
|
|
$ |
50 |
|
|
|
5.06 |
% |
|
|
64 |
|
January 1, 2010 thru October 31, 2010 |
|
|
$ |
50 |
|
|
|
5.15 |
% |
|
|
38 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
|
$ |
1,458 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Designated as cash flow hedge. |
Commodity Price Sensitivity as of March 31, 2006
Our major market risk exposure is in the pricing applicable to our oil and natural gas
production. Market risk refers to the risk of loss from adverse changes in oil and natural gas
prices. Realized pricing is primarily driven by the prevailing domestic price for crude oil and
spot prices applicable to the region in which we produce natural gas. Historically, prices
received for oil and natural gas production have been volatile and unpredictable. We expect
pricing volatility to continue. Oil prices ranged from a low of $36.43 per barrel to a high of
$65.63 per barrel during 2005. Natural gas prices we received during 2005 ranged from a low of
$2.22 per Mcf to a high of $15.43 per Mcf. During the first quarter ended March 31, 2006 oil
prices ranged from a low of $51.65 to a high of $66.18. Natural gas prices we received during the
first quarter ended March 31, 2006 ranged from a low of $2.87 per Mcf to a high of $15.11 per Mcf.
A significant decline in the prices of oil or natural gas could have a material adverse effect on
our financial condition and results of operations.
We employ various derivative instruments in order to minimize our exposure to the
aforementioned commodity price volatility. As of March 31, 2006, we had employed costless collars,
collars, and swaps in order to protect against this price volatility. Although all of the
contracts that we have entered into are viewed as protection against this price volatility, all but
two of these contracts are accounted for by the mark-to-market accounting method as prescribed in
SFAS 133.
As of March 31, 2006, we had commodity swap contracts designated as cash flow hedges totaling
750 Bbls per day from January 1, 2006 through December 20, 2006 at a NYMEX swap price of $23.04 per
Bbl.
A description of our active commodity derivative contracts as of March 31, 2006 follows:
Put Options. In 2005 we purchased put options or floors on volumes of 3,000 MMBtu
per day for a total of 642,000 MMBtu during the seven month period from April 1, 2006 through
October 31, 2006 at an average floor price of $7.17 per MMBtu for a total consideration of
approximately $230,000. The puts have fair market value of $514,000 as of March 31, 2006.
(31)
Collars. Collars are contracts which combine both a put option or floor and a call
option or ceiling. These contracts may or may not involve payment or receipt of cash at
inception, depending on the ceiling and floor pricing.
A summary of our collar positions at March 31, 2006 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Houston Ship |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Channel Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
Ny Mex Oil Prices |
|
|
|
|
|
|
Prices |
|
|
WAHA Gas Prices |
|
|
Fair |
|
|
|
Barrels of |
|
|
|
|
|
|
|
|
|
|
M M Btu of |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market |
|
Period of Time |
|
Oil |
|
|
Floor |
|
|
Cap |
|
|
Natural Gas |
|
|
Floor |
|
|
Cap |
|
|
Floor |
|
|
Cap |
|
|
Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
|
April 1,
2006 thru
December 31,
2006 |
|
|
217,800 |
|
|
$ |
48.26 |
|
|
$ |
75.91 |
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(1,342 |
) |
April 1,
2006 thru
October 31,
2006 |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
|
428,000 |
|
|
$ |
7.50 |
|
|
$ |
13.90 |
|
|
$ |
|
|
|
$ |
|
|
|
|
442 |
|
April 1,
2006 thru
October 31,
2006 |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
|
214,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
9.00 |
|
|
$ |
14.55 |
|
|
|
546 |
|
January 1,
2007 thru
December 31,
2007 |
|
|
219,000 |
|
|
$ |
52.50 |
|
|
$ |
83.00 |
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
(276 |
) |
April 1,
2007 thru
October 31,
2007 |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
|
214,000 |
|
|
$ |
6.00 |
|
|
$ |
11.05 |
|
|
$ |
|
|
|
$ |
|
|
|
|
(100 |
) |
January 1,
2008 thru
December 31,
2008 |
|
|
109,800 |
|
|
$ |
55.00 |
|
|
$ |
76.50 |
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
(196 |
) |
January 1,
2009 thru
December 31,
2009 |
|
|
91,250 |
|
|
$ |
55.00 |
|
|
$ |
73.00 |
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
(207 |
) |
January 1,
2010 thru
December 31,
2010 |
|
|
76,000 |
|
|
$ |
55.00 |
|
|
$ |
71.00 |
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
(176 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(1,309 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Swaps. Generally, swaps are an agreement to buy or sell a specified
commodity for delivery in the future, at an agreed fixed price. Swap transactions convert a
floating or market price into a fixed price. For any particular swap transaction, the counterparty
is required to make a payment to the Company if the reference price for any settlement period is
less than the swap or fixed price for such contract, and the Company is required to make a payment
to the counterparty if the reference price for any settlement period is greater than the swap or
fixed price for such contract.
We have entered into oil swap contracts with BNP Paribas. A recap for the period of time,
number of barrels, swap prices and fair market values as of March 31, 2006 for these swaps follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nymex Oil |
|
|
Fair Market |
|
Period of Time |
|
|
Barrels of Oil |
|
|
Swap Price |
|
|
Value |
|
|
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
|
April 1, 2006 thru December 20, 2006(1) |
|
|
|
198,000 |
|
|
$ |
23.04 |
|
|
$ |
(8,903 |
) |
April 1, 2006 thru December 31, 2006 |
|
|
|
137,500 |
|
|
$ |
36.35 |
|
|
|
(4,391 |
) |
January 1, 2007 thru December 31, 2007 |
|
|
|
474,500 |
|
|
$ |
34.36 |
|
|
|
(15,645 |
) |
January 1, 2008 thru December 31, 2008 |
|
|
|
439,200 |
|
|
$ |
33.37 |
|
|
|
(13,723 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total fair market value |
|
|
|
|
|
|
|
|
|
|
$ |
(42,662 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Designated as a cash flow hedge. |
(32)
ITEM 4. CONTROLS AND PROCEDURES
As part of the preparation of our financial statements for the year ended December 31, 2005,
we undertook a review of our accounting for oil and natural gas and interest rate derivatives. We
use derivative instruments as a means of reducing financial exposure to fluctuating oil and natural
gas prices and interest rates. We included changes from period to period in the fair value of
derivatives designated by management as cash flow hedges (Hedges) as increases or decreases to
Accumulated Other Comprehensive Income (AOCI) as allowed by Statement of Financial Accounting
Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (FAS 133).
This Hedge accounting treatment is allowed for certain derivatives, including the types of
derivatives used by us to reduce exposure to changes in oil and natural gas prices associated with
the sale of oil and natural gas production and fluctuations in interest rates. In order to qualify
for Hedge accounting treatment, specific standards and documentation requirements must be met at
the inception of the derivative. We believed that we met those standards and requirements and that
our Hedge accounting treatment was permitted under FAS 133. However, after a review of FAS 133 and
our underlying documentation related to our derivative instruments designated as Hedges, we
determined that certain of our derivative instruments did not qualify for Hedge accounting
treatment under FAS 133. Specifically, we determined that documentation of the relationship of
hedged items and the derivative instruments being employed and designated as Hedges was
insufficient for derivative instruments entered into during periods subsequent to June 30, 2004;
and, that accounting for derivative instruments entered into during periods subsequent to June 30,
2004 as cash flow Hedges was, therefore, inappropriate. Accordingly, we restated our consolidated
financial statements for the year ended December 31, 2004, the quarters ended March 31, June 30 and
September 30, 2005, and the quarters ended September 30 and December 31, 2004 to account for the
derivative instruments as non-hedging derivatives. Management concluded, based on the circumstances
involving the restatement of the aforementioned financial statements that as of December 31, 2005,
a material weakness in internal controls over financial reporting existed with respect to the
design of the Companys controls over the proper recording and disclosure of derivative instruments
in accordance with FAS 133.
During the first quarter of 2006, and after reassessing and further evaluating our internal
controls over financial reporting related to the initiating and recording of our derivative
transactions, managements corrective actions to date include changing our accounting for all of
our existing derivative instruments that do not qualify for Hedge accounting treatment to the
mark-to-market accounting treatment prescribed by FAS 133. In addition, management has
determined that future derivative transactions will be accounted for using mark-to-market
accounting. Under FAS 133, the mark-to-market accounting treatment should be utilized for
derivative instruments that do not qualify for Hedge accounting treatment.
As of the end of the period covered by this Quarterly Report on Form 10-Q, the effectiveness
of our disclosure controls and procedures was evaluated by our management, with the participation
of our Chief Executive Officer, Larry C. Oldham (principal executive officer), and our Chief
Financial Officer, Steven D. Foster (principal financial officer), in accordance with Rules of the
Securities Exchange Act of 1934. Based on that evaluation, Mr. Oldham and Mr. Foster have
concluded that our disclosure controls and procedures were effective as of March 31, 2006 to
provide reasonable assurance that information required to be disclosed in our reports filed or
submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported
within the time periods specified in the SECs rules and forms.
Except as described in this ITEM 4, there has been no change in our internal controls over
financial reporting that occurred during the three months ended March 31, 2006 that has materially
affected, or is reasonably likely to materially affect, our internal controls over financial
reporting.
(33)
PART II OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
On December 30, 2005, we were named as a defendant in a lawsuit filed in the 352nd Judicial
District Court of Tarrant County, Texas, Cause No. 352-215616-05, AFE Oil and Gas, L.L.C. (aka AFE
Oil and Gas, LLC) v. Premium Resources II, L.P., Premium Resources, Inc., Danay Covert, Nick
Morris, William D. Middleton, Dale Resources, L.L.C., and Parallel Petroleum, Inc.
In this suit, the plaintiff alleges breach of fiduciary duty, fraud and conspiracy to defraud,
breach of contract, constructive trust, suit to remove cloud from title, declaratory judgment,
alter ego, and statutory fraud and seeks recovery of an unspecified amount of actual damages,
special damages, consequential damages, exemplary damages, attorneys fees, pre-judgment and
post-judgment interest and costs. Generally, the plaintiff alleges that it owns a 5.5% overriding
royalty interest in certain oil and gas properties known as the Square Top LP and the West Fork
LP leases located in Tarrant County, Texas. The plaintiff alleges that the defendants (other than
Dale Resources and Parallel) wrongfully and intentionally allowed these original oil and gas leases
to terminate, causing the termination of plaintiffs overriding royalty interest in each lease. The
plaintiff further alleges that the defendants (other than Dale Resources and Parallel) failed to
drill wells necessary to maintain the original leases in force and that after the original leases
were allowed to terminate, the defendants (other than Dale Resources and Parallel) then acquired
new oil and gas leases covering these same oil and gas properties, which were subsequently assigned
to Dale Resources. Thereafter, Dale Resources allegedly assigned a portion of these new leases to
Parallel.
In addition to seeking unspecified monetary damages, the plaintiff also seeks to impose a
constructive trust for its benefit on the new oil and natural gas leases and seeks a judicial
declaration that either (1) the plaintiff is the owner of an overriding royalty interest in the new
leases or that (2) the original leases and plaintiffs interest in the original leases are still in
effect. The plaintiff also claims that the new leases constitute a cloud on plaintiffs title and
seeks to have that cloud removed. Based on our present understanding of this case, we believe that
we have substantial defenses to the plaintiffs claims and intend to vigorously assert these
defenses. However, if the plaintiff is awarded an interest in the new leases, we could potentially
become liable for the payment to plaintiff of the portion of production proceeds attributable to
plaintiffs interest received by us. On the other hand, if the plaintiff prevails on its claim that
the original leases are still in effect, our interest in the new leases could become subject to
forfeiture. Based on the information known to date, we have not established a reserve for this
matter.
From time to time, we are party to ordinary routine litigation incidental to our business. We
are currently a defendant in one other lawsuit. We do not believe the ultimate outcome of this
lawsuit will have a material adverse effect on our financial condition or results of options. We
are not aware of any other threatened litigation and we have not been a party to any bankruptcy,
receivership, reorganization, adjustment or similar proceeding.
ITEM 1A. RISK FACTORS
There have been no material changes from the risk factors as previously disclosed in our Form
10-K Report for the fiscal year ended December 31, 2005.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
In
November 2001, we engaged Stonington Corporation for the purpose of obtaining general
corporate financial advisory services and financial advisory services in the placement of debt or
equity securities. Under our agreement with Stonington, we issued to Stonington warrants to
purchase an
(34)
aggregate of 275,000 shares of our common stock. The warrants were issued at an initial exercise
price of $2.95 per share, the fair market value of the common stock at the date of issuance, and
are exercisable during the four-year period commencing one year after the initial issuance of the
warrants. The warrants were issued as partial payment for services rendered for financial and
investment advice provided by Stonington. The warrants expire on November 20, 2006 and grant
certain rights of registration for the common stock issuable upon exercise of the warrants. The
warrants contain customary antidilution provisions so as to avoid dilution of the equity interests
represented by the underlying common stock upon the occurrence of certain events such as share
dividends and splits. In the event of liquidation, dissolution or winding up of Parallel, holders
of the warrants are not entitled to participate in the assets of Parallel. The warrants have no
voting rights. After giving effect to certain adjustments under the antidilution provisions of the
warrants, the aggregate number of shares of common stock initially issuable upon exercise price of
the warrants was increased to 285,561 shares and the initial exercise price was reduced to $2.84
per share. The warrants were issued in a transaction not involving a public offering and were
issued in reliance upon the exemption from registration under Section 4(2) of the Securities Act of
1933, as amended.
The warrants may be exercised in whole or in part at any time during the period from November
20, 2002 to November 20, 2006 by payment in cash of an amount determined by multiplying the
exercise price by the number of shares of common stock as to which the warrants are being
exercised. The warrants also contain a net exercise provision entitling the holder of the
warrants to exercise the warrants by receiving shares of common stock equal to the value of the
warrants being surrendered for exercise. Utilizing this net exercise feature, on March 30, 2006,
Stonington surrendered 41,521 warrants for exercise and received 35,129 shares of common stock. No
cash proceeds were received by Parallel. The common stock was issued in reliance upon the
exemptions from registration contained in Section 3(a)(9) and Section 4(2) of the Securities Act.
ITEM 6. EXHIBITS
(a) Exhibits
The following exhibits are filed herewith or incorporated by reference, as indicated:
|
|
|
No. |
|
Description of Exhibit |
3.1
|
|
Certificate of Incorporation of Registrant (Incorporated by reference to Exhibit 3.1 to Form
10-Q of the Registrant for the fiscal quarter ended June 30, 2004) |
|
|
|
3.2
|
|
Bylaws of Registrant (Incorporated by reference to Exhibit 3 of the Registrants Form 8-K,
dated October 9, 2000, as filed with the Securities and Exchange Commission on October 10,
2000) |
|
|
|
3.3
|
|
Certificate of Formation of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.3 of
the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004) |
|
|
|
3.4
|
|
Limited Liability Company Agreement of Parallel, L.L.C. (Incorporated by reference to Exhibit
No. 3.4 of the Registrants Statement on Form S-3, No. 333-119725 filed on October 13, 2004) |
|
|
|
3.5
|
|
Certificate of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit
No. 3.5 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on
October 13, 2004) |
|
|
|
3.6
|
|
Agreement of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No.
3.6 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October
13, 2004) |
(35)
|
|
|
No. |
|
Description of Exhibit |
4.1
|
|
Certificate of Designations, Preferences and Rights of Serial Preferred Stock 6%
Convertible Preferred Stock (Incorporated by reference to Exhibit 4.1 of Form 10-Q of the
Registrant for the fiscal quarter ended June 30, 2004) |
|
|
|
4.2
|
|
Certificate of Designation, Preferences and Rights of Series A Preferred Stock (Incorporated
by reference to Exhibit 4.2 of Form 10-K of the Registrant for the fiscal year ended December
31, 2000) |
|
|
|
4.3
|
|
Rights Agreement, dated as of October 5, 2000, between the Registrant and Computershare Trust
Company, Inc., as Rights Agent (Incorporated by reference to Exhibit 4.3 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2000) |
|
|
|
4.4
|
|
Form of Indenture relating to senior debt securities of the Registrant (Incorporated by
reference to Exhibit No. 4.4 of the Registrants Statement on Form S-3, No. 333-119725 filed
on October 13, 2004) |
|
|
|
4.5
|
|
Form of Indenture relating to subordinated debt securities of the Registrant (Incorporated by
reference to Exhibit No. 4.5 of the Registrants Registration Statement on Form S-3, No.
333-119725 filed on October 13, 2004) |
|
|
|
4.6
|
|
Form of common stock certificate of the Registrant (Incorporated by reference to Exhibit No.
4.6 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October
13, 2004) |
|
|
|
4.7
|
|
Warrant Purchase Agreement, dated November 20, 2001, between the Registrant and Stonington
Corporation (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant for the
fiscal year ended December 31, 2004) |
|
|
|
4.8
|
|
Warrant Purchase Agreement, dated December 23, 2003, between the Registrant and Stonington
Corporation (Incorporated by reference to Exhibit 4.8 of Form 10-K of the Registrant for the
fiscal year ended December 31, 2004) |
|
|
|
|
|
Executive Compensation Plans and Arrangements (Exhibit No.s 10.1 through 10.8): |
|
|
|
10.1
|
|
1992 Stock Option Plan (Incorporated by reference to Exhibit 10.1 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2004) |
|
|
|
10.2
|
|
Merrill Lynch, Pierce, Fenner & Smith Incorporated Prototype Simplified Employee Pension Plan
(Incorporated by reference to Exhibit 10.6 of the Registrants Form 10-K for the fiscal year
ended December 31, 1995) |
|
|
|
10.3
|
|
Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.3 of the
Registrants Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2005) |
|
|
|
10.4
|
|
1998 Stock Option Plan (Incorporated by reference to Exhibit 10.7 of Form 10-K of the
Registrant for the fiscal year ended December 31, 1998) |
|
|
|
10.5
|
|
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) |
(36)
|
|
|
No. |
|
Description of Exhibit |
10.6
|
|
2001 Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.7 of
the Registrants Form 10-Q Report for the fiscal quarter ended March 31, 2004) |
|
|
|
10.7
|
|
2004 Non-Employee Director Stock Grant Plan (Incorporated by reference to Exhibit 10.1 of the
Registrants Form 8-K Report dated September 22, 2004) |
|
|
|
10.8
|
|
Incentive and Retention Plan (Incorporated by reference to Exhibit 10.1 of the Registrants
Form 8-K Report dated September 23, 2004 and filed with the Securities and Exchange Commission
on September 29, 2004) |
|
|
|
10.9
|
|
Certificate of Formation of First Permian, L.L.C. (Incorporated by reference to Exhibit 10.1
of the Registrants Form 8-K Report dated June 30, 1999) |
|
|
|
10.10
|
|
Limited Liability Company Agreement of First Permian, L.L.C. (Incorporated by reference to
Exhibit 10.2 of the Registrants Form 8-K Report dated June 30, 1999) |
|
|
|
10.11
|
|
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) |
|
|
|
10.12
|
|
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 Registrants Form 8-K Report dated June 30, 1999) |
|
|
|
10.13
|
|
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 Registrants Form 8-K Report dated June 30, 1999) |
|
|
|
10.14
|
|
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) |
|
|
|
10.15
|
|
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) |
|
|
|
10.16
|
|
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) |
|
|
|
10.17
|
|
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) |
|
|
|
10.18
|
|
Guaranty dated December 20, 2002, between Parallel, L.L.C. and First American Bank, SSB, as
Agent (Incorporated by reference to Exhibit 10.3 of Form 8-K of the Registrant, dated December
20, 2002) |
|
|
|
10.19
|
|
First Amendment to First Amended and Restated Credit Agreement, dated as of September 12,
2003, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First
American Bank, SSB, Western National Bank, and BNP Paribas (Incorporated by reference to
Exhibit 10.29 of Form 10-Q of the Registrant for the quarter ended September 30, 2003) |
(37)
|
|
|
No. |
|
Description of Exhibit |
10.20
|
|
Second Amendment and Restated Credit Agreement, dated September 27, 2004, by and among
Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB,
BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit
10.1 of the Registrants Form 8-K Report dated September 27, 2004 and filed with the
Securities and Exchange Commission on October 1, 2004) |
|
|
|
10.21
|
|
Agreement of Limited Partnership of West Fork Pipeline Company LP (Incorporated by reference
to Exhibit 10.21 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004) |
|
|
|
10.22
|
|
First Amendment to Second Amended and Restated Credit Agreement, dated as of December 27,
2004, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First
American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by
reference to Exhibit 10.1 of the Registrants Form 8-K Report dated December 30, 2004 and
filed with the Securities and Exchange Commission on December 30, 2004) |
|
|
|
10.23
|
|
Second Amendment to Second Amended and Restated Credit Agreement, dated as of April 1, 2005,
by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American
Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference
to Exhibit 10.1 of the Registrants Form 8-K Report dated April 4, 2005 and filed with the
Securities and Exchange Commission on April 8, 2005) |
|
|
|
10.24
|
|
Third Amendment to Second Amended and Restated Credit Agreement (Incorporated by reference
to Exhibit 10.1 of the Registrants Form 8-K Report dated October 4, 2005 and filed with the
Securities and Exchange Commission on October 20, 2005) |
|
|
|
10.25
|
|
Purchase and Sale Agreement, dated as of October 14, 1005, among Parallel, L.P., Lynx
Production Company, Inc., Elton Resources, Inc., Cascade Energy Corporation, Chelsea Energy,
Inc., William P. Sutter, Trustee, William P. Sutter Trust, J. Leroy Bell, E. L. Brahaney,
Brent Beck, Cavic Interests, LLC and Stanley Talbott (Incorporated by reference to Exhibit
10.2 of the Registrants Form 8-K Report dated October 14, 2005 and filed with the Securities
and Exchange Commission on October 20, 2005) |
|
|
|
10.26
|
|
Ancillary Agreement to Purchase and Sale Agreement, dated October 14, 2005, between
Parallel, L.P. and Lynx Production Company, Inc. (Incorporated by reference to Exhibit 10.3 of
the Registrants Form 8-K Report dated October 14, 2005 and filed with the Securities and
Exchange Commission on October 20, 2005) |
|
|
|
10.27
|
|
Guarantee of Parallel, L.P., dated October 13, 2004 (Incorporated by reference to Exhibit
10.4 of the Registrants Form 8-K Report dated October 14, 2005 and filed with the Securities
and Exchange Commission on October 20, 2005) |
|
|
|
10.28
|
|
ISDA Master Agreement, dated as of October 13, 2005, between Parallel, L.P. and Citibank,
N.A. (Incorporated by reference to Exhibit 10.5 of the Registrants Form 8-K Report dated
October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005) |
|
|
|
10.29
|
|
Third Amended and Restated Credit Agreement, dated as of December 23, 2005, among Parallel
Petroleum Corporation, Parallel, L.P., Parallel, L.L.C. and Citibank Texas, N.A., BNP Paribas,
CitiBank F.S.B., Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland and
Fortis Capital Corp. (Incorporated by reference to Exhibit No. 10.1 of the Registrants Form
8-K Report, dated December 23, 2005, as filed with the Securities and Exchange Commission on
December 30, 2005) |
(38)
|
|
|
No. |
|
Description of Exhibit |
10.30
|
|
Second Lien Term Loan Agreement, dated November 15, 2005, among Parallel Petroleum
Corporation, Parallel, L.P., BNP Paribas and Citibank Texas, N.A. (Incorporated by reference
to Exhibit No. 10.4 of the Registrants Form 8-K Report, dated November 15, 2005, as filed
with the Securities and Exchange Commission on November 21, 2005) |
|
|
|
10.31
|
|
Intercreditor and Subordination Agreement, dated November 15, 2005, among Citibank Texas,
N.A., BNP Paribas, Parallel Petroleum Corporation, Parallel, L.P. and Parallel, L.L.C.
(Incorporated by reference to Exhibit No. 10.5 of the Registrants Form 8-K Report, dated
November 15, 2005, as filed with the Securities and Exchange Commission on November 21, 2005) |
|
|
|
14
|
|
Code of Ethics (Incorporated by reference to Exhibit No. 14 of the Registrants Form 10-K
Report for the fiscal year ended December 31, 2003 and filed with the Securities and Exchange
Commission on March 22, 2004) |
|
|
|
21
|
|
Subsidiaries (Incorporated by reference to Exhibit No. 21 of the Registrants Form 10-K
Report for the fiscal year ended December 31, 2003 and filed with the Securities and Exchange
Commission on March 22, 2004) |
|
|
|
*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. |
(39)
SIGNATURES
Pursuant to the requirements 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.
|
|
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|
|
PARALLEL PETROLEUM CORPORATION |
|
|
|
|
|
BY: /s/ Larry C. Oldham |
|
|
|
Date: May 10, 2006
|
|
Larry C. Oldham |
|
|
President and Chief Executive Officer |
|
|
|
Date: May 10, 2006
|
|
BY: /s/ Steven D. Foster |
|
|
|
|
|
Steven D. Foster, |
|
|
Chief Financial Officer |
INDEX TO EXHIBITS
|
|
|
No. |
|
Description of Exhibit |
3.1
|
|
Certificate of Incorporation of Registrant (Incorporated by reference to Exhibit 3.1 to Form
10-Q of the Registrant for the fiscal quarter ended June 30, 2004) |
|
|
|
3.2
|
|
Bylaws of Registrant (Incorporated by reference to Exhibit 3 of the Registrants Form 8-K,
dated October 9, 2000, as filed with the Securities and Exchange Commission on October 10,
2000) |
|
|
|
3.3
|
|
Certificate of Formation of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.3 of
the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004) |
|
|
|
3.4
|
|
Limited Liability Company Agreement of Parallel, L.L.C. (Incorporated by reference to Exhibit
No. 3.4 of the Registrants Statement on Form S-3, No. 333-119725 filed on October 13, 2004) |
|
|
|
3.5
|
|
Certificate of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit
No. 3.5 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on
October 13, 2004) |
|
|
|
3.6
|
|
Agreement of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No.
3.6 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October
13, 2004) |
|
|
|
4.1
|
|
Certificate of Designations, Preferences and Rights of Serial Preferred Stock 6%
Convertible Preferred Stock (Incorporated by reference to Exhibit 4.1 of Form 10-Q of the
Registrant for the fiscal quarter ended June 30, 2004) |
|
|
|
4.2
|
|
Certificate of Designation, Preferences and Rights of Series A Preferred Stock (Incorporated
by reference to Exhibit 4.2 of
Form 10-K of the Registrant for the fiscal year ended December
31, 2000) |
|
|
|
4.3
|
|
Rights Agreement, dated as of October 5, 2000, between the Registrant and Computershare Trust
Company, Inc., as Rights Agent (Incorporated by reference to Exhibit 4.3 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2000) |
|
|
|
4.4
|
|
Form of Indenture relating to senior debt securities of the Registrant (Incorporated by
reference to Exhibit No. 4.4 of the Registrants Statement on Form S-3, No. 333-119725 filed
on October 13, 2004) |
|
|
|
4.5
|
|
Form of Indenture relating to subordinated debt securities of the Registrant (Incorporated by
reference to Exhibit No. 4.5 of the Registrants Registration Statement on Form S-3, No.
333-119725 filed on October 13, 2004) |
|
|
|
4.6
|
|
Form of common stock certificate of the Registrant (Incorporated by reference to Exhibit No.
4.6 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October
13, 2004) |
|
|
|
4.7
|
|
Warrant Purchase Agreement, dated November 20, 2001, between the Registrant and Stonington
Corporation (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant for the
fiscal year ended December 31, 2004) |
|
|
|
4.8
|
|
Warrant Purchase Agreement, dated December 23, 2003, between the Registrant and Stonington
Corporation (Incorporated by reference to Exhibit 4.8 of Form 10-K of the Registrant for the
fiscal year ended December 31, 2004) |
|
|
|
No. |
|
Description of Exhibit |
|
|
Executive Compensation Plans and Arrangements (Exhibit No.s 10.1 through 10.8): |
|
|
|
10.1
|
|
1992 Stock Option Plan (Incorporated by reference to Exhibit 10.1 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2004) |
|
|
|
10.2
|
|
Merrill Lynch, Pierce, Fenner & Smith Incorporated Prototype Simplified Employee Pension Plan
(Incorporated by reference to Exhibit 10.6 of the Registrants Form 10-K for the fiscal year
ended December 31, 1995) |
|
|
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10.3
|
|
Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.3 of the
Registrants Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2005) |
|
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10.4
|
|
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) |
|
|
|
10.5
|
|
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) |
|
|
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10.6
|
|
2001 Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.7 of
the Registrants Form 10-Q Report for the fiscal quarter ended March 31, 2004) |
|
|
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10.7
|
|
2004 Non-Employee Director Stock Grant Plan (Incorporated by reference to Exhibit 10.1 of the
Registrants Form 8-K Report dated September 22, 2004) |
|
|
|
10.8
|
|
Incentive and Retention Plan (Incorporated by reference to Exhibit 10.1 of the Registrants
Form 8-K Report dated September 23, 2004 and filed with the Securities and Exchange Commission
on September 29, 2004) |
|
|
|
10.9
|
|
Certificate of Formation of First Permian, L.L.C. (Incorporated by reference to Exhibit 10.1
of the Registrants Form 8-K Report dated June 30, 1999) |
|
|
|
10.10
|
|
Limited Liability Company Agreement of First Permian, L.L.C. (Incorporated by reference to
Exhibit 10.2 of the Registrants Form 8-K Report dated June 30, 1999) |
|
|
|
10.11
|
|
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) |
|
|
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10.12
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|
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 Registrants Form 8-K Report dated June 30, 1999) |
|
|
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10.13
|
|
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 Registrants Form 8-K Report dated June 30, 1999) |
|
|
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10.14
|
|
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) |
|
|
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10.15
|
|
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) |
|
|
|
No. |
|
Description of Exhibit |
10.16
|
|
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) |
|
|
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10.17
|
|
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) |
|
|
|
10.18
|
|
Guaranty dated December 20, 2002, between Parallel, L.L.C. and First American Bank, SSB, as
Agent (Incorporated by reference to Exhibit 10.3 of Form 8-K of the Registrant, dated December
20, 2002) |
|
|
|
10.19
|
|
First Amendment to First Amended and Restated Credit Agreement, dated as of September 12,
2003, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First
American Bank, SSB, Western National Bank, and BNP Paribas (Incorporated by reference to
Exhibit 10.29 of Form 10-Q of the Registrant for the quarter ended September 30, 2003) |
|
|
|
10.20
|
|
Second Amendment and Restated Credit Agreement, dated September 27, 2004, by and among
Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB,
BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit
10.1 of the Registrants Form 8-K Report dated September 27, 2004 and filed with the
Securities and Exchange Commission on October 1, 2004) |
|
|
|
10.21
|
|
Agreement of Limited Partnership of West Fork Pipeline Company LP (Incorporated by reference
to Exhibit 10.21 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004) |
|
|
|
10.22
|
|
First Amendment to Second Amended and Restated Credit Agreement, dated as of December 27,
2004, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First
American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by
reference to Exhibit 10.1 of the Registrants Form 8-K Report dated December 30, 2004 and
filed with the Securities and Exchange Commission on December 30, 2004) |
|
|
|
10.23
|
|
Second Amendment to Second Amended and Restated Credit Agreement, dated as of April 1, 2005,
by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American
Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference
to Exhibit 10.1 of the Registrants Form 8-K Report dated April 4, 2005 and filed with the
Securities and Exchange Commission on April 8, 2005) |
|
|
|
10.24
|
|
Third Amendment to Second Amended and Restated Credit Agreement (Incorporated by reference
to Exhibit 10.1 of the Registrants Form 8-K Report dated October 4, 2005 and filed with the
Securities and Exchange Commission on October 20, 2005) |
|
|
|
10.25
|
|
Purchase and Sale Agreement, dated as of October 14, 1005, among Parallel, L.P., Lynx
Production Company, Inc., Elton Resources, Inc., Cascade Energy Corporation, Chelsea Energy,
Inc., William P. Sutter, Trustee, William P. Sutter Trust, J. Leroy Bell, E. L. Brahaney,
Brent Beck, Cavic Interests, LLC and Stanley Talbott (Incorporated by reference to Exhibit
10.2 of the Registrants Form 8-K Report dated October 14, 2005 and filed with the Securities
and Exchange Commission on October 20, 2005) |
|
|
|
10.26
|
|
Ancillary Agreement to Purchase and Sale Agreement, dated October 14, 2005, between
Parallel, L.P. and Lynx Production Company, Inc. (Incorporated by reference to Exhibit 10.3 of
the Registrants Form 8-K Report dated October 14, 2005 and filed with the Securities and
Exchange Commission on October 20, 2005) |
|
|
|
No. |
|
Description of Exhibit |
10.27
|
|
Guarantee of Parallel, L.P., dated October 13, 2004 (Incorporated by reference to Exhibit
10.4 of the Registrants Form 8-K Report dated October 14, 2005 and filed with the Securities
and Exchange Commission on October 20, 2005) |
|
|
|
10.28
|
|
ISDA Master Agreement, dated as of October 13, 2005, between Parallel, L.P. and Citibank,
N.A. (Incorporated by reference to Exhibit 10.5 of the Registrants Form 8-K Report dated
October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005) |
|
|
|
10.29
|
|
Third Amended and Restated Credit Agreement, dated as of December 23, 2005, among Parallel
Petroleum Corporation, Parallel, L.P., Parallel, L.L.C. and Citibank Texas, N.A., BNP Paribas,
CitiBank F.S.B., Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland and
Fortis Capital Corp. (Incorporated by reference to Exhibit No. 10.1 of the Registrants Form
8-K Report, dated December 23, 2005, as filed with the Securities and Exchange Commission on
December 30, 2005) |
|
10.30
|
|
Second Lien Term Loan Agreement, dated November 15, 2005, among Parallel Petroleum
Corporation, Parallel, L.P., BNP Paribas and Citibank Texas, N.A. (Incorporated by reference
to Exhibit No. 10.4 of the Registrants Form 8-K Report, dated November 15, 2005, as filed
with the Securities and Exchange Commission on November 21, 2005) |
|
|
|
10.31
|
|
Intercreditor and Subordination Agreement, dated November 15, 2005, among Citibank Texas,
N.A., BNP Paribas, Parallel Petroleum Corporation, Parallel, L.P. and Parallel, L.L.C.
(Incorporated by reference to Exhibit No. 10.5 of the Registrants Form 8-K Report, dated
November 15, 2005, as filed with the Securities and Exchange Commission on November 21, 2005) |
|
|
|
14
|
|
Code of Ethics (Incorporated by reference to Exhibit No. 14 of the Registrants Form 10-K
Report for the fiscal year ended December 31, 2003 and filed with the Securities and Exchange
Commission on March 22, 2004) |
|
|
|
21
|
|
Subsidiaries (Incorporated by reference to Exhibit No. 21 of the Registrants Form 10-K
Report for the fiscal year ended December 31, 2003 and filed with the Securities and Exchange
Commission on March 22, 2004) |
|
|
|
*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. |