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) OF THE SECURITIES
EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2008 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 000-13305
PARALLEL PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
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Delaware
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75-1971716 |
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(State of other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.) |
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1004 N. Big Spring, Suite 400,
Midland, Texas
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79701 |
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(Address of Principal Executive Offices)
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(Zip Code) |
(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, a non-accelerated filer or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o (Do not check if a smaller reporting company) | Smaller reporting company 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 July 28, 2008, 41,549,746 shares of the Registrants Common Stock, $0.01 par value, were
outstanding.
PART 1 FINANCIAL INFORMATION
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ITEM 1. |
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FINANCIAL STATEMENTS |
PARALLEL PETROLEUM CORPORATION
Consolidated Balance Sheets
($ in thousands)
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June 30, |
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December 31, |
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2008 |
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2007 |
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(unaudited) |
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Assets |
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Current assets: |
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Cash and cash equivalents |
|
$ |
8,910 |
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$ |
7,816 |
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Accounts receivable: |
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|
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Oil and natural gas sales |
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33,334 |
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|
20,499 |
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Joint interest owners and other, net of allowance for doubtful account of $50 |
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1,905 |
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|
2,460 |
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Affiliates and joint ventures |
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6 |
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3,970 |
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35,245 |
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26,929 |
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Other current assets |
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|
548 |
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|
600 |
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Deferred tax asset |
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21,461 |
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10,293 |
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Total current assets |
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66,164 |
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45,638 |
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Property and equipment, at cost: |
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Oil and natural gas properties, full cost method (including $109,761 and $86,402 not
subject to depletion) |
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782,492 |
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648,576 |
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Other |
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3,033 |
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2,877 |
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785,525 |
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651,453 |
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Less accumulated depreciation, depletion and amortization |
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(165,196 |
) |
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(145,482 |
) |
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Net property and equipment |
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620,329 |
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505,971 |
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Restricted cash |
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80 |
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78 |
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Investment in pipelines and gathering system ventures |
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328 |
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8,638 |
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Other assets, net of accumulated amortization of $1,711 and $1,425 |
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3,886 |
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2,768 |
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$ |
690,787 |
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$ |
563,093 |
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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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$ |
62,917 |
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$ |
47,848 |
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Asset retirement obligations |
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877 |
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|
598 |
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Derivative obligations |
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62,962 |
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30,424 |
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Put obligations |
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302 |
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Total current liabilities |
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127,058 |
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78,870 |
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Revolving credit facility |
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137,000 |
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60,000 |
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Senior notes (principal amount $150,000) |
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145,630 |
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145,383 |
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Asset retirement obligations |
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4,729 |
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|
4,339 |
|
Derivative obligations |
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47,836 |
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13,194 |
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Put obligations |
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3,029 |
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Deferred tax liability |
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19,916 |
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26,045 |
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Total long-term liabilities |
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358,140 |
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248,961 |
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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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Common stock par value $0.01 per share, authorized 60,000,000 shares,
issued and outstanding 41,545,114 and 41,252,644 |
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415 |
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|
412 |
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Additional paid-in capital |
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198,726 |
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196,457 |
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Retained earnings |
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6,448 |
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38,393 |
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Total stockholders equity |
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205,589 |
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235,262 |
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$ |
690,787 |
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$ |
563,093 |
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The accompanying notes are an integral part of these Consolidated Financial Statements
(1)
PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Operations
(unaudited)
(in thousands, except per share data)
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Three Months Ended June 30, |
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Six Months Ended June 30, |
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2008 |
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2007 |
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2008 |
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|
2007 |
|
Oil and natural gas revenues: |
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|
|
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|
|
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Oil and natural gas sales |
|
$ |
56,075 |
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|
$ |
27,354 |
|
|
$ |
100,016 |
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|
$ |
50,470 |
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Cost and expenses: |
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Lease operating expense |
|
|
7,254 |
|
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|
5,576 |
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|
|
14,233 |
|
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|
9,975 |
|
Production taxes |
|
|
2,996 |
|
|
|
1,194 |
|
|
|
5,285 |
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|
2,248 |
|
Production tax refund |
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(1,209 |
) |
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|
|
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|
(1,209 |
) |
General and administrative |
|
|
3,265 |
|
|
|
2,580 |
|
|
|
5,833 |
|
|
|
5,245 |
|
Depreciation, depletion and amortization |
|
|
10,483 |
|
|
|
7,150 |
|
|
|
19,835 |
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|
|
13,859 |
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|
Total costs and expenses |
|
|
23,998 |
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|
|
15,291 |
|
|
|
45,186 |
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|
30,118 |
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Operating income |
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|
32,077 |
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|
|
12,063 |
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|
54,830 |
|
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|
20,352 |
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Other income (expense), net: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Loss on derivatives not classified as hedges |
|
|
(71,609 |
) |
|
|
(2,170 |
) |
|
|
(93,495 |
) |
|
|
(6,605 |
) |
Interest and other income |
|
|
32 |
|
|
|
56 |
|
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|
65 |
|
|
|
108 |
|
Interest expense |
|
|
(5,368 |
) |
|
|
(4,312 |
) |
|
|
(10,886 |
) |
|
|
(8,020 |
) |
Other expense |
|
|
(1 |
) |
|
|
21 |
|
|
|
(1 |
) |
|
|
(15 |
) |
Equity in gain (loss) of pipelines
and gathering system ventures |
|
|
165 |
|
|
|
(289 |
) |
|
|
382 |
|
|
|
(594 |
) |
|
|
|
|
|
|
|
|
|
|
|
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|
Total other income (expense), net |
|
|
(76,781 |
) |
|
|
(6,694 |
) |
|
|
(103,935 |
) |
|
|
(15,126 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes |
|
|
(44,704 |
) |
|
|
5,369 |
|
|
|
(49,105 |
) |
|
|
5,226 |
|
Income tax benefit (expense), deferred |
|
|
15,499 |
|
|
|
(1,905 |
) |
|
|
17,160 |
|
|
|
(1,858 |
) |
|
|
|
|
|
|
|
|
|
|
|
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|
Net income (loss) |
|
$ |
(29,205 |
) |
|
$ |
3,464 |
|
|
$ |
(31,945 |
) |
|
$ |
3,368 |
|
|
|
|
|
|
|
|
|
|
|
|
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|
Net income (loss) per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Basic |
|
$ |
(0.70 |
) |
|
$ |
0.09 |
|
|
$ |
(0.77 |
) |
|
$ |
0.09 |
|
|
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Diluted |
|
$ |
(0.70 |
) |
|
$ |
0.09 |
|
|
$ |
(0.77 |
) |
|
$ |
0.09 |
|
|
|
|
|
|
|
|
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Weighted average common shares outstanding: |
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Basic |
|
|
41,446 |
|
|
|
37,786 |
|
|
|
41,359 |
|
|
|
37,667 |
|
|
|
|
|
|
|
|
|
|
|
|
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|
Diluted |
|
|
41,446 |
|
|
|
38,769 |
|
|
|
41,359 |
|
|
|
38,763 |
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|
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|
|
|
|
|
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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
Six Months Ended June 30, 2008 and 2007
(unaudited)
($ in thousands)
|
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2008 |
|
|
2007 |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(31,945 |
) |
|
$ |
3,368 |
|
Adjustments to reconcile net income (loss) to net cash
provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
19,835 |
|
|
|
13,859 |
|
Gain on sale of automobiles |
|
|
(4 |
) |
|
|
|
|
Accretion of asset retirement obligation |
|
|
187 |
|
|
|
164 |
|
Accretion of senior notes discount |
|
|
247 |
|
|
|
|
|
Deferred income tax (benefit) expense |
|
|
(17,160 |
) |
|
|
1,858 |
|
Loss on derivatives not classified as hedges |
|
|
93,495 |
|
|
|
6,605 |
|
Accretion of
interest on put obligations |
|
|
6 |
|
|
|
|
|
Common stock issued to directors |
|
|
217 |
|
|
|
|
|
Stock option expense |
|
|
227 |
|
|
|
59 |
|
Equity in (gain) loss of pipelines and gathering system ventures |
|
|
(382 |
) |
|
|
594 |
|
Bad debt expense |
|
|
|
|
|
|
(30 |
) |
|
|
|
|
|
|
|
|
|
Changes in assets and liabilities: |
|
|
|
|
|
|
|
|
Other assets, net |
|
|
(480 |
) |
|
|
(88 |
) |
Restricted cash |
|
|
(2 |
) |
|
|
273 |
|
Accounts receivable |
|
|
(8,316 |
) |
|
|
5,889 |
|
Other current assets |
|
|
(99 |
) |
|
|
293 |
|
Accounts payable and accrued liabilities |
|
|
15,069 |
|
|
|
1,831 |
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
70,895 |
|
|
|
34,675 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
Additions to oil and natural gas properties |
|
|
(124,727 |
) |
|
|
(73,553 |
) |
Proceeds from disposition of oil and natural gas properties |
|
|
|
|
|
|
1,764 |
|
Additions to other property and equipment |
|
|
(273 |
) |
|
|
(214 |
) |
Settlements on derivative instruments |
|
|
(22,839 |
) |
|
|
(5,862 |
) |
Net investment in pipelines and gathering system ventures |
|
|
(15 |
) |
|
|
(2,848 |
) |
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(147,854 |
) |
|
|
(80,713 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Borrowings from bank line of credit |
|
|
77,000 |
|
|
|
46,000 |
|
Payments on bank line of credit |
|
|
|
|
|
|
(1,500 |
) |
Deferred financing cost |
|
|
(270 |
) |
|
|
(175 |
) |
Proceeds from exercise of stock options and warrants |
|
|
1,323 |
|
|
|
1,318 |
|
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
78,053 |
|
|
|
45,643 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
1,094 |
|
|
|
(395 |
) |
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of period |
|
|
7,816 |
|
|
|
5,910 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
8,910 |
|
|
$ |
5,515 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash financing and investing activities: |
|
|
|
|
|
|
|
|
Deferred
purchase of derivative puts |
|
$ |
3,325 |
|
|
$ |
|
|
Oil and natural gas properties asset retirement obligations |
|
$ |
482 |
|
|
$ |
(385 |
) |
Property transfer: |
|
|
|
|
|
|
|
|
Transfer to oil and natural gas properties |
|
$ |
8,707 |
|
|
$ |
|
|
Transfer from equity investment |
|
$ |
(8,707 |
) |
|
$ |
|
|
Non-cash exchange of oil and natural gas properties: |
|
|
|
|
|
|
|
|
Properties received in exchange |
|
$ |
|
|
|
$ |
6,463 |
|
Properties delivered in exchange |
|
$ |
|
|
|
$ |
(5,495 |
) |
Other transactions: |
|
|
|
|
|
|
|
|
Interest paid |
|
$ |
9,901 |
|
|
$ |
8,474 |
|
The accompany notes are an integral part of these Consolidated Financial Statements.
(3)
PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Stockholders Equity
Year-Ended December 31, 2007 and Year-to-Date June 30, 2008
(unaudited)
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock |
|
|
Additional |
|
|
|
|
|
|
Total |
|
|
|
Number of |
|
|
|
|
|
|
paid-in |
|
|
Retained |
|
|
stockholders |
|
|
|
shares |
|
|
Amount |
|
|
capital |
|
|
earnings |
|
|
equity |
|
Balance |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007 |
|
|
41,253 |
|
|
$ |
412 |
|
|
$ |
196,457 |
|
|
$ |
38,393 |
|
|
$ |
235,262 |
|
Common stock issued to directors |
|
|
18 |
|
|
|
|
|
|
|
217 |
|
|
|
|
|
|
|
217 |
|
Warrants exercised |
|
|
149 |
|
|
|
1 |
|
|
|
891 |
|
|
|
|
|
|
|
892 |
|
Fees associated with warrant exercise |
|
|
|
|
|
|
|
|
|
|
(74 |
) |
|
|
|
|
|
|
(74 |
) |
Options exercised |
|
|
125 |
|
|
|
2 |
|
|
|
503 |
|
|
|
|
|
|
|
505 |
|
Stock offering costs |
|
|
|
|
|
|
|
|
|
|
368 |
|
|
|
|
|
|
|
368 |
|
Stock option expense |
|
|
|
|
|
|
|
|
|
|
227 |
|
|
|
|
|
|
|
227 |
|
Tax benefit of stock option exercise
in excess of compensation |
|
|
|
|
|
|
|
|
|
|
137 |
|
|
|
|
|
|
|
137 |
|
Net loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(31,945 |
) |
|
|
(31,945 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2008 |
|
|
41,545 |
|
|
$ |
415 |
|
|
$ |
198,726 |
|
|
$ |
6,448 |
|
|
$ |
205,589 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompany 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.
Parallel Petroleum Corporation, or Parallel, is engaged in the acquisition, development and
exploitation of long-lived oil and natural gas reserves and, to a lesser extent, exploring for new
oil and natural gas reserves. The majority of our producing properties are in the:
|
|
|
Permian Basin of west Texas and New Mexico; and |
|
|
|
|
Fort Worth Basin of north Texas. |
The financial information included herein is unaudited. The balance sheet as of December 31,
2007 has been derived from our audited Consolidated Financial Statements as of December 31, 2007.
The unaudited financial 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 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 Quarterly Report on Form 10-Q
pursuant to certain rules and regulations of the Securities and Exchange Commission. The financial
statements included in this report 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, 2007.
Unless otherwise indicated or unless the context otherwise requires, all references to we,
us, our, Parallel, or Company mean the registrant, Parallel Petroleum Corporation and,
where applicable, its former consolidated subsidiaries.
NOTE 2. STOCKHOLDERS EQUITY
Parallel accounts for stock based compensation in accordance with the Financial Accounting
Standards Board (FASB) Statement of Financial Accounting Standards No. 123 (revised 2004),
Share-Based Payment (SFAS 123(R)).
Options
For the six months ended June 30, 2008 and 2007, Parallel recognized compensation expense of
approximately $227,000 and $59,000, respectively, with a tax benefit of approximately $77,000 and
$20,000, respectively, associated with our stock option grants. During the second quarter of 2007,
we revised our estimate of expected forfeitures of stock options granted to directors due to the
resignation of a director and the subsequent forfeiture of 40,000 stock options held by him. As a
result, we revised our estimate of the grant date fair value of shares expected to ultimately vest
under our stock option plan by approximately $283,000. As a consequence, general and
administrative expenses during the three months ended June 30, 2007 were reduced by approximately
$154,000 which includes a cumulative adjustment for amounts previously expensed and associated with
options estimated to be forfeited or surrendered.
(5)
The following table presents future stock-based compensation expense for our outstanding stock
options which we expect to recognize during the indicated vesting periods:
|
|
|
|
|
|
|
($ in thousands) |
|
Third quarter 2008 |
|
$ |
559 |
|
Fourth quarter 2008 |
|
|
535 |
|
2009 |
|
|
1,534 |
|
2010 |
|
|
789 |
|
2011 and 2012 |
|
|
480 |
|
|
|
|
|
Total |
|
$ |
3,897 |
|
|
|
|
|
At June 30, 2008, options to purchase 310,045 shares of common stock were outstanding and
vested. At that same date, options to purchase 476,250 shares were outstanding and unvested.
During the six months ended June 30, 2008, options to purchase 355,000 shares were granted to the
officers and employees, options to purchase 126,205 shares of common stock were exercised and no
options expired or were forfeited.
The fair value of each option award is estimated on the date of grant. The fair values of
stock options granted prior to and remaining outstanding at June 30, 2008 and that covered shares
subject to future vesting at that date were determined using the Black-Scholes option valuation
method and the assumptions noted in the following table. Expected volatilities are based on
implied volatilities from traded options and historical volatility of our stock. The expected term
of the options granted used in the Black-Scholes model represent the period of time that options
granted are expected to be outstanding. Risk free rates are based on the U.S. Treasury, Daily
Treasury Yield Curve Rate.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
2007 |
|
2005 |
|
2001 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected volatility |
|
|
46.50 |
% |
|
|
52.52 |
% |
|
|
54.20 |
% |
|
|
57.95 |
% |
Weighted-average volatility |
|
|
46.50 |
% |
|
|
52.52 |
% |
|
|
54.20 |
% |
|
|
57.95 |
% |
Expected dividends |
|
|
0.00 |
|
|
|
0.00 |
|
|
|
0.00 |
|
|
|
0.00 |
|
Expected term (in years) |
|
|
6.25 |
|
|
|
5.75 |
|
|
|
6.50 |
|
|
|
7.50 |
|
Risk-free rate |
|
|
3.81%-3.86 |
% |
|
|
4.89 |
% |
|
|
4.20 |
% |
|
|
5.05 |
% |
A summary of the stock option activity as of June 30, 2008 is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
Remaining |
|
|
|
|
|
|
|
|
|
|
Average Exercise |
|
|
Contractual |
|
|
Aggregate |
|
|
|
Options |
|
|
Price |
|
|
Term |
|
|
Intrinsic Value |
|
|
|
(in thousands) |
|
|
|
|
|
|
(years) |
|
|
(in thousands) |
|
Outstanding December 31, 2007 |
|
|
558 |
|
|
$ |
7.03 |
|
|
|
|
|
|
|
|
|
Granted |
|
|
355 |
|
|
$ |
21.02 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(126 |
) |
|
$ |
3.99 |
|
|
|
|
|
|
|
|
|
Surrendered |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding June 30, 2008 |
|
|
787 |
|
|
$ |
13.84 |
|
|
|
9.1 |
|
|
$ |
4,949 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at June 30, 2008 |
|
|
310 |
|
|
$ |
6.45 |
|
|
|
4.4 |
|
|
$ |
4,242 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
Average weighted grant date fair value of options issued and unvested, June 30, 2008 |
|
$ |
4,596 |
|
Average weighted grant date fair value of options issued and outstanding, June 30, 2008 |
|
$ |
5,750 |
|
(6)
We have outstanding stock options granted under six separate plans. Options expire 10 years
from the date of grant and become exercisable at rates ranging from 10% each year up to 50% each
year. The exercise price cannot be less than the fair market value per share of common stock on
the date of grant.
For the six months ended June 30, 2008 cash received from the exercise of stock options was
approximately $505,000 with an associated $137,000 tax benefit.
Restricted Stock
On June 12, 2008, 10,000 shares of restricted stock were awarded to a non-employee director
under our 2008 Long-Term Incentive Plan. The fair value of the restricted stock awarded was based
on the last sales price of our common stock on the Nasdaq Global Market on the date of grant. For
the six months ended June 30, 2008, compensation expense of approximately $57,000 was recognized
with the restricted stock. These shares vest in four equal increments on June 12th of
each year, commencing on June 12, 2008
The following table presents future stock-based compensation expense for the restricted stock
award, which we expect to recognize during the indicated vesting periods:
|
|
|
|
|
|
|
($ in thousands) |
|
Third quarter 2008 |
|
$ |
24 |
|
Fourth quarter 2008 |
|
|
24 |
|
2009 |
|
|
67 |
|
2010 |
|
|
29 |
|
2011 |
|
|
7 |
|
|
|
|
|
Total |
|
$ |
151 |
|
|
|
|
|
A summary of restricted stock activity as of June 30, 2008 is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
|
|
|
Remaining |
|
|
|
|
|
|
|
Award Date |
|
|
Contractual |
|
|
|
Restricted Stock |
|
|
Fair Value |
|
|
Term |
|
|
|
|
|
|
|
|
|
|
|
(years) |
|
Outstanding December 31, 2007 |
|
|
|
|
|
$ |
|
|
|
|
|
|
Granted |
|
|
10,000 |
|
|
$ |
20.91 |
|
|
|
|
|
Vested |
|
|
(2,500 |
) |
|
$ |
20.91 |
|
|
|
|
|
Surrendered |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-vested shares at June 30, 2008 |
|
|
7,500 |
|
|
$ |
20.91 |
|
|
|
2.9 |
|
|
|
|
|
|
|
|
|
|
|
Stock Awards
On June 12, 2008, each of our four non-employee Directors was awarded 1,912 shares of common
stock under our 2008 Long-Term Incentive Plan, representing compensation expense in the amount of
$160,000 for the six months ended June 30, 2008. The fair value of the common stock awarded was
based on the last sales price of our common stock on the Nasdaq Global Market on the date of grant.
The shares vested 100% on the date of the grant.
Warrants
On April 15, 2008, our registration statement relating to 300,030 shares of
common stock issuable upon the exercise of outstanding warrants was declared effective by the
Securities and Exchange Commission. The warrants were issued in our initial public offering in
1980, as a component
(7)
of the units sold by us. Pursuant to the terms of the warrants, holders of the warrants were
entitled to purchase one share of common stock for each warrant exercised. The warrants were
exercisable at $6.00 per share at any time on or before 5:00 p.m., Mountain Time, on May 15, 2008,
at which time the warrants expired. Between April 15, 2008 and May 15, 2008 a total of 148,637
warrants were exercised for net proceeds of approximately $818,000.
NOTE 3. CREDIT FACILITIES
In the past, we have maintained two separate credit facilities. One of these credit facilities
is our Fourth Amended and Restated Credit Agreement, dated May 16, 2008, or Revolving Credit
Agreement, with a group of bank lenders that provide us with a revolving line of credit having a
borrowing base limitation of $230.0 million at June 30, 2008. The total amount that we can borrow
and have outstanding at any one time is limited to the lesser of $600.0 million or the borrowing
base established by the lenders. At June 30, 2008, the principal amount outstanding under our
revolving credit facility was $137.0 million, excluding $445,000 reserved for our letters of
credit. Unamortized
fees in the amount of $875,000 related to the prior Revolving Credit
Agreement have been rolled into the current Revolving Credit
Agreement, as amended, and will be amortized over the remaining term
of five years.
Our second credit facility was a five year term loan facility provided to us under a Second
Lien Term Loan Agreement, or the Second Lien Agreement, with a group of banks and other lenders.
The Second Lien Agreement was paid off and terminated on July 31, 2007 with our payment to the
lenders of $50.2 million, including interest.
Revolving Credit Facility
Our Revolving Credit Agreement allows us to borrow, repay and reborrow amounts available under
the revolving credit facility. The amount of the borrowing base is based primarily upon the
estimated value of our oil and natural gas reserves. The borrowing base 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 revolving
credit facility in an amount equal to the excess. Except for 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 banks base rate or
the LIBOR rate, at our election. Generally, the banks base rate is equal to its prime rate as
announced by it from time to time.
The LIBOR rate is generally equal to the sum of (a) the rate designated as British Bankers
Association Interest Settlement Rates and offered in one, two, three, six or twelve month interest
periods for deposits of $1.0 million, and (b) a margin ranging from 2.00% to 2.50%, depending upon
the outstanding principal amount of our loan. 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 4.75%. At June 30, 2008, our base rate, plus the applicable margin, was 5.0%
on $137.0 million, the outstanding principal amount of our revolving loan on that same date.
In the case of base rate loans, interest is payable on the last day of each month. In the case
of LIBOR loans, interest is payable on the last day of each applicable interest period; provided
that if the applicable interest period is longer than three months, interest is payable at
three-month intervals following the first day of such interest period.
(8)
If the total outstanding borrowings under the revolving credit facility are less than the
borrowing base, we are required to pay an unused commitment fee to the lenders in an amount equal
to .25% of the daily average of the unadvanced portion of the borrowing base. The fee is payable
quarterly.
If the borrowing base is increased, we are also required to pay a fee of .375% on the amount
of any increase.
The Revolving Credit Agreement contains various restrictive covenants, including (i)
maintenance of a minimum current ratio, (ii) maintenance of a maximum ratio of funded indebtedness
to earnings before interest, income taxes, depreciation, depletion and amortization, (iii)
maintenance of a minimum net worth, (iv) prohibition of payment of dividends and (v) restrictions
on incurrence of additional debt. We have pledged substantially all of our producing oil and
natural gas properties to secure the repayment of our indebtedness under the Revolving Credit
Agreement.
All outstanding principal and accrued and unpaid interest under the revolving credit facility
is due and payable on December 31, 2013. 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 June 30, 2008 we were in compliance with all of the covenants in our Revolving Credit
Agreement.
Senior Notes
On July 31, 2007, we completed a private offering of unsecured senior notes, or the senior
notes in the principal amount of $150.0 million. The senior notes mature on August 1, 2014 and
bear interest at 10.25% which is payable semi-annually beginning on February 1, 2008. Prior to
August 1, 2010, we may redeem up to 35% of the senior notes for a price equal to 110.250% of the
original principal amount of the senior notes with the proceeds of certain equity offerings. On or
after August 1, 2011 we may redeem all or some of the senior notes at a redemption price that will
decrease from 105.125% of the principal amount of the senior notes to 100% of the principal amount
on August 1, 2013. In addition, prior to August 1, 2011, we may redeem some or all of the senior
notes at a redemption price equal to 100% of the principal amount of the senior notes to be
redeemed, plus a make-whole premium, plus any accrued and unpaid interest. Generally, the
make-whole premium is an amount equal to the greater of (a) 1% of the principal amount of the
senior notes being redeemed and (b) the excess of the present value of the redemption price of such
notes as of August 1, 2011 plus all required interest payments due through August 1, 2011 (computed
at a discount rate equal to a specified U.S. Treasury Rate plus 50 basis points), over the
principal amount of the senior notes being redeemed.
The indenture governing the senior notes restricts our ability to: (i) borrow money; (ii)
issue redeemable and preferred stock; (iii) pay distributions or dividends; (iv) make investments;
(v) create liens without securing the senior notes; (vi) enter into agreements that restrict
dividends from subsidiaries; (vii) sell certain assets or merge with or into other companies;
(viii) enter into transactions with affiliates; (ix) guarantee indebtedness; and (x) enter into new
lines of business.
Interest Accrued
For the six months ended June 30, 2008, the aggregate interest accrued under our revolving
credit facility and our senior notes was approximately $10.3 million. Bank fees and note discount
amortization was approximately $621,000 and interest capitalized was approximately $44,000.
NOTE 4. PROPERTY EXCHANGE AND ACQUISITIONS
On February 23, 2007, we entered into a property exchange agreement with an unrelated third
party. As a result of the exchange, we acquired an additional 9,233 net undeveloped acres in our
New Mexico Wolfcamp project area with an estimated fair value of approximately $6.5 million. We
are the operator of wells drilled on this undeveloped acreage. Under the terms of the exchange
agreement, we assigned to the third party interests in 37 non-operated wells and 3,250 net
undeveloped non-operated acres in the New
(9)
Mexico Wolfcamp project area, along with cash of
approximately $969,000. In accordance with the full cost method of accounting, no gain or loss was
recorded on the transaction.
On June 26, 2008 we exercised a preferential right and purchased the interests owned by an
unrelated third party, in our operated Diamond M properties in Scurry County, Texas, effective May
1, 2008. The purchase price, approximately $35.5 million, was financed with borrowings under our
revolving credit facility.
The acquired interest consisted of two components, including an 89% working interest in the
Base production and reserves and a 22.3% working interest in the production and reserves above the
Base. As used in our original trade agreement with the unrelated third party, the Base production
and reserves generally referred to and meant future production and reserves defined by an
established base production decline curve as of December 19, 2001. Prior to this acquisition, we
did not own an interest in the Base production and reserves but owned a 65.7% working interest in
the production and reserves above the Base. This acquisition resulted in an increase in our
current ownership in the Base production and reserves from zero to an approximate 89% working
interest (77% net revenue interest), and an increase in the production and reserves above the Base
from a 65.7% working interest to an 88% working interest (76% net revenue interest).
As described in Note 10 below, in June 2008 we acquired all of the assets of the Hagerman Gas
Gathering System Joint Venture.
NOTE 5. 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, 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.
The net book value of oil and natural gas properties, less related deferred income taxes, 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 Securities and Exchange Commission, the excess above the ceiling may not be 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.
At
June 30, 2008, the net book value of our oil and gas properties, less
related deferred income taxes, was below the calculated ceiling. As a
result, we were not required to record a reduction of our oil and gas
properties under the full cost method of accounting.
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 six month periods ended June 30, 2008 and 2007, overhead costs capitalized
were approximately $842,000 and $725,000, respectively.
NOTE 6. 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. In addition, our
revolving credit facility requires 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.
(10)
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.
We are exposed to credit risk in the event of nonperformance by the counterparties to these
contracts, BNP Paribas and Citibank, N.A. However, we periodically assess the creditworthiness of
the counterparties to mitigate this credit risk.
Adoption of SFAS No. 157
We adopted SFAS No. 157, Fair Value Measurements, effective January 1, 2008 for all
financial assets and liabilities. SFAS No. 157 provides standards and disclosures for assets and
liabilities that are measured and reported at fair value. In February 2008, the FASB issued FSP No.
157-2, which delayed the effective date of SFAS No. 157 by one year for nonfinancial assets and
liabilities. Beginning January 1, 2009, we will apply SFAS 157 fair value requirements to
nonfinancial assets and nonfinancial liabilities that are not recognized or disclosed on a
recurring basis. As defined in SFAS No. 157, fair value is the price that would be received to
sell an asset or paid to transfer a liability in an orderly transaction between market participants
at the measurement date (exit price). SFAS No. 157 requires disclosure that establishes a framework
for measuring fair value and expands disclosure about fair value measurements. The statement
requires fair value measurements be classified and disclosed in one of the following categories:
|
Level 1: |
|
Unadjusted quoted prices in active markets that are accessible at
the measurement date for identical, unrestricted assets or liabilities. We
consider active markets as those in which transactions for the assets or
liabilities occur in sufficient frequency and volume to provide pricing
information on an ongoing basis. |
|
|
Level 2: |
|
Quoted prices in markets that are not active, or inputs which are
observable, either directly or indirectly, for substantially the full term of
the asset or liability. This category includes those derivative instruments
that we value using observable market data. Substantially all of these inputs
are observable in the marketplace throughout the full term of the derivative
instrument, can be derived from observable data, or supported by observable
levels at which transactions are executed in the marketplace. Instruments in
this category include non-exchange traded derivatives such as
over-the-counter commodity price swaps and interest rate swaps. |
|
|
Level 3: |
|
Measured based on prices or valuation models that require inputs
that are both significant to the fair value measurement and less observable
from objective sources (i.e., supported by little or no market activity). Our
valuation models are primarily industry-standard models that consider various
inputs including: (a) quoted forward prices for commodities, (b) time value,
(c) volatility factors and (d) current market and contractual prices for the
underlying instruments, as well as other relevant economic measures. Level 3
instruments primarily include derivative instruments, such as commodity price
collars and puts. Although we review our counterpartys valuation and assess
the reasonableness of our prices and valuation techniques, we do not have
sufficient corroborating market evidence to support classifying these price
collars and put assets and liabilities as Level 2. |
(11)
As required by SFAS No. 157, financial assets and liabilities are classified based on the
lowest level of input that is significant to the fair value measurement. Our assessment of the
significance of a particular input to the fair value measurement requires judgment, and may affect
the valuation of the fair value of assets and liabilities and their placement within the fair value
hierarchy levels. The following table summarizes the valuation of our derivative financial
instruments by SFAS No. 157 pricing levels as of June 30,
2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quoted Prices in |
|
|
|
|
|
|
|
|
|
|
|
|
Active Markets |
|
|
|
|
|
|
|
|
|
|
|
|
for Identical |
|
|
Other Observable |
|
|
Unobservable |
|
|
Fair Value at |
|
|
|
Assets (Level 1) |
|
|
Inputs (Level 2) |
|
|
Inputs (Level 3) |
|
|
June 30, 2008 |
|
Interest Swaps |
|
$ |
|
|
|
$ |
(2,123 |
) |
|
$ |
|
|
|
$ |
(2,123 |
) |
Oil Swaps |
|
$ |
|
|
|
$ |
(23,557 |
) |
|
$ |
|
|
|
$ |
(23,557 |
) |
Oil & Gas Collars |
|
$ |
|
|
|
$ |
|
|
|
$ |
(88,018 |
) |
|
$ |
(88,018 |
) |
Oil Puts |
|
$ |
|
|
|
$ |
|
|
|
$ |
2,900 |
|
|
$ |
2,900 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
|
|
|
$ |
(25,680 |
) |
|
$ |
(85,118 |
) |
|
$ |
(110,798 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
The determination of the fair values above incorporates various factors required under SFAS
No. 157. These factors include not only the impact of our nonperformance risk on our liabilities
but also the credit standing of the counterparties involved.
The following table sets forth a reconciliation of changes in the fair value of financial
assets and liabilities classified as level 3 in the fair value hierarchy (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, 2008 |
|
|
June 30, 2008 |
|
|
|
Derivative |
|
|
Derivative |
|
|
Derivative |
|
|
Derivative |
|
|
|
Collars |
|
|
Puts |
|
|
Collars |
|
|
Puts |
|
Beginning balance |
|
$ |
(31,389 |
) |
|
$ |
|
|
|
$ |
(15,852 |
) |
|
$ |
|
|
Total losses |
|
|
(60,743 |
) |
|
|
(425 |
) |
|
|
(77,489 |
) |
|
|
(425 |
) |
Settlements |
|
|
4,114 |
|
|
|
|
|
|
|
5,323 |
|
|
|
|
|
Purchases |
|
|
|
|
|
|
3,325 |
|
|
|
|
|
|
|
3,325 |
|
Transfers in and/or out of level 3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance |
|
$ |
(88,018 |
) |
|
$ |
2,900 |
|
|
$ |
(88,018 |
) |
|
$ |
2,900 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in unrealized losses included in earnings relating
to derivatives still held as of June 30, 2008(1) |
|
$ |
(56,629 |
) |
|
$ |
(425 |
) |
|
$ |
(72,166 |
) |
|
$ |
(425 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Gains and losses (realized and unrealized) included in earnings for the three months and six months ended
June 30, 2008 are reported in Other Income on the Consolidated Statement of Operations. |
Interest Rate Sensitivity
We have employed 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. These contracts are accounted for by mark
to market accounting as prescribed in SFAS 133. We view these contracts as protection against
future interest rate volatility. As of June 30, 2008, the fair market value of these interest rate
swaps was a liability of approximately $2.1 million.
(12)
The table below recaps the nature of these interest rate swaps and the fair market value of
these contracts as of June 30, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional |
|
|
Weighted Average |
|
|
Estimated |
|
Period of Time |
|
Amounts |
|
|
Fixed Interest Rates |
|
|
Fair Market Value |
|
|
|
($ in millions) |
|
|
|
|
|
|
($ in thousands) |
|
July 1, 2008 through December 31, 2008 |
|
$ |
100 |
|
|
|
4.86 |
% |
|
$ |
(997 |
) |
January 1, 2009 through December 31, 2009 |
|
$ |
50 |
|
|
|
5.06 |
% |
|
|
(774 |
) |
January 1, 2010 through October 31, 2010 |
|
$ |
50 |
|
|
|
5.15 |
% |
|
|
(352 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
$ |
(2,123 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Price Sensitivity
All of our commodity derivatives are accounted for using mark-to-market accounting as
prescribed in SFAS 133.
Put Options. Puts are an option to sell an asset. For any put transaction, the
counterparty is required to make a payment to the Company if the reference floating price for any
settlement period is less than the put or floor price for such contract.
In June 2008 we entered into multiple put contracts with BNP Paribas. In lieu of making
premium payments for the puts at the time of entering into our put contracts, we deferred payment
until the settlement dates of the contract. Future payments will be netted against any payments
that the counterparty may owe to us based on the floating price. We
have accrued a liability as of
June 30, 2008 of $3.331 million for the purchase price of the puts, and we will pay a premium for
these puts due to the deferral of the payments until the settlement dates. The premiums associated
with these puts will be treated as interest expense and will have an effective interest rate
between 4.3% and 5.7%.
A summary of our put positions at June 30, 2008 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
Barrels of |
|
|
|
|
|
|
Fair Market |
|
Period of Time |
|
Oil |
|
|
Floor |
|
|
Value |
|
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
|
|
January 1, 2009 through December 31, 2009 |
|
|
109,500 |
|
|
$ |
100.00 |
|
|
$ |
505 |
|
January 1, 2010 through December 31, 2010 |
|
|
134,100 |
|
|
$ |
100.00 |
|
|
|
1,087 |
|
January 1, 2011 through December 31, 2011 |
|
|
146,000 |
|
|
$ |
100.00 |
|
|
|
1,308 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
$ |
2,900 |
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
(13)
A summary of our collar positions at June 30, 2008 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
Barrels of |
|
|
NYMEX Oil Prices |
|
|
Fair Market |
|
Period of Time |
|
Oil |
|
|
Floor |
|
|
Cap |
|
|
Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 1, 2008 through December 31, 2008 |
|
|
174,800 |
|
|
$ |
63.42 |
|
|
$ |
83.86 |
|
|
$ |
(9,941 |
) |
January 1, 2009 through December 31, 2009 |
|
|
620,500 |
|
|
$ |
63.53 |
|
|
$ |
80.21 |
|
|
|
(36,970 |
) |
January 1, 2010 through October 31, 2010 |
|
|
486,400 |
|
|
$ |
63.44 |
|
|
$ |
78.26 |
|
|
|
(28,180 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MMBtu of |
|
|
WAHA Gas Prices |
|
|
|
|
|
|
|
Natural Gas |
|
|
Floor |
|
|
Cap |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 1, 2008 through December 31, 2008 |
|
|
1,840,000 |
|
|
$ |
7.38 |
|
|
$ |
9.28 |
|
|
|
(5,455 |
) |
January 1, 2009 through December 31, 2009 |
|
|
3,285,000 |
|
|
$ |
7.06 |
|
|
$ |
9.93 |
|
|
|
(7,472 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(88,018 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
Barrels of |
|
|
NYMEX Oil |
|
|
Fair Market |
|
Period of Time |
|
Oil |
|
|
Swap Price |
|
|
Value |
|
|
|
|
|
|
|
|
|
|
|
($ in thousands |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 1, 2008 through December 31, 2008
|
|
|
220,800 |
|
|
$ |
33.37 |
|
|
$ |
(23,557 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 7. 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 (loss) 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.
(14)
The following table provides the computation of basic and diluted earnings per share for the
three and six months ended June 30, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
(in thousands, except per share data) |
|
Basic EPS Computation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(29,205 |
) |
|
$ |
3,464 |
|
|
$ |
(31,945 |
) |
|
$ |
3,368 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding |
|
|
41,446 |
|
|
|
37,786 |
|
|
|
41,359 |
|
|
|
37,667 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share |
|
$ |
(0.70 |
) |
|
$ |
0.09 |
|
|
$ |
(0.77 |
) |
|
$ |
0.09 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS Computation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(29,205 |
) |
|
$ |
3,464 |
|
|
$ |
(31,945 |
) |
|
$ |
3,368 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding |
|
|
41,446 |
|
|
|
37,786 |
|
|
|
41,359 |
|
|
|
37,667 |
|
Employee stock options |
|
|
|
|
|
|
714 |
|
|
|
|
|
|
|
812 |
|
Warrants |
|
|
|
|
|
|
269 |
|
|
|
|
|
|
|
284 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares for diluted
earnings per share assuming conversion |
|
|
41,446 |
|
|
|
38,769 |
|
|
|
41,359 |
|
|
|
38,763 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share |
|
$ |
(0.70 |
) |
|
$ |
0.09 |
|
|
$ |
(0.77 |
) |
|
$ |
0.09 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three and six months ended June 30, 2008, the effects of all potentially dilutive
securities (including options and warrants) were excluded from the computation of diluted earnings
per share because we had a net loss from continuing operations and therefore, the effect would have
been antidilutive. Options and warrants to purchase approximately 370,000 and 429,000 shares of
common stock were excluded from the computation of diluted earnings per share for the three and six
months ended June 30, 2008, respectively, because their inclusion would have been antidilutive.
NOTE 8. ASSET RETIREMENT OBLIGATIONS
The following table summarizes our asset retirement obligation transactions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
($ in thousands) |
|
Beginning asset retirement obligation |
|
$ |
5,802 |
|
|
$ |
5,034 |
|
|
$ |
4,937 |
|
|
$ |
5,063 |
|
Additions related to new properties |
|
|
554 |
|
|
|
48 |
|
|
|
706 |
|
|
|
66 |
|
Revisions in estimated cash flows |
|
|
(851 |
) |
|
|
(55 |
) |
|
|
(209 |
) |
|
|
(167 |
) |
Deletions related to property disposals |
|
|
(3 |
) |
|
|
(265 |
) |
|
|
(15 |
) |
|
|
(284 |
) |
Accretion expense |
|
|
104 |
|
|
|
80 |
|
|
|
187 |
|
|
|
164 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending asset retirement obligation |
|
$ |
5,606 |
|
|
$ |
4,842 |
|
|
$ |
5,606 |
|
|
$ |
4,842 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(15)
NOTE 9. RECENTLY ANNOUNCED ACCOUNTING PRONOUNCEMENTS
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS 157),
which defines fair value, establishes a framework for measuring fair value in accordance with
generally accepted accounting principles, and expands disclosures about fair value measurements.
This statement does not require any new fair value measurements but may require some entities to
change their measurement practices. We adopted SFAS No. 157 effective January 1, 2008 and the
adoption did not have a significant effect on our financial position or operating results.
In February 2007, the FASB issued SFAS 159, The Fair Value Option for Financial Assets and
Financial Liabilities, Including an Amendment of FASB Statement No. 115, (FAS 159) which became
effective on January 1, 2008. FAS 159 permits entities to measure eligible financial assets,
financial liabilities and firm commitments at fair value, on an instrument-by-instrument basis,
that are otherwise not permitted to be accounted for at fair value under other generally accepted
accounting principles. The fair value measurement election is irrevocable and subsequent changes in
fair value must be recorded in earnings. This statement, for us, became effective in the first
quarter of 2008 and it did not have any effect on our financial position or operating results as we
did not elect to apply the Fair Value Method.
In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (SFAS
141(R)), which replaces FASB Statement No. 141. SFAS 141(R) establishes principles and
requirements for how an acquirer recognizes and measures in its financial statements the
identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree
and the goodwill acquired. The statement also establishes disclosure requirements that will enable
users to evaluate the nature and financial effects of the business combination. SFAS 141(R) is
effective for acquisitions that occur in an entitys fiscal year that begins after December 15,
2008, which will be our fiscal year 2009. The impact, if any, will depend on the nature and size of
business combinations that we consummate after the effective date.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated
Financial Statementsan amendment of ARB No. 51 (SFAS 160). SFAS 160 requires that accounting
and reporting for minority interests will be recharacterized as noncontrolling interests and
classified as a component of equity. SFAS 160 also establishes reporting requirements that provide
sufficient disclosures that clearly identify and distinguish between the interests of the parent
and the interests of the noncontrolling owners. SFAS 160 applies to all entities that prepare
consolidated financial statements, except not-for-profit organizations, but will affect only those
entities that have an outstanding noncontrolling interest in one or more subsidiaries or that
deconsolidate a subsidiary. This statement is effective as of the beginning of our first fiscal
year beginning after December 15, 2008, which will be our fiscal year 2009. Based upon our balance
sheet, the statement would have no impact.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and
Hedging Activities, an amendment of FASB Statement No. 133 (SFAS 161). This statement is intended
to improve transparency in financial reporting by requiring enhanced disclosures of an entitys
derivative instruments and hedging activities and their effects on the entitys financial position,
financial performance, and cash flows. SFAS 161 applies to all derivative instruments within the
scope of SFAS 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133), as
well as related hedged items, bifurcated derivatives, and nonderivative instruments that are
designated and qualify as hedging instruments. Entities with instruments subject to SFAS 161 must
provide more robust qualitative disclosures and expanded quantitative disclosures. SFAS 161 is
effective prospectively for financial statements issued for fiscal years and interim periods
beginning after November 15, 2008, with early application permitted. We are currently evaluating
the disclosure implications of this statement.
(16)
NOTE 10. INVESTMENT IN GAS GATHERING SYSTEMS
As of June 30, 2008 we had total equity investments of $328,000 in West Fork Pipeline II, L.P.
Our current investment percentage in this limited partnership is 23.25848%. For the three months
ended June 30, 2008 we recorded a gain of $3,000, compared to a gain of $2,000 for the three month
period ended June 30, 2007. For the six months ended June 30, 2008, we recorded a gain of $1,000,
compared to a gain of $5,000 for the six month period ended June 30, 2007. West Fork Pipeline II,
L.P. is currently acquiring the necessary easements and permits to begin transmission of natural
gas.
In June 2008, we acquired all of the assets of the Hagerman Gas Gathering System Joint Venture
in connection with winding up and terminating the Joint Venture. At the time we acquired the
assets, we had a net investment of approximately $8.7 million in the Joint Venture. For the three
months ended June 30, 2008, we recorded an equity gain of $162,000, compared to a loss of
$(291,000) for the three month period ended June 30, 2007. For the six months ended June 30, 2008,
we recorded a gain of $381,000, compared to a loss of $(599,000) for the six months ended June 30,
2007. The increase in income from period to period is the result of greater gas volumes flowing
through the gathering system in 2008, as compared to 2007.
The winding up of the Joint Venture commenced on June 19, 2008. At the time of the winding up
of the Joint Venture, the investment was transferred into oil and natural gas properties.
NOTE 11. COMMITMENTS AND CONTINGENCIES
From time to time, we are party to ordinary routine litigation incidental to our business.
On April 14, 2008, we were added as a defendant to a lawsuit filed in 2007, styled Brady
Briscoe vs. Capstar Drilling, L.P. (Capstar), Cause No. 21,287, in the 259th District Court of
Jones County, Texas. The plaintiff has alleged that he was injured as the result of an accident
while he was working, as an employee of an unrelated third party, on a drilling rig
operated by Capstar. Capstar was conducting drilling operations for us. The plaintiff has asserted
general allegations of negligence as to Capstar and, specifically, a failure to properly equip its
drilling rig, further alleging that we were in charge of the drilling rig and the operational
details of the plaintiffs work. The plaintiff has sued for an amount of actual damages of up to
$15.0 million, together with pre-judgment interest, post-judgment interest and exemplary damages.
Capstar recently settled with the plaintiff and Capstar has been (or is soon to be) dismissed from
the lawsuit. If judgment is entered against us, we would be entitled to a credit for the amount
that the plaintiff has already received from Capstar.
Even though we cannot predict the ultimate outcome of this matter, we believe we have
meritorious defenses and intend to vigorously contest this lawsuit. We have not established a
reserve with respect to the plaintiffs claims.
On March 24, 2008, a lawsuit was filed in the 24th District Court of Jackson
County, Texas, against us and twenty-two other defendants in Cause No. 07-6-13069, styled Tony
Kubenka, Carolyn Kubenka, Dennis J. Kallus, David J. Kallus, Mary L. Kallus, Patricia Kallus, Nova
Deleon, Janie Figuerova, and Larkin Thedford, Plaintiffs v. Tri-C Resources, Inc., Marie S. Adian,
Laura E. Adian, Glenn A. Fiew, Lynn Kramer, Debra Boysen, Carol J. Gleason, Alana Sue Curlee,
Connie W. Marthiljohni, Claire E. Adian, Zachary D. Adian, Donald R. Starkweather, Inc., D.A.
Webernick, Danette Bundick, Johnny A. Webernick, Donna Gail Glover, Sherry Shulze, William H.
Webernick, Jr., TAC Resources, Inc., New Century Exploration, Inc., Allegro Investments, Inc. and
Welper Interests, LP.
The nine plaintiffs in this lawsuit have named us and the other working interest owners,
including Tri-C Resources, Inc., the operator, as defendants. The plaintiffs in this lawsuit allege
that they are royalty owners under oil and gas leases which are part of a pooled gas unit (the
unit) located in Jackson County,
(17)
Texas, and that the defendants, including us, are owners of the leasehold estate under the
plaintiffs leases and others forming the unit. Plaintiffs also assert that one of the leases
(other than plaintiffs leases) forming part of the unit has terminated and, as a result, the
defendants have not properly computed the royalties due to plaintiffs from unit production and have
failed to properly pay royalties due to them. Plaintiffs have sued for an unspecified amount of
damages, including exemplary damages, under theories of breach of contract (including breach of
express and implied covenants of their leases) and conversion, and seek an accounting, a
declaratory judgment to declare the rights of the parties under the leases, and attorneys fees,
interest and court costs.
If a judgment adverse to the defendants was entered, as a working interest owner in the leases
comprising the unit, we believe our liability would be proportionate to the ownership of the other
working interest owners in the leases. We have filed an answer denying any liability. Although an
initial exchange of discovery has occurred, we cannot predict the ultimate outcome of this matter,
we believe we have meritorious defenses and intend to vigorously contest this lawsuit. We have not
established a reserve with respect to plaintiffs claims.
We received a Notice of Proposed Adjustment from the Internal Revenue Service, or the
Service in May 2007 advising us of proposed adjustments to federal income tax of approximately
$2.0 million for the years 2004 and 2005. Subsequent discussions with the Service placed the
issues contested in a development status. In November 2007, the Service issued a letter on the
matter giving the company 30 days to agree or disagree with a final examination report. The final
examination report reflected revisions of the previous proposed adjustments resulting in a reduced
$1.1 million of additional income tax and interest charges. The decrease in proposed tax was the
result of information supplied by us to the examiner as well as discussions of the applicable tax
statutes and regulations. In December 2007, we filed a protest documenting our complete
disagreement with the adjustments proposed on the final examination report and requested a
conference with the appeals office of the Service. The examination office of the Service filed a
response to our protest in February 2008 with the appeals office. On June 4, 2008, our
representatives met with the Services Appeals Officer to review specific issues related to our
calculation of net income from oil and gas and the associated treatment of certain deductions.
During this meeting we were advised that a request to issue an advisory opinion had been
submitted to the National Office of the Service. Pending issuance of this advisory opinion, we will
submit an amendment to our initial protest in further support of our position. We intend to
vigorously contest the adjustment proposed by the Service and believe that we will ultimately
prevail in our position. We have not recorded a liability for tax, interest, or penalties related
to this matter based on our analysis. If a liability for additional income tax should later be
determined to be more likely than not, we anticipate the adjustment to increase the federal income
tax liability would be offset by an increase to a deferred tax asset and would not result in a
charge to earnings. Any interest or penalties resulting from a subsequent determination of
increased tax liability would require a charge to earnings. We believe that the effects of this
matter would not have a material effect on our results of operations for the fiscal quarter in
which we actually incur or establish a reserve account for interest or penalties.
We are also presently a named defendant in one other lawsuit arising out of our operations in
the normal course of business, which we believe is not material.
We are not aware of any legal or governmental proceedings against us, or contemplated to be
brought against us, under the various environmental protection statutes to which we are subject,
nor have we 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. For
the three months ended June 30, 2008 and June 30, 2007 we made contributions to the 401(k) Plan and
Trust of approximately $77,000 and $67,000, respectively. For the six months ended June 30, 2008
and June 30, 2007, we made contributions to the 401(k) Plan and Trust of approximately $152,000 and
$134,000, respectively.
(18)
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 2007 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
Conduct Exploitation Activities on Our Existing Assets. We seek to maximize economic return on
our existing assets by maximizing production rates and ultimate recovery, while managing
operational efficiency to minimize direct lifting costs. Development and production growth
activities include infill and extension drilling of new wells, re-completion, pay adds and
re-stimulation of existing wells and implementation and management of enhanced oil recovery
projects such as waterflood operations. Operational efficiencies and cost reduction measures
include optimization of surface facilities, such as fluid handling systems, gas compression or
artificial lift installations. Efficiencies are also increased through aggressive monitoring and
management of electrical power consumption, injection water quality programs, chemical and
corrosion prevention programs and the use of production surveillance equipment and software. In all
instances, a proactive approach is taken to achieve the desired result while ensuring minimal
environmental impact.
Use of Horizontal Drilling and Fracture Stimulation Activities in Gas Resource Plays. We
believe the use of horizontal drilling and fracture stimulations has enabled us to develop reserves
economically, such as our Barnett Shale and Wolfcamp Carbonate gas projects.
Use Advanced Technologies and Production Techniques. We believe that 3-D seismic surveys,
horizontal drilling, fracture stimulation and other advanced technologies and production techniques
are useful tools that help improve normal drilling operations and enhance our production and
returns. We believe that our use of these technologies and production techniques in exploring for,
developing and exploiting oil and natural gas properties can reduce drilling risks, lower finding
costs, provide for more efficient production of oil and natural gas from our properties and
increase the probability of locating and producing reserves that might not otherwise be discovered.
Acquire Long-Lived Properties with Enhancement Opportunities. Our acquisition strategy is
focused on leveraging our geographical expertise in our core areas of operation and seeking assets
located in and around these areas. We selectively evaluate acquisition opportunities and expect
that they will continue to play a role in increasing our reserve base and future drilling
inventory. When identifying target assets, we focus primarily on reserve quality and assets in new
development plays with upside potential. Through this approach, we have traditionally targeted
smaller asset acquisitions which allow us to absorb, enhance and exploit properties without taking
on significant integration risk.
Conduct Exploratory Activities. Although we do not emphasize exploratory drilling, we will
selectively undertake exploratory projects that have known geological and reservoir characteristics
that are in close proximity to existing wells so data from the existing wells can be correlated
with seismic data on or near the prospect being evaluated, and that could have a potentially
meaningful impact on our reserves.
The extent to which we are able to implement and follow through with our business strategy is
influenced by:
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the prices we receive for the oil and natural gas we produce; |
(19)
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the results of reprocessing and reinterpreting our 3-D seismic data; |
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the results of our drilling activities; |
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the costs of obtaining high quality field services; |
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our ability to find and consummate acquisition opportunities; and |
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|
our ability to negotiate and enter into work to earn arrangements, joint ventures
or other similar arrangements on terms acceptable to us. |
Significant changes in the prices we receive for the oil and natural gas we produce, or the
occurrence of unanticipated events beyond our control, may cause us to defer or deviate from our
business strategy, including the amounts we have budgeted for our activities.
Operating Performance
Our operating performance is influenced by several factors, the most significant of which are
the prices we receive for our oil and natural gas and the quantities of oil and natural gas that we
are able to produce. The world price for oil has overall influence on the prices that we receive
for our oil production. The prices received for different grades of oil are based upon the world
price for oil, which is then adjusted based upon the particular grade. Typically, light oil is
sold at a premium, while heavy grades of crude are discounted. Natural gas prices we receive are
influenced by:
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seasonal demand; |
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weather; |
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hurricane conditions in the Gulf of Mexico; |
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availability of pipeline transportation to end users; |
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proximity of our wells to major transportation pipeline infrastructures; and |
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to a lesser extent, world oil prices. |
Additional factors influencing our overall operating performance include:
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production expenses; |
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overhead requirements; |
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costs of capital; and |
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effects of derivative contracts. |
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:
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cash flow from operations; |
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sales of our equity and debt securities; |
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bank borrowings; and |
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industry joint ventures. |
For the three months ended June 30, 2008 (the Current Quarter), the sale price we received
for
(20)
our crude oil production averaged $119.42 per barrel, compared with $59.24 per barrel for the
three months ended June 30, 2007 (the Comparable Quarter). The average sales price we received
for natural gas for the Current Quarter was $9.95 per Mcf, compared with $6.79 per Mcf for the
Comparable Quarter. For information regarding prices received, refer to the selected operating
data table under -Results of Operations on page 22.
For the six months ended June 30, 2008 (the Current Period), the sale price we received for
our crude oil production averaged $106.32 per barrel, compared with $55.56 per barrel for the six
months ended June 30, 2007 (the Comparable Period). The average sales price we received for
natural gas for the Current Period was $8.90 per Mcf, compared with $6.34 per Mcf for the
Comparable Period. For information regarding prices received, refer to the selected operating data
table under -Results of Operations on page 22.
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 are individually assessed for impairment. The cost of any impaired property
is transferred to the balance of oil and natural gas properties being depleted.
Results of Operations
Our business activities are characterized by frequent, and sometimes significant, changes in
our:
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reserve base; |
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sources of production; |
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product mix (gas versus oil volumes); and |
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the prices we receive for our oil and natural gas production. |
(21)
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 and six months ended June 30, 2008 and June 30, 2007.
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Three Months Ended |
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Six Months Ended |
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6/30/2008 |
|
|
6/30/2007 |
|
|
6/30/2008 |
|
|
6/30/2007 |
|
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|
(in thousands, except per unit data) |
|
Production Volumes: |
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|
|
|
|
|
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|
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|
|
|
|
|
Oil (Bbls) |
|
|
237 |
|
|
|
270 |
|
|
|
484 |
|
|
|
543 |
|
Natural gas (Mcf) |
|
|
2,790 |
|
|
|
1,679 |
|
|
|
5,452 |
|
|
|
3,200 |
|
BOE(1) |
|
|
702 |
|
|
|
550 |
|
|
|
1,393 |
|
|
|
1,076 |
|
BOE per day |
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|
7.7 |
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|
6.0 |
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|
7.7 |
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|
|
5.9 |
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|
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|
|
|
|
|
|
|
|
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|
Sales Prices: |
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|
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|
Oil (per Bbl) |
|
$ |
119.42 |
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|
$ |
59.24 |
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|
$ |
106.32 |
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|
$ |
55.56 |
|
Natural gas (per Mcf) |
|
$ |
9.95 |
|
|
$ |
6.79 |
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|
$ |
8.90 |
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|
$ |
6.34 |
|
BOE price |
|
$ |
79.86 |
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|
$ |
49.81 |
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|
$ |
71.80 |
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|
$ |
46.89 |
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Operating Revenues |
|
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|
|
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|
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|
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|
|
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|
Oil |
|
$ |
28,322 |
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|
$ |
15,956 |
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|
$ |
51,491 |
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$ |
30,167 |
|
Natural gas |
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|
27,753 |
|
|
|
11,398 |
|
|
|
48,525 |
|
|
|
20,303 |
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|
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|
|
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|
|
|
|
|
|
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|
$ |
56,075 |
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|
$ |
27,354 |
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|
$ |
100,016 |
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|
$ |
50,470 |
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Operating Expenses: |
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Lease operating expense |
|
$ |
7,254 |
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$ |
5,576 |
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$ |
14,233 |
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$ |
9,975 |
|
Production taxes |
|
|
2,996 |
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|
1,194 |
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|
5,285 |
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|
2,248 |
|
Production tax refund |
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(1,209 |
) |
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(1,209 |
) |
General and administrative |
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|
3,265 |
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|
2,580 |
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5,833 |
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|
5,245 |
|
Depreciation, depletion and amortization |
|
|
10,483 |
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|
7,150 |
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|
19,835 |
|
|
|
13,859 |
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
23,998 |
|
|
$ |
15,291 |
|
|
$ |
45,186 |
|
|
$ |
30,118 |
|
|
|
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|
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|
|
|
|
|
|
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|
|
|
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Operating income |
|
$ |
32,077 |
|
|
$ |
12,063 |
|
|
$ |
54,830 |
|
|
$ |
20,352 |
|
|
|
|
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|
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|
|
|
|
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|
(1) |
|
A BOE means one barrel of oil equivalent using the ratio of six Mcf of gas to
one barrel of oil. |
RESULTS OF OPERATIONS
For the Three Months Ended June 30, 2008 and 2007:
Our oil and natural gas revenues and production product mix are displayed in the following
table for the Current and Comparable Quarters.
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|
|
|
Revenues |
|
Production |
|
|
2008 |
|
2007 |
|
2008 |
|
2007 |
Oil |
|
|
51 |
% |
|
|
58 |
% |
|
|
34 |
% |
|
|
49 |
% |
Natural gas |
|
|
49 |
% |
|
|
42 |
% |
|
|
66 |
% |
|
|
51 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(22)
The following table shows our production volumes, product sales prices and operating revenues
for the indicated periods.
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|
|
|
|
Three Months Ended June 30, |
|
|
Increase |
|
|
% Increase |
|
|
|
2008 |
|
|
2007 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
(in thousands except per unit data) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Volumes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
237 |
|
|
|
270 |
|
|
|
(33 |
) |
|
|
(12 |
)% |
Natural gas (Mcf) |
|
|
2,790 |
|
|
|
1,679 |
|
|
|
1,111 |
|
|
|
66 |
% |
BOE |
|
|
702 |
|
|
|
550 |
|
|
|
152 |
|
|
|
28 |
% |
BOE/Day |
|
|
7.7 |
|
|
|
6.0 |
|
|
|
1.7 |
|
|
|
28 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
119.42 |
|
|
$ |
59.24 |
|
|
$ |
60.18 |
|
|
|
102 |
% |
Natural gas (per Mcf) |
|
$ |
9.95 |
|
|
$ |
6.79 |
|
|
$ |
3.16 |
|
|
|
47 |
% |
BOE price |
|
$ |
79.86 |
|
|
$ |
49.81 |
|
|
$ |
30.05 |
|
|
|
60 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
28,322 |
|
|
$ |
15,956 |
|
|
$ |
12,366 |
|
|
|
78 |
% |
Natural gas |
|
|
27,753 |
|
|
|
11,398 |
|
|
|
16,355 |
|
|
|
143 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
56,075 |
|
|
$ |
27,354 |
|
|
$ |
28,721 |
|
|
|
105 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenues
Average wellhead realized crude oil prices increased $60.18 per Bbl, or 102%, to $119.42 per
Bbl in the Current Quarter, over the Comparable Quarter. This price increase resulted in increased
revenues by approximately $14.3 million for the Current Quarter, as compared to the Comparable
Quarter. Oil production decreased 12%, which was attributable to natural production declines of
approximately 33,000 Bbls. This decrease in production is largely due to natural declines in the
Permian Basin area. The decrease in oil production resulted in decreased revenue of approximately
$1.9 million for the Current Quarter.
Natural gas revenues
Average realized wellhead natural gas prices increased $3.16 per Mcf, or 47%, to $9.95 per Mcf
in the Current Quarter, over the Comparable Quarter. This price increase accounted for an increase
in revenue of approximately $8.8 million. Natural gas production increased 66% in the Current
Quarter primarily due to new wells in the New Mexico Wolf Camp and Barnett Shale areas where
volumes were up approximately 444,000 Mcf and 743,000 Mcf, respectively, over the Comparable
Quarter. The overall increase in natural gas volumes increased revenue approximately $7.6 million
for the Current Quarter.
Cost and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
|
Increase |
|
|
% Increase |
|
|
|
2008 |
|
|
2007 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
|
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
|
$ |
7,254 |
|
|
$ |
5,576 |
|
|
$ |
1,678 |
|
|
|
30 |
% |
Production taxes |
|
|
2,996 |
|
|
|
1,194 |
|
|
|
1,802 |
|
|
|
151 |
% |
Production tax refund |
|
|
|
|
|
|
(1,209 |
) |
|
|
1,209 |
|
|
|
(100 |
)% |
General and administrative |
|
|
3,265 |
|
|
|
2,580 |
|
|
|
685 |
|
|
|
27 |
% |
Depreciation, depletion and amortization |
|
|
10,483 |
|
|
|
7,150 |
|
|
|
3,333 |
|
|
|
47 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
23,998 |
|
|
$ |
15,291 |
|
|
$ |
8,707 |
|
|
|
57 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(23)
Lease operating expense
Lease operating expense increased approximately $1.7 million, or 30%, to $7.3 million during
the Current Quarter, compared to $5.6 million for the Comparable Quarter. Lifting cost (excluding
production taxes) increased to $10.33 per BOE for the Current Quarter, compared to $10.15 per BOE
in the Comparable Quarter. The increase was due primarily to higher workover expense from casing
repairs and an increase in gathering and treating costs associated with increased production in the
New Mexico Wolfcamp area. Ad valorem taxes increased in the Current Quarter by $468,000 over the
Comparable Quarter due to an overall increase in our producing property values.
Production taxes
Production taxes increased $1.8 million for the Current Quarter, as compared to the Comparable
Quarter. Production taxes were 5.3% of revenue for the Current Quarter compared to 4.4% of revenue
for the Comparable Quarter. The increase is related to higher natural gas production and higher
tax rates in the New Mexico area. Production taxes in future periods will be a function of product
mix, production volumes, product prices and tax rates.
General and administrative
General and administrative expenses increased 27%, or $685,000, for the Current Quarter, over
the Comparable Quarter. This increase was primarily due to an increase in staffing, salary and
stock based compensation. This increase over the Comparable Quarter was partially offset by lower
franchise taxes, and fees associated with consulting and related services in the Current Quarter.
On a BOE basis, general and administrative costs were $4.65 per BOE in the Current Quarter, as
compared to $4.69 per BOE in the Comparable Quarter.
Depreciation, depletion and amortization
Depreciation depletion and amortization expense increased 47%, or $3.3 million, in the Current
Quarter, over the Comparable Quarter. Total depreciation, depletion and amortization per BOE was
$14.93 for the Current Quarter and $13.00 for the Comparable Quarter. This increase is
attributable to an overall increase in actual and anticipated drilling costs. Increased cost
levels affect both the depletable amounts of capitalized costs in 2008 and the depletion
attributable to amounts of estimated future development costs on proved undeveloped properties. Our
drilling over the past year and our future drilling plans are focused on our natural gas resource
projects which have higher associated per BOE drilling and development costs due to the nature of
the wellbores. These factors, when combined with the increase in the absolute level of our capital
expenditures during this time period, have led to a significant increase in our depletion rate per
BOE.
Other income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
|
Increase |
|
|
% Increase |
|
|
|
2008 |
|
|
2007 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
|
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss on derivatives not classified as hedges |
|
$ |
(71,609 |
) |
|
$ |
(2,170 |
) |
|
$ |
(69,439 |
) |
|
|
3,200 |
% |
Interest and other income |
|
|
32 |
|
|
|
56 |
|
|
|
(24 |
) |
|
|
(43 |
)% |
Interest expense |
|
|
(5,368 |
) |
|
|
(4,312 |
) |
|
|
(1,056 |
) |
|
|
24 |
% |
Other expense |
|
|
(1 |
) |
|
|
21 |
|
|
|
(22 |
) |
|
|
(105 |
)% |
Equity in gain (loss) of pipelines and
gathering system ventures |
|
|
165 |
|
|
|
(289 |
) |
|
|
454 |
|
|
|
157 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(76,781 |
) |
|
$ |
(6,694 |
) |
|
$ |
(70,087 |
) |
|
|
1,047 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(24)
Loss on derivatives not classified as hedges
We
recorded a loss of $(71.6) million in the Current Quarter for derivatives not classified as hedges,
as compared to a loss of $(2.2) million for the Comparable Quarter. The greatest impact of the
change in fair market valuation was within our crude oil contracts due to the significant increase
in oil prices through June 30, 2008. We settled in cash a net of $14.6 million in derivative
contracts during the Current Quarter. See Note 6 to Consolidated
Financial Statements.
Interest expense
Interest expense increased approximately $1.1 million. The Current Quarter included higher
interest expense of approximately $758,000 primarily due to higher average outstanding debt
balances over the Comparable Quarter. The Current Quarter had increased bank fees and note discount
of approximately $159,000 primarily due to the amortized discount on the Senior Notes. Capitalized
interest for the Current Quarter was approximately $(19,000) and $(156,000) for the Comparable
Quarter. Our weighted average interest rate decreased to 8.33% for the Current Quarter, from 8.53%
for the Comparable Quarter.
Equity in gain (loss) of pipelines and gathering system ventures
For the Current Quarter, our investment in the Hagerman Gas Gathering System Joint Venture
recorded a gain of $162,000, compared to a loss of $(291,000) for the Comparable Quarter. This
increase in earnings of $453,000 is the result of increased volumes flowing through the gathering
system from period to period.
In
June 2008, we acquired all of the assets of the Hagerman Gas
Gathering System. Subsequent to the acquisition, the results
of operations of the Hagerman Gas Gathering System will be included in our operating income and not
as an equity gain / loss item in our Consolidated Statement of Operations. See Note 10 to
Consolidated Financial Statements.
Income taxes
Income
tax benefit was approximately $15.5 million in the Current Quarter, as compared to an
expense of approximately $1.9 million in the Comparable Quarter. Income tax expense (benefit) for
2008 will be dependent on our earnings and is expected to be approximately 35% of income (loss)
before income taxes.
Basic and diluted net income (loss)
We had basic and diluted net income (loss) per share of $(.70) and $.09 for Current Quarter
and the Comparable Quarter, respectively. Basic weighted average common shares outstanding
increased from 37.8 million shares in the Comparable Quarter to 41.4 million shares in the Current
Quarter. The increase in common shares was primarily due to our public offering of 3.0 million
shares of common stock in December 2007 and the exercise of employee and nonemployee stock options
in 2007 and 2008 and the exercise of warrants during 2008.
(25)
RESULTS OF OPERATIONS
For the Six Months Ended June 30, 2008 and 2007:
Percentages of our revenues and production, by product mix, are shown in the following table
for the Current Period and Comparable Period.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
Production |
|
|
2008 |
|
2007 |
|
2008 |
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
51 |
% |
|
|
60 |
% |
|
|
35 |
% |
|
|
50 |
% |
Natural gas |
|
|
49 |
% |
|
|
40 |
% |
|
|
65 |
% |
|
|
50 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table shows our production volumes, product sale prices and operating revenues
for the following periods.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
Increase |
|
|
% Increase |
|
|
|
2008 |
|
|
2007 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
(in thousands except per unit data) |
|
Production Volumes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
484 |
|
|
|
543 |
|
|
|
(59 |
) |
|
|
(11 |
)% |
Natural gas (Mcf) |
|
|
5,452 |
|
|
|
3,200 |
|
|
|
2,252 |
|
|
|
70 |
% |
BOE |
|
|
1,393 |
|
|
|
1,076 |
|
|
|
317 |
|
|
|
29 |
% |
BOE/Day |
|
|
7.7 |
|
|
|
5.9 |
|
|
|
1.8 |
|
|
|
31 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
106.32 |
|
|
$ |
55.56 |
|
|
$ |
50.76 |
|
|
|
91 |
% |
Natural gas (per Mcf) |
|
$ |
8.90 |
|
|
$ |
6.34 |
|
|
$ |
2.56 |
|
|
|
40 |
% |
BOE price |
|
$ |
71.80 |
|
|
$ |
46.89 |
|
|
$ |
24.91 |
|
|
|
53 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
51,491 |
|
|
$ |
30,167 |
|
|
|
21,324 |
|
|
|
71 |
% |
Natural gas |
|
|
48,525 |
|
|
|
20,303 |
|
|
|
28,222 |
|
|
|
139 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
100,016 |
|
|
$ |
50,470 |
|
|
$ |
49,546 |
|
|
|
98 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenues
Oil revenues increased $21.3 million, or 71%, in the Current Period, over the Comparable
Period. Oil production decreased largely due to natural declines in the Permian Basin area. The
decrease in oil production decreased revenue approximately $3.3 million for 2008. Wellhead average
realized crude oil prices increased $50.76 per Bbl, or 91%, to $106.32 per Bbl for 2008 over the
Comparable Period. The increase in oil prices increased revenue approximately $24.6 million for
the Current Period.
Natural gas revenues
Natural gas revenues increased $28.2 million, or 139%, in the Current Period, over the
Comparable Period. Natural gas production increased 70%, which was attributable to new wells in
our New Mexico and Barnett Shale areas increasing production approximately 2.4 Bcf, partially
offset by natural declines in our other producing areas. The increase in natural gas volumes
increased revenue approximately $14.3 million in the Current Period. Average realized wellhead
natural gas prices increased $2.56 per Mcf or 40% to $8.90 Mcf in the Current Period over the
Comparable Period, causing an increase in revenue of $13.9 million in the Current Period.
(26)
Cost and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, |
|
|
Increase |
|
|
% Increase |
|
|
|
2008 |
|
|
2007 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
|
$ |
14,233 |
|
|
$ |
9,975 |
|
|
$ |
4,258 |
|
|
|
43 |
% |
Production taxes |
|
|
5,285 |
|
|
|
2,248 |
|
|
|
3,037 |
|
|
|
135 |
% |
Production tax refund |
|
|
|
|
|
|
(1,209 |
) |
|
|
1,209 |
|
|
|
(100 |
)% |
General and administrative |
|
|
5,833 |
|
|
|
5,245 |
|
|
|
588 |
|
|
|
11 |
% |
Depreciation, depletion and amortization |
|
|
19,835 |
|
|
|
13,859 |
|
|
|
5,976 |
|
|
|
43 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
45,186 |
|
|
$ |
30,118 |
|
|
$ |
15,068 |
|
|
|
50 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
Lease operating costs increased approximately $4.3 million, or 43%, to $14.2 million during
the Current Period, from $10.0 million in the Comparable Period. Lifting cost (excluding
production taxes) increased to $10.22 per BOE for the Current Period, compared to $9.27 per BOE in
the Comparable Period. The increase was due primarily to higher workover expense from casing
repairs and an increase in gathering and treating costs associated with increased production in the
New Mexico Wolfcamp area. Ad valorem taxes increased in the Current Period by $900,000 over the
Comparable Quarter due to an overall increase in our producing property values.
Production taxes
Production tax increased $3.0 million, in the Current Period, over the Comparable Period
primarily due to a $49.5 million increase in revenue. Production taxes in future periods will be a
function of product mix, production volumes, product prices and tax rates.
A production tax refund was received in June 2007 in the amount of $1.2 million for gas
production taxes on non-operated wells in the Wilcox area of south Texas for production during the
period from March 2005 through January 2007. These refunds were received by the operator of these
wells after the operators application for tax abatement was approved by state regulatory agencies.
The reduction in our production tax expense was recognized only when approval of the application
for tax abatement was granted by the state.
General and Administrative
Total general and administrative expenses increased 11%, or approximately $588,000, in the
Current Period, over the Comparable Period. The increase in general and administrative costs is
due to higher employee compensation, related benefit costs, stock based compensation and consulting
and contract employees. General and administrative expenses capitalized to the full cost pool were
$842,000 in the Current Period compared to $725,000 in the Comparable Period. On a BOE basis,
general and administrative costs decreased to $4.19 per BOE in the Current Period from $4.87 per
BOE in the Comparable Period.
(27)
Depreciation, depletion and amortization
Depreciation, depletion and amortization expense increased 43%, or $6.0 million, in the
Current Period, over the Comparable Period. Total depreciation, depletion and amortization expense
per BOE was $14.24 for the Current Period and $12.88 for the Comparable Period. This increase is
attributable to an overall increase in actual and anticipated drilling costs and related oilfield
service costs. Increased cost levels affect both the depletable amounts of capitalized costs in
2008 and the depletion attributable to amounts of estimated future development costs on proved
undeveloped properties. Our drilling over the past year and our future drilling plans are focused
on our natural gas resource projects which have higher associated per BOE drilling and development
costs than our drilling projects in the Permian Basin of west Texas and onshore gulf coast of south
Texas due to the use of horizontal drilling and multi-stage stimulation techniques. These factors,
when combined with the increase in the absolute level of our capital expenditures during this time
period, have led to a significant increase in our depletion rate per BOE.
Other income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, |
|
|
Increase |
|
|
% Increase |
|
|
|
2008 |
|
|
2007 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
|
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss on derivatives not classified as hedges |
|
$ |
(93,495 |
) |
|
$ |
(6,605 |
) |
|
$ |
(86,890 |
) |
|
|
1,316 |
% |
Interest and other income |
|
|
65 |
|
|
|
108 |
|
|
|
(43 |
) |
|
|
(40 |
)% |
Interest expense |
|
|
(10,886 |
) |
|
|
(8,020 |
) |
|
|
(2,866 |
) |
|
|
36 |
% |
Other expense |
|
|
(1 |
) |
|
|
(15 |
) |
|
|
14 |
|
|
|
(93 |
)% |
Equity in gain (loss) of pipelines
and gathering system ventures |
|
|
382 |
|
|
|
(594 |
) |
|
|
976 |
|
|
|
(164 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(103,935 |
) |
|
$ |
(15,126 |
) |
|
$ |
(88,809 |
) |
|
|
587 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss on derivatives not classified as hedges
We recorded a loss of $(93.5) million in the Current Period for derivatives not classified as
hedges, as compared to a loss of $(6.6) million for the Comparable Period. The greatest impact of
the change in fair market valuation was within our crude oil contracts due to the significant
increase in oil prices through June 30, 2008. We settled in cash a net of $22.8 million in
derivative contracts during the Current Period. See Note 6 to
Consolidated Financial Statements.
Interest expense
Interest expense increased approximately $2.9 million. The Current Period included higher
interest expense of approximately $2.1 million primarily due to higher average outstanding debt
balances over the Comparable Period. The Current Period had increased bank fees and note discount
of approximately $489,000 primarily due to the amortized discount on the Senior Notes. Capitalized
interest for the Current Period was approximately $(44,000) and $(345,000) for the Comparable
Period. Our weighted average interest rate increased to 8.78% for the Current Period, from 8.52%
for the Comparable Period.
Equity in gain (loss) of pipelines and gathering system ventures
For the Current Period, our investment in the Hagerman Gas Gathering System Joint Venture
recorded a gain of $381,000. This gain compares to a loss of $(599,000) for the Comparable Period.
This increase in earnings of $980,000 is the result of increased volumes flowing through the
system from period to period.
In
June 2008, we acquired all of the assets of the Hagerman Gas
Gathering System. Subsequent to the acquisition, the results
of operations of the Hagerman Gas Gathering System will be included in our operating income and not
as an equity gain/loss item in our Consolidated Statement of Operations. See Note 10 to
Consolidated Financial Statements.
(28)
Income taxes
Income
tax benefit was $17.2 million in the Current Period, compared to an expense of $(1.9)
million in the Comparable Period. Income tax benefit (expense) for 2008 will be dependent on our
earnings and is expected to be approximately 35% of income before income taxes.
Basic and diluted net income (loss)
We had basic and diluted net income (loss) per share of $(0.77) and $0.09 for 2008 and 2007,
respectively. Basic weighted average common shares outstanding increased from approximately 37.7
million shares in 2007 to approximately 41.4 million shares in 2008. The increase was primarily
due to our public offering of 3.0 million shares of common stock in December 2007 and the exercise
of employee and nonemployee stock options in 2007 and 2008 and warrant exercises in 2008.
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 depend on many factors, including the prices we receive for oil and natural gas we produce.
Our
working capital deficit increased approximately $27.7 million as of June 30, 2008,
compared with December 31, 2007. Current liabilities exceeded
current assets by approximately $60.9
million at June 30, 2008. The working capital deficit increase was due to an increase in accounts
payable of approximately $15.1 million and an increase in current derivative obligations of
approximately $32.5 million, offset by an increase in accounts receivable of approximately $8.3
million and an increase in deferred tax assets of approximately $11.2 million.
We incurred net property costs of $125.0 million for the six months ended June 30, 2008,
compared to $74.9 million for the same period in 2007. The increase is primarily related to
drilling activity in the Barnett Shale and in the New Mexico Wolfcamp areas, as well as
acquisitions in our core properties. Included in our property basis for the first six months of
2008 and 2007 were net changes in asset retirement costs of approximately $482,000 and $(385,000),
respectively. See Note 8 to Consolidated Financial Statements.
Our capital investment budget will be funded from our estimated operating cash flows and our
bank borrowings. If our cash flows and bank borrowings are not sufficient to fund all of our
estimated capital expenditures, we may fund any shortfall with proceeds from the sale of our debt
or equity securities, reduce our capital budget or effect a combination of these alternatives. The
amount and timing of our expenditures are subject to change based upon market conditions, results
of expenditures, new opportunities and other factors.
If our revenues or the borrowing base under our revolving credit facility decrease as a result
of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other
reason, we may have limited ability to obtain the capital necessary to undertake or complete future
drilling projects. We may, from time to time, seek additional financing, either in the form of
increased bank borrowings, sale of debt or equity securities or other forms of financing and there
can be no assurance as to the availability of any additional financing upon terms acceptable to us.
Stockholders equity at June 30, 2008 was $205.6 million, as compared to $235.3 million at
December 31, 2007. The decrease is primarily attributable to our net loss of approximately $(31.9)
million.
(29)
Bank Borrowings
In the past, we have maintained two separate credit facilities. One of these credit facilities
is our Fourth Amended and Restated Credit Agreement, dated May 16, 2008, or Revolving Credit
Agreement, with a group of bank lenders which provide us with a revolving line of credit having a
borrowing base limitation of $230.0 million at June 30, 2008. The total amount that we can borrow
and have outstanding at any one time is limited to the lesser of $600.0 million or the borrowing
base established by the lenders. At June 30, 2008, the principal amount outstanding under our
revolving credit facility was $137.0 million, excluding $445,000 reserved for our letters of
credit. Unamortized
fees in the amount of $875,000 related to the prior Revolving Credit
Agreement have been rolled into the current Revolving Credit
Agreement, as amended, and will be amortized over the remaining term
of five years.
Our second credit facility was a five year term loan facility provided to us under a Second
Lien Term Loan Agreement, or the Second Lien Agreement, with a group of banks and other lenders.
The Second Lien Agreement was paid off and terminated on July 31, 2007 with our payment to the
lenders of $50.2 million, including interest.
Revolving Credit Facility
Our Revolving Credit Agreement allows us to borrow, repay and reborrow amounts available under
the revolving credit facility. The amount of the borrowing base is based primarily upon the
estimated value of our oil and natural gas reserves. The borrowing base 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 revolving
credit facility in an amount equal to the excess. Except for 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 banks base rate or
the LIBOR rate, at our election. Generally, the banks base rate is equal to its prime rate as
announced by it from time to time.
The LIBOR rate is generally equal to the sum of (a) the rate designated as British Bankers
Association Interest Settlement Rates and offered in one, two, three, six or twelve month interest
periods for deposits of $1.0 million, and (b) a margin ranging from 2.00% to 2.50%, depending upon
the outstanding principal amount of our loan. 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 4.75%. At June 30, 2008, base rate plus the applicable margin, was 5.0% on
$137.0 million, the outstanding principal amount of our revolving loan on that same date.
In the case of base rate loans, interest is payable on the last day of each month. In the case
of LIBOR loans, interest is payable on the last day of each applicable interest period; provided
that if the applicable interest period is longer than three months, interest is payable at
three-month intervals following the first day of such interest period.
If the total outstanding borrowings under the revolving credit facility are less than the
borrowing base, we are required to pay an unused commitment fee to the lenders in an amount equal
to .25% of the daily average of the unadvanced portion of the borrowing base. The fee is payable
quarterly.
If the borrowing base is increased, we are also required to pay a fee of .375% on the amount
of any increase.
(30)
The Revolving Credit Agreement contains various restrictive covenants, including (i)
maintenance of a minimum current ratio, (ii) maintenance of a maximum ratio of funded indebtedness
to earnings before interest, income taxes, depreciation, depletion and amortization, (iii)
maintenance of a minimum net worth, (iv) prohibition of payment of dividends and (v) restrictions
on incurrence of additional debt. We have pledged substantially all of our producing oil and
natural gas properties to secure the repayment of our indebtedness under the Revolving Credit
Agreement.
All outstanding principal and accrued and unpaid interest under the revolving credit facility
is due and payable on December 31, 2013. 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 June 30, 2008 we were in compliance with all of the covenants in our Revolving Credit
Agreement.
Senior Notes
On July 31, 2007, we completed a private offering of unsecured senior notes, or the senior
notes, in the principal amount of $150.0 million. The senior notes mature on August 1, 2014 and
bear interest at 10.25% which is payable semi-annually beginning on February 1, 2008. Prior to
August 1, 2010, we may redeem up to 35% of the senior notes for a price equal to 110.250% of the
original principal amount of the senior notes with the proceeds of certain equity offerings. On or
after August 1, 2011 we may redeem all or some of the senior notes at a redemption price that will
decrease from 105.125% of the principal amount of the senior notes to 100% of the principal amount
on August 1, 2013. In addition, prior to August 1, 2011, we may redeem some or all of the senior
notes at a redemption price equal to 100% of the principal amount of the senior notes to be
redeemed, plus a make-whole premium, plus any accrued and unpaid interest. Generally, the
make-whole premium is an amount equal to the greater of (a) 1% of the principal amount of the
senior notes being redeemed and (b) the excess of the present value of the redemption price of such
notes as of August 1, 2011 plus all required interest payments due through August 1, 2011 (computed
at a discount rate equal to a specified U.S. Treasury Rate plus 50 basis points), over the
principal amount of the senior notes being redeemed.
The indenture governing the senior notes restricts our ability to: (i) borrow money; (ii)
issue redeemable and preferred stock; (iii) pay distributions or dividends; (iv) make investments;
(v) create liens without securing the senior notes; (vi) enter into agreements that restrict
dividends from subsidiaries; (vii) sell certain assets or merge with or into other companies;
(viii) enter into transactions with affiliates; (ix) guarantee indebtedness; and (x) enter into new
lines of business.
Interest Accrued
For the Current Period, the aggregate interest accrued under our Revolving Credit Agreement
and our senior notes was approximately $10.3 million. Bank fees
and note discount amortization was
approximately $621,000 for the Current Period and interest capitalized was approximately $44,000.
Commodity Price Risk Management Transactions and Effects of Derivative Instruments
The purpose of our derivative transactions is to provide a measure of stability in our cash
flows. The derivative trade arrangements we have employed include collars, costless collars,
floors or purchased puts, and oil, natural gas and interest rate swaps.
At June 30, 2008 we had no derivatives in place that were designated as cash flow hedges. All
commodity derivative contracts at June 30, 2008 were accounted for by mark-to-market accounting
whereby changes in fair value were charged to earnings. Changes in the fair values of derivatives
are recorded in our Consolidated Statements of Operations as these changes occur in Other income
(expense),
(31)
net. To the extent these trades relate to production in 2008 and beyond, and oil prices
increase, we will report a loss currently, but if there are no further changes in prices, our
revenue will be correspondingly higher (than if there had been no price increase) when the
production is sold.
All interest rate swaps that we have entered into for 2008 and beyond are accounted for by
mark-to-market accounting as prescribed in SFAS 133.
We are exposed to credit risk in the event of nonperformance by the counterparties to our
derivative trade instruments. However, we periodically assess the creditworthiness of the
counterparties to mitigate this credit risk.
We adopted SFAS No. 157 Fair Value Measurement effective January 1, 2008 to measure fair
value of our derivatives which had no significant effect on our financial position or operating
results.
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 obligations
and commitments, we do not believe there will 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 June 30, 2008:
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Obligation Due in Period |
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Six Months |
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ending |
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December 31, |
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Years ended December 31, |
|
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After |
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|
Contractual Cash Obligations |
|
2008 |
|
|
2009 |
|
|
2010 |
|
|
2011 |
|
|
2012 |
|
|
5 years |
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Total |
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|
|
($ in thousands) |
|
Revolving Credit Facility
(secured)(1) |
|
$ |
3,444 |
|
|
$ |
6,850 |
|
|
$ |
6,850 |
|
|
$ |
6,850 |
|
|
$ |
6,869 |
|
|
$ |
143,850 |
|
|
$ |
174,713 |
|
Senior Notes (unsecured)(2) |
|
|
7,688 |
|
|
|
15,375 |
|
|
|
15,375 |
|
|
|
15,375 |
|
|
|
15,375 |
|
|
|
180,750 |
|
|
|
249,938 |
|
Office Lease (Dinero Plaza) |
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|
135 |
|
|
|
271 |
|
|
|
107 |
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31 |
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|
|
544 |
|
Asset retirement obligations(3) |
|
|
736 |
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|
|
151 |
|
|
|
78 |
|
|
|
75 |
|
|
|
36 |
|
|
|
4,530 |
|
|
|
5,606 |
|
Derivative obligations |
|
|
39,445 |
|
|
|
44,129 |
|
|
|
27,224 |
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|
|
|
|
|
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|
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|
|
|
|
|
110,798 |
|
Put
obligations(4) |
|
|
|
|
|
|
646 |
|
|
|
1,378 |
|
|
|
1,689 |
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|
|
|
|
|
|
|
|
|
|
3,713 |
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|
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|
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Total |
|
$ |
51,448 |
|
|
$ |
67,422 |
|
|
$ |
51,012 |
|
|
$ |
24,020 |
|
|
$ |
22,280 |
|
|
$ |
329,130 |
|
|
$ |
545,312 |
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(1) |
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Outstanding principal of $137.0 million due December 31, 2013 and estimated interest
obligation calculated using the interest rate at June 30, 2008 of 5.0%. |
|
(2) |
|
Outstanding principal of $150.0 million due
August 1, 2014 and interest
obligation calculated at an interest rate of 10.25%. |
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(3) |
|
Asset retirement obligations of oil and natural gas assets, excluding salvage
value. |
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(4) |
|
The put obligations above represent the undiscounted
obligation to our counterparty. The will recognize $382,000 of
interest associated with the put obligations over the remaining life of the
contracts. |
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:
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internally generated cash from operations; |
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proceeds from bank borrowings; and |
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proceeds from sales of equity and debt securities. |
(32)
The continued availability of these capital sources depends upon a number of variables,
including:
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our proved reserves; |
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the volumes of oil and natural gas we produce from existing wells; |
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the prices at which we sell oil and natural gas; and |
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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:
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increased bank borrowings; |
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additional sales of our debt or equity securities; |
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sales of non-core properties; |
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other forms of financing; or |
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a combination of the above. |
Except for the revolving credit facility we have with our bank lenders, we do not currently
have any agreements for any future financing and there can be no assurance as to the availability
or terms of any such future financing.
Inflation
Our drilling and production costs have escalated and we expect this trend to continue.
However, over the past several years our commodity prices have increased to offset the effects of
cost inflation.
Oil and Natural Gas Price Trends
Changes in oil and natural gas prices significantly affect our revenues, financial condition,
cash flows and borrowing capacity. Markets for oil and natural gas have historically been volatile
and we expect this trend to continue. 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. Although we are unable to accurately predict the prices we
receive for our oil and natural gas, any significant or sustained declines in oil or natural gas
prices may materially adversely affect our financial condition, liquidity, ability to obtain
financing and operating results. Lower oil or natural gas prices also may reduce the amount of oil
or natural gas that we can produce economically. A decline in oil or natural gas prices could have
a material adverse effect on the estimated value and estimated quantities of our oil and natural
gas reserves, our ability to fund our operations and our financial condition, cash flow, results of
operations and access to capital.
Our capital expenditure budgets are highly dependent on future oil and natural gas prices.
For the six months ended June 30, 2007, the average realized sales price for our oil and
natural gas was $46.89 per BOE. For the six months ended June 30, 2008, our average realized price
was $71.80 per BOE.
Production Trends
Like all other oil and gas exploration and production companies, we experience natural
production declines. We recognize that oil and gas production from a given well naturally
decreases over time and that
(33)
a downward trend in our overall production could occur unless these natural declines are
offset by additional production from drilling, workover or recompletion activity, or acquisitions
of producing properties. If any production declines we experience are other than a temporary
trend, and if we cannot economically replace our reserves, our results of operations may be
materially adversely affected and our stock price may decline. Our future growth will depend upon
our ability to continue to add oil and natural gas reserves in excess of production at a reasonable
cost.
While we have achieved increased production and revenue in our New Mexico Wolfcamp and Barnett
Shale projects as a result of our significant investments in these areas, production growth in our
Barnett Shale investments has been restricted due to limited pipeline capacity.
In recent periods, we have concentrated our drilling and development efforts on our resource
natural gas projects in our Barnett Shale and New Mexico Wolfcamp projects. Due to limited
development, our production has decreased in accordance with normal decline curves for our
principal Permian Basin oil properties and south Texas gas properties. We expect our 2008
capital spending for our Permian Basin oil properties to increase.
Lease Operating Expense Trends
The level of drilling, workover and maintenance activity in the primary areas in which we
operate and produce continues at a historically high level. Service rates charged by oil field
service companies have increased significantly during recent periods. These increased cost levels
have affected our per BOE lease operating expense. While we do not expect the rate of increase of
service costs to continue at the same pace as in recent periods, further increases are possible and
could significantly impact our lease operating expense. However, as we continue to increase our
production we also expect to see a leveling off of our per BOE lease operating expenses.
Interest Expense Trends
On July 31, 2007 we completed a private offering of $150.0 million of senior notes that bear
interest at 10.25%. As a result of the issuance of the notes and the increase in our current
borrowings, we expect a corresponding increase in our annual interest expense. An increase in
interest rates will also negatively impact our interest expense.
Recent Accounting Pronouncements
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS 157), which
defines fair value, establishes a framework for measuring fair value in accordance with generally
accepted accounting principles, and expands disclosures about fair value measurements. This
statement does not require any new fair value measurements but may require some entities to change
their measurement practices. We adopted SFAS No. 157 effective January 1, 2008 and the adoption
did not have a significant effect on our financial position or operating results.
In February 2007, the FASB issued SFAS 159, The Fair Value Option for Financial Assets and
Financial Liabilities, Including an Amendment of FASB Statement No. 115, (FAS 159) which became
effective on January 1, 2008. FAS 159 permits entities to measure eligible financial assets,
financial liabilities and firm commitments at fair value, on an instrument-by-instrument basis,
that are otherwise not permitted to be accounted for at fair value under other generally accepted
accounting principles. The fair value measurement election is irrevocable and subsequent changes in
fair value must be recorded in earnings. This statement, for us, became effective in the first
quarter of 2008 and it did not have any effect on our financial position or operating results as we
did not elect to apply the Fair Value Method.
(34)
In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (SFAS
141(R)), which replaces FASB Statement No. 141. SFAS 141(R) establishes principles and
requirements for how an acquirer recognizes and measures in its financial statements the
identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree
and the goodwill acquired. The statement also establishes disclosure requirements that will enable
users to evaluate the nature and financial effects of the business combination. SFAS 141(R) is
effective for acquisitions that occur in an entitys fiscal year that begins after December 15,
2008, which will be our fiscal year 2009. The impact, if any, will depend on the nature and size of
business combinations that we consummate after the effective date.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated
Financial Statementsan amendment of ARB No. 51 (SFAS 160). SFAS 160 requires that accounting
and reporting for minority interests will be recharacterized as noncontrolling interests and
classified as a component of equity. SFAS 160 also establishes reporting requirements that provide
sufficient disclosures that clearly identify and distinguish between the interests of the parent
and the interests of the noncontrolling owners. SFAS 160 applies to all entities that prepare
consolidated financial statements, except not-for-profit organizations, but will affect only those
entities that have an outstanding noncontrolling interest in one or more subsidiaries or that
deconsolidate a subsidiary. This statement is effective as of the beginning of an entitys first
fiscal year beginning after December 15, 2008, which will be our fiscal year 2009. Based upon our
balance sheet, the statement would have no impact.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and
Hedging Activities, an amendment of FASB Statement No. 133 (SFAS 161). This statement is intended
to improve transparency in financial reporting by requiring enhanced disclosures of an entitys
derivative instruments and hedging activities and their effects on the entitys financial position,
financial performance, and cash flows. SFAS 161 applies to all derivative instruments within the
scope of SFAS 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133), as
well as related hedged items, bifurcated derivatives, and nonderivative instruments that are
designated and qualify as hedging instruments. Entities with instruments subject to SFAS 161 must
provide more robust qualitative disclosures and expanded quantitative disclosures. SFAS 161 is
effective prospectively for financial statements issued for fiscal years and interim periods
beginning after November 15, 2008, with early application permitted. We are currently evaluating
the disclosure implications of this statement.
Critical Accounting Policies
Our critical accounting policies are included and discussed in our Annual Report on Form 10-K
for the year ended December 31, 2007, as filed with the Securities and Exchange Commission on
February 20, 2008. These critical accounting policies 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 included in our Annual Report on Form 10-K for the
year ended December 31, 2007.
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:
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our future financial and operating performance and results; |
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our drilling plans and ability to secure drilling rigs to effectuate our plans; |
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production volumes; |
(35)
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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; |
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number and location of planned wells; |
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our future commodity price risk management activities; and |
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our plans and forecasts. |
We have based these forward-looking statements on our current assumptions, expectations and
projections about future events.
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 from our expectations.
We believe the assumptions and expectations reflected in these forward-looking statements are
reasonable. However, we cannot give any assurance that our expectations will prove to be correct
or that we will be able to take any actions that are presently planned. All of these statements
involve assumptions of future events and risks and uncertainties. Risks and uncertainties
associated with forward-looking statements include, but are not limited to:
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fluctuations in prices of oil and natural gas; |
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dependent on key personnel; |
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reliance on technological development and technology development programs; |
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demand for oil and natural gas; |
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losses due to potential or future litigation; |
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future capital requirements and availability of financing; |
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geological concentration of our reserves; |
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risks associated with drilling and operating wells; |
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competition; |
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general economic conditions; |
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governmental regulations and liability for environmental matters; |
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receipt of amounts owed to us by purchasers of our production and counterparties to
our hedging contracts; |
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hedging decisions, including whether or not to hedge; |
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events similar to 911; |
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actions of third party co-owners of interests in properties in which we also own an
interest; and |
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fluctuations in interest rates and availability of capital. |
For these and other reasons, actual results may differ materially from those projected or
implied.
(36)
We believe it is important to communicate our expectations of future performance to our
investors. However, events may occur in the future that we are unable to accurately predict, or
over which we have no control. We caution you against putting undue reliance on forward-looking
statements or projecting any future results based on such statements.
Before you invest in our common stock, 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 13 of our Form 10-K for the year ended December 31, 2007.
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ITEM 3. |
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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
The following quantitative and qualitative information is provided about market risks and
derivative instruments to which we were a party at June 30, 2008, and from which we may incur
future earnings, gains or losses from changes in market interest rates and oil and natural gas
prices.
Interest Rate Sensitivity as of June 30, 2008
Although we are currently protected from interest rate volatility through our senior notes and
our interest rate swaps, we believe that in the future we will be exposed to interest rate
volatility as our borrowings increase and as our interest rate swaps are settled. 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 interest rates by expected maturity dates. Refer to Note 3 of the Consolidated Financial
Statements for further discussion of our debt that is sensitive to interest rates.
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2012 and |
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2008 |
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2009 |
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2010 |
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2011 |
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after |
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Total |
|
|
($ in thousands, except interest rates) |
Revolving Credit Facility (secured) |
|
$ |
|
|
|
$ |
|
|
|
$ |
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|
|
$ |
|
|
|
$ |
137,000 |
|
|
$ |
137,000 |
|
Average interest rate |
|
|
5.00 |
% |
|
|
5.00 |
% |
|
|
5.00 |
% |
|
|
5.00 |
% |
|
|
5.00 |
% |
|
|
|
|
Senior notes |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
150,000 |
|
|
$ |
150,000 |
|
Average interest rate |
|
|
10.25 |
% |
|
|
10.25 |
% |
|
|
10.25 |
% |
|
|
10.25 |
% |
|
|
10.25 |
% |
|
|
|
|
At June 30, 2008, we had outstanding bank loans in the aggregate principal amount of $137.0
million at a base interest rate of 5.0%. Under our revolving credit facility, we may elect an
interest rate based upon the agent banks base lending rate or the LIBOR rate, plus a margin
ranging from 2.00% to 2.50% per annum, depending upon the outstanding principal amount of the
loans. The interest rate we are required to pay, including the applicable margin, may never be less
than 4.75%.
At June 30, 2008, we had outstanding senior notes in the aggregate principal amount of $150.0
million bearing interest at a rate of 10.25% per annum. The carrying value of our 10.25% senior
notes at June 30, 2008 is approximately $145.6 million. Interest on our senior notes and their
carrying value are not affected by changes in interest rates.
We have employed fixed interest rate swap contracts with BNP Paribas and Citibank, N.A. based
on the 90-day LIBOR rates at the time of the contract. These contracts are accounted for by
mark-to-market accounting as prescribed in SFAS 133. As of June 30, 2008, the fair market value
of these interest rate swaps was a liability of approximately $2.1 million.
(37)
A recap for the period of time, notional amounts, fixed interest rates, and fair market value
of these contracts at June 30, 2008 follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional |
|
|
Weighted Average |
|
|
Estimated |
|
Period of Time |
|
Amounts |
|
|
Fixed Interest Rates |
|
|
Fair Market Value |
|
|
|
($ in millions) |
|
|
|
|
|
|
($ in thousands) |
|
July 1, 2008 through December 31, 2008 |
|
$ |
100 |
|
|
|
4.86 |
% |
|
$ |
(997 |
) |
January 1, 2009 through December 31, 2009 |
|
$ |
50 |
|
|
|
5.06 |
% |
|
|
(774 |
) |
January 1, 2010 through October 31, 2010 |
|
$ |
50 |
|
|
|
5.15 |
% |
|
|
(352 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
$ |
(2,123 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Price Sensitivity
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. NYMEX closing oil prices ranged from
a low of $50.48 per barrel to
a high of $70.68 per barrel during the six months ended June 30, 2007. NYMEX closing natural gas
prices during the six months ended June 30, 2007 ranged from a
low of $6.16 per Mcf to a high of
$8.19 per Mcf. During the six months ended June 30, 2008 NYMEX closing oil prices ranged from a
low of $86.99 to a high of $140.21. NYMEX closing natural gas prices during the six months ended
June 30, 2008 ranged from a low of $7.62 per Mcf to a high of $13.35 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 June 30, 2008, we had employed costless collars,
puts and swaps in order to protect against this price volatility. Although all of the contracts
that we have entered into are viewed as protection against this price volatility, all contracts are
accounted for by the mark-to-market accounting method as prescribed in SFAS 133.
At June 30, 2008 we had oil collar, put and swap derivative contracts in place covering future
oil production of approximately 1.9 million barrels. Although oil futures prices have decreased
since June 30, 2008, the estimated future settlement payments still continue to exceed the capped
price for each of our collars. If futures prices remain at these levels we will be required to
remit the excess of the NYMEX price for each settlement period over the cap price contained in
the respective collar contract as detailed in the tables below. Changes in oil prices will also
impact our net settlement payments under commodity swap contracts. While settlement payments on
our collar and swap contracts could be significant, these payments should not significantly affect
our cash flow since payments made to counterparties to these contracts should be substantially
offset by commodity prices received on the actual sale of our production. Changes in oil prices
will affect the fair value of our oil contracts as recorded in our balance sheet during future
periods and, consequently, our reported net earnings. Changes in the recorded fair value of
commodity derivatives are marked to market through earnings. If oil prices increase, this negative
effect on earnings will become more significant. However, if oil prices decrease, the negative
effect on earnings that we have experienced in recent periods will be reversed to the extent of the
price change. We are currently unable to estimate the effects on earnings in future periods, but
based on the volume of future oil production covered by the oil derivative contracts, the effects
may be material.
At June 30, 2008 we had natural gas collar derivative contracts in place covering future
natural gas production of approximately 5.1 Bcf. Natural gas futures prices have decreased since
the end of the quarter and we do not anticipate payment to our counterparties for a majority of
these contracts at settlement date if prices remain at these levels. Changes in natural gas prices
will affect the fair value of our natural gas contracts as recorded on our balance sheet during future periods and consequently, our
reported net
(38)
earnings. Changes in the recorded fair value of commodity derivatives are marked to
market through earnings. We are currently unable to estimate the effects on earnings in future
periods, but based on the volume of future natural gas production covered by the natural gas
derivative contracts, the effects may be material.
Descriptions of our active commodity derivative contracts as of June 30, 2008 are set forth
below:
Put Options. Puts are an option to sell an asset. For any put transaction, the
counterparty is required to make a payment to the Company if the reference floating price for any
settlement period is less than the put or floor price for such contract.
In June 2008 we entered into multiple put contracts with BNP Paribas. In lieu of making
premium payments for the puts at the time of entering into our put contracts, we deferred payment
until the settlement dates of the contract. Future payments will be netted against any payments
that the counterparty may owe to us based on the floating price. We have accrued a liability as of
June 30, 2008 of $3.331 million for the purchase price of the puts, and we will pay a premium for
these puts due to the deferral of the payments until the settlement dates. The premiums associated
with these puts will be treated as interest expense and will have an effective interest rate
between 4.3% and 5.7%.
A summary of our put positions at June 30, 2008 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
Barrels of |
|
|
|
|
|
|
Fair Market |
|
Period of Time |
|
Oil |
|
|
Floor |
|
|
Value |
|
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
|
|
January 1, 2009 through December 31, 2009 |
|
|
109,500 |
|
|
$ |
100.00 |
|
|
$ |
505 |
|
January 1, 2010 through December 31, 2010 |
|
|
134,100 |
|
|
$ |
100.00 |
|
|
|
1,087 |
|
January 1, 2011 through December 31, 2011 |
|
|
146,000 |
|
|
$ |
100.00 |
|
|
|
1,308 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
$ |
2,900 |
|
|
|
|
|
|
|
|
|
|
|
|
|
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 June 30, 2008 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
Barrels of |
|
|
NYMEX Oil Prices |
|
|
Fair Market |
|
Period of Time |
|
Oil |
|
|
Floor |
|
|
Cap |
|
|
Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
|
|
July 1, 2008 through December 31, 2008 |
|
|
174,800 |
|
|
$ |
63.42 |
|
|
$ |
83.86 |
|
|
$ |
(9,941 |
) |
January 1, 2009 through December 31, 2009 |
|
|
620,500 |
|
|
$ |
63.53 |
|
|
$ |
80.21 |
|
|
|
(36,970 |
) |
January 1, 2010 through October 31, 2010 |
|
|
486,400 |
|
|
$ |
63.44 |
|
|
$ |
78.26 |
|
|
|
(28,180 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MMBtu of |
|
|
WAHA Gas Prices |
|
|
|
|
|
|
|
Natural Gas |
|
|
Floor |
|
|
Cap |
|
|
|
|
|
|
July 1, 2008 through December 31, 2008 |
|
|
1,840,000 |
|
|
$ |
7.38 |
|
|
$ |
9.28 |
|
|
|
(5,455 |
) |
January 1, 2009 through December 31, 2009 |
|
|
3,285,000 |
|
|
$ |
7.06 |
|
|
$ |
9.93 |
|
|
|
(7,472 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(88,018 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(39)
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 June 30, 2008 for these swaps follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
Barrels of |
|
|
NYMEX Oil |
|
|
Fair Market |
|
Period of Time |
|
Oil |
|
|
Swap Price |
|
|
Value |
|
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 1, 2008 through December 31, 2008 |
|
|
220,800 |
|
|
$ |
33.37 |
|
|
$ |
(23,557 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
ITEM 4. CONTROLS AND PROCEDURES
As of the end of the period covered by this Quarterly Report on Form 10-Q, the effectiveness
of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities
Exchange Act of 1934, as amended) was evaluated by our management, with the participation of 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, as amended. Based on that evaluation, Mr. Oldham and Mr. Foster have
concluded that our disclosure controls and procedures were effective as of June 30, 2008 to provide
reasonable assurance that information required to be disclosed in our reports filed or submitted
under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to
management and recorded, processed, summarized and reported within the time periods specified in
the SECs rules and forms.
There were no changes in our internal control over financial reporting that occurred during
our last fiscal quarter that have materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting.
PART II OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
From time to time, we are party to ordinary routine litigation incidental to our business.
On April 14, 2008, we were added as a defendant to a lawsuit filed in 2007, styled Brady
Briscoe vs. Capstar Drilling, L.P. (Capstar), Cause No. 21,287, in the 259th District Court of
Jones County, Texas. The plaintiff has alleged that he was injured as the result of an accident
while he was working, as an employee of an unrelated third party, on a drilling rig
operated by Capstar. Capstar was conducting drilling operations for us. The plaintiff has asserted
general allegations of negligence as to Capstar and, specifically, a failure to properly equip its
drilling rig, further alleging we were in charge of the drilling rig and the operational details
of the plaintiffs work. The plaintiff has sued for an amount of actual damages of up to $15.0
million, together with pre-judgment interest, post-judgment interest and exemplary damages.
Capstar recently settled with the plaintiff and Capstar has been (or is soon to be) dismissed from
the lawsuit. If judgment is entered against us, we would be entitled to a credit for the amount
that the plaintiff has already received from Capstar.
(40)
Even though we cannot predict the ultimate outcome of this matter, we believe we have
meritorious defenses and intend to vigorously contest this lawsuit. We have not established a
reserve with respect to the plaintiffs claims.
On March 24, 2008, a lawsuit was filed in the 24th District Court of Jackson
County, Texas, against us and twenty-two other defendants in Cause No. 07-6-13069, styled Tony
Kubenka, Carolyn Kubenka, Dennis J. Kallus, David J. Kallus, Mary L. Kallus, Patricia Kallus, Nova
Deleon, Janie Figuerova, and Larkin Thedford, Plaintiffs v. Tri-C Resources, Inc., Marie S. Adian,
Laura E. Adian, Glenn A. Fiew, Lynn Kramer, Debra Boysen, Carol J. Gleason, Alana Sue Curlee,
Connie W. Marthiljohni, Claire E. Adian, Zachary D. Adian, Donald R. Starkweather, Inc., D.A.
Webernick, Danette Bundick, Johnny A. Webernick, Donna Gail Glover, Sherry Shulze, William H.
Webernick, Jr., TAC Resources, Inc., New Century Exploration, Inc., Allegro Investments, Inc. and
Welper Interests, LP.
The nine plaintiffs in this lawsuit have named us and the other working interest owners,
including Tri-C Resources, Inc., the operator, as defendants. The plaintiffs in this lawsuit allege
that they are royalty owners under oil and gas leases which are part of a pooled gas unit (the
unit) located in Jackson County, Texas, and that the defendants, including us, are owners of the
leasehold estate under the plaintiffs leases and others forming the unit. Plaintiffs also assert
that one of the leases (other than plaintiffs leases) forming part of the unit has terminated and,
as a result, the defendants have not properly computed the royalties due to plaintiffs from unit
production and have failed to properly pay royalties due to them. Plaintiffs have sued for an
unspecified amount of damages, including exemplary damages, under theories of breach of contract
(including breach of express and implied covenants of their leases) and conversion, and seek an
accounting, a declaratory judgment to declare the rights of the parties under the leases, and
attorneys fees, interest and court costs.
If a judgment adverse to the defendants was entered, as a working interest owner in the leases
comprising the unit, we believe our liability would be proportionate to the ownership of the other
working interest owners in the leases. We have filed an answer denying any liability. Although an
initial exchange of discovery has occurred, we cannot predict the ultimate outcome of this matter,
we believe we have meritorious defenses and intend to vigorously contest this lawsuit. We have not
established a reserve with respect to plaintiffs claims.
We received a Notice of Proposed Adjustment from the Internal Revenue Service, or the
Service in May 2007 advising us of proposed adjustments to federal income tax of approximately
$2.0 million for the years 2004 and 2005. Subsequent discussions with the Service placed the
issues contested in a development status. In November 2007, the Service issued a letter on the
matter giving the company 30 days to agree or disagree with a final examination report. The final
examination report reflected revisions of the previous proposed adjustments resulting in a reduced
$1.1 million of additional income tax and interest charges. The decrease in proposed tax was the
result of information supplied by us to the examiner as well as discussions of the applicable tax
statutes and regulations. In December 2007, we filed a protest documenting our complete
disagreement with the adjustments proposed on the final examination report and requested a
conference with the appeals office of the Service. The examination office of the Service filed a
response to our protest in February 2008 with the appeals office. On June 4, 2008, our
representatives met with the Services Appeals Officer to review specific issues related to our
calculation of net income from oil and gas and the associated treatment of certain deductions.
During this meeting we were advised that a request to issue an advisory opinion had been
submitted to the National Office of the Service. Pending issuance of this advisory opinion, we will
submit an amendment to our initial protest in further support of our position. We intend to
vigorously contest the adjustment proposed by the Service and believe that we will ultimately
prevail in our position. We have not recorded a liability for tax, interest, or penalties related
to this matter based on our analysis. If a liability for additional income tax should later be
determined to be more likely than not, we anticipate the adjustment to increase the federal income
tax liability would be offset by an increase to a deferred tax asset and would not result in a
charge to earnings. Any interest or penalties resulting from a subsequent determination of
increased tax liability would require a charge to
(41)
earnings. We believe that the effects of this matter would not have a material effect on our
results of operations for the fiscal quarter in which we actually incur or establish a reserve
account for interest or penalties.
We are also presently a named defendant in one other lawsuit arising out of our operations in
the normal course of business, which we believe is not material.
We are not aware of any legal or governmental proceedings against us, or contemplated to be
brought against us, under the various environmental protection statutes to which we are subject,
nor have we 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, 2007.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
At our annual meeting of stockholders held on May 28, 2008, the stockholders approved the
Parallel Petroleum Corporation 2008 Long-Term Incentive Plan. As previously reported in our
Current Report on Form 8-K filed with the Securities and Exchange Commission on June 18, 2008, a
portion of our non-employee Directors fees was paid on June 12, 2008, in the form of grants of
shares of common stock having a fair market value of $40,000. The number of shares awarded to each
non-employee Director was determined by dividing $40,000 by $20.91, the closing price of our common
stock on the Nasdaq Global Market on the date of grant. A total of 7,648 shares of common stock
were granted to four non-employee Directors as follows: Jeffrey G. Shrader 1,912 shares; Edward
A. Nash 1,912 shares; Martin B. Oring 1,912 shares; and Ray M. Poage 1,912 shares. In
addition, on that same date, an additional restricted stock award was granted to Mr. Nash for
10,000 shares of stock. These shares vest in four equal increments on June 12th of each
year, commencing on June 12, 2008. The shares of common stock were issued without registration
under the Securities Act of 1933, as amended, in reliance on the exemption provided by Section 4(2)
of the Securities Act.
Under our 2004 Non-Employee Director Stock Grant Plan, each non-employee Director is entitled
to receive an annual retainer fee consisting of shares of common stock that are automatically
granted on the first day of July in each year. The actual number of shares received is determined
by dividing $25,000 by the average daily closing price of the common stock on the Nasdaq Global
Market for the ten consecutive trading days commencing fifteen trading days before the first day of
July of each year ($21.664). Effective July 1, 2008, in accordance with the terms of the plan, a
total of 4,612 shares of common stock were granted to four non-employee Directors as follows:
Jeffrey G. Shrader 1,153 shares; Edward A. Nash 1,153 shares; Martin B. Oring 1,153
shares; and Ray M. Poage 1,153 shares. The shares of common stock were issued without
registration under the Securities Act of 1933, as amended, in reliance on the exemption provided by
Section 4(2) of the Securities Act. Generally, shares issued under this plan are not transferable
as long as the non-employee Director holding the shares remains a Director of the Company.
(42)
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Our annual meeting of stockholders was held on May 28, 2008. At the meeting, the following
five persons were elected to serve as directors of Parallel for a term of one year expiring in 2009
and until their respective successors are duly qualified and elected: (1) Edward A. Nash, (2)
Larry C. Oldham, (3) Martin B. Oring, (4) Ray M. Poage, and (5) Jeffrey G. Shrader. Set forth below
is a tabulation of votes with respect to each nominee for director.
|
|
|
|
|
|
|
|
|
NAME |
|
VOTES CAST FOR |
|
VOTES WITHHELD |
|
|
|
|
|
|
|
|
|
Edward A. Nash |
|
|
37,556,042 |
|
|
|
544,485 |
|
Larry C. Oldham |
|
|
37,719,715 |
|
|
|
380,812 |
|
Martin B. Oring |
|
|
37,547,737 |
|
|
|
552,790 |
|
Ray M. Poage |
|
|
37,548,187 |
|
|
|
552,340 |
|
Jeffrey G. Shrader |
|
|
37,545,847 |
|
|
|
554,680 |
|
Secondly, the stockholders voted on the approval of our 2008 Long-Term Incentive Plan. Set
forth below is a tabulation of votes with respect to the approval of our 2008 Long-Term Incentive
Plan:
|
|
|
|
|
|
|
|
|
|
|
|
|
BROKER |
VOTES FOR |
|
VOTES AGAINST |
|
ABSTENTIONS |
|
NON-VOTES |
|
|
|
|
|
|
|
30,677,807
|
|
1,250,362
|
|
177,501
|
|
5,994,857 |
Also, the stockholders voted upon and ratified the appointment of BDO Seidman, LLP to serve as
our independent public accountants for 2008. Set forth below is a tabulation of votes with respect
to the proposal to ratify the appointment of our independent public accountants:
|
|
|
|
|
VOTES FOR |
|
VOTES AGAINST |
|
ABSTENTIONS |
|
|
|
|
|
37,896,866
|
|
120,348
|
|
83,313 |
ITEM 6. 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 10.1 of the Registrants Current
Report on Form 8-K filed on November 30, 2007) |
|
|
|
3.3
|
|
Certificate of Formation of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.3 of
the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004) |
|
|
|
3.4
|
|
Limited Liability Company Agreement of Parallel, L.L.C. (Incorporated by reference to Exhibit
No. 3.4 of the Registrants Statement on Form S-3, No. 333-119725 filed on October 13, 2004) |
|
|
|
3.5
|
|
Certificate of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit
No. 3.5 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on
October 13, 2004) |
(43)
|
|
|
No. |
|
Description of Exhibit |
|
|
|
3.6
|
|
Agreement of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No.
3.6 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October
13, 2004) |
|
|
|
4.1
|
|
Certificate of Designations, Preferences and Rights of Serial Preferred Stock 6%
Convertible Preferred Stock (Incorporated by reference to Exhibit 4.1 of Form 10-Q of the
Registrant for the fiscal quarter ended June 30, 2004) |
|
|
|
4.2
|
|
Certificate of Designations, Preferences and Rights of Series A Preferred Stock (Incorporated
by reference to Exhibit 4.2 of Form 10-K of the Registrant for the fiscal year ended December
31, 2000) |
|
|
|
4.3
|
|
Rights Agreement, dated as of October 5, 2000, between the Registrant and Computershare Trust
Company, Inc., as Rights Agent (Incorporated by reference to Exhibit 1 of Form 8-A of the
Registrant filed with the Securities and Exchange Commission on October 10, 2000) |
|
|
|
4.4
|
|
Form of common stock certificate of the Registrant (Incorporated by reference to Exhibit No.
4.6 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October
13, 2004) |
|
|
|
4.5
|
|
Warrant Purchase Agreement, dated November 20, 2001, between the Registrant and Stonington
Corporation (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant for the
fiscal year ended December 31, 2004) |
|
|
|
4.6
|
|
Warrant Purchase Agreement, dated December 23, 2003, between the Registrant and Stonington
Corporation (Incorporated by reference to Exhibit 4.8 of Form 10-K of the Registrant for the
fiscal year ended December 31, 2004) |
|
|
|
4.7
|
|
Purchase Warrant Agreement, dated as of October 1, 1980, between the Registrant and American
Stock Transfer, Inc. (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant
for the fiscal year ended December 31, 2006) |
|
|
|
4.8
|
|
First Amendment to Warrant Agreement, dated as of February 22, 2007, among the Registrant,
Computershare Shareholder Services, Inc. and Computershare Trust Company, N.A. (Incorporated
by reference to Exhibit 4.8 of Form 10-K of the Registrant for the fiscal year ended December
31, 2006) |
|
|
|
4.9
|
|
Form of Rule 144A 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.2 to the
Registrants Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
4.10
|
|
Form of IAI 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.3 to the
Registrants Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
4.11
|
|
Form of Regulation S 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.4 to
the Registrants Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
4.12
|
|
Indenture, dated as of July 31, 2007, among the Registrant as Issuer and Wells Fargo Bank,
National Association as Trustee (Incorporated by reference to Exhibit 4.1 to the Registrants
Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
4.13
|
|
Registration Rights Agreement, dated as of July 31, 2007, by and among the Registrant,
Jefferies & Company, Inc., Merrill Lynch, Pierce, Fenner and Smith Incorporated and BNP
Paribas Securities Corp. (Incorporated by reference to Exhibit 10.2 to the Registrants
Current Report on Form 8-K filed on August 1, 2007) |
(44)
|
|
|
No. |
|
Description of Exhibit |
|
|
|
4.14
|
|
Purchase Agreement, dated as of July 26, 2007, by and among the Registrant, Jefferies &
Company, Inc., Merrill Lynch, Pierce, Fenner and Smith Incorporated and BNP Paribas Securities
Corp. (Incorporated by reference to Exhibit 4.2 to the Registrants Current Report on Form 8-K
filed on August 1, 2007) |
|
|
|
4.15
|
|
Form of 101/4% Unrestricted Senior Note due 2014 (Incorporated by reference to Exhibit 4.13 of
Form S-4 of the Registrant, Registration No. 333-148465) |
|
|
|
Executive Compensation Plans and Arrangements (Exhibit No.s 10.1 through 10.11): |
|
|
|
10.1
|
|
1992 Stock Option Plan (Incorporated by reference to Exhibit 10.1 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2004) |
|
|
|
10.2
|
|
Merrill Lynch, Pierce, Fenner & Smith Incorporated Prototype Simplified Employee Pension Plan
(Incorporated by reference to Exhibit 10.6 of the Registrants Form 10-K for the fiscal year
ended December 31, 1995) |
|
|
|
10.3
|
|
Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.3 of the
Registrants Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2005) |
|
|
|
10.4
|
|
1998 Stock Option Plan (Incorporated by reference to Exhibit 10.4 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2006) |
|
|
|
10.5
|
|
2001 Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.7 of
the Registrants Form 10-Q Report for the fiscal quarter ended March 31, 2004) |
|
|
|
10.6
|
|
2004 Non-Employee Director Stock Grant Plan (Incorporated by reference to Exhibit 10.1 of the
Registrants Form 8-K Report dated September 22, 2004) |
|
|
|
10.7
|
|
Incentive and Retention Plan (Incorporated by reference to Exhibit 10.7 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2006) |
|
|
|
10.8
|
|
2008 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.1 of the Registrants
Form 8-K Report dated March 27, 2008) |
|
|
|
10.9
|
|
Form of Nonqualified Stock Option Agreement for nonqualified stock options granted under the
Registrants 2008 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.2 of the
Registrants Current Report on Form 8-K filed on June 18, 2008) |
|
|
|
10.10
|
|
Form of Outside Director Stock Award Agreement for stock awards granted under the
Registrants 2008 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.3 of the
Registrants Current Report on Form 8-K filed on June 18, 2008) |
|
|
|
10.11
|
|
Form of Outside Director Restricted Stock Agreement for restricted stock grants under the
Registrants 2008 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.4 of the
Registrants Current Report on Form 8-K filed on June 18, 2008) |
|
|
|
10.12
|
|
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) |
(45)
|
|
|
No. |
|
Description of Exhibit |
|
10.13
|
|
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) |
|
|
|
10.14
|
|
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) |
|
|
|
10.15
|
|
Second Amended and Restated Credit Agreement, dated September 27, 2004, by and among
Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB,
BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit
10.1 of the Registrants Form 8-K Report dated September 27, 2004 and filed with the
Securities and Exchange Commission on October 1, 2004) |
|
|
|
10.16
|
|
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) |
|
|
|
10.17
|
|
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) |
|
|
|
10.18
|
|
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) |
|
|
|
10.19
|
|
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) |
|
|
|
10.20
|
|
Purchase and Sale Agreement, dated as of October 14, 2005, 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) |
|
|
|
10.21
|
|
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) |
|
|
|
10.22
|
|
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) |
|
|
|
10.23
|
|
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) |
(46)
|
|
|
No. |
|
Description of Exhibit |
|
|
|
10.24
|
|
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) |
|
|
|
10.25
|
|
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) |
|
|
|
10.26
|
|
Intercreditor and Subordination Agreement, dated November 15, 2005, among Citibank Texas,
N.A., BNP Paribas, Parallel Petroleum Corporation, Parallel, L.P. and Parallel, L.L.C.
(Incorporated by reference to Exhibit No. 10.5 of the Registrants Form 8-K Report, dated
November 15, 2005, as filed with the Securities and Exchange Commission on November 21, 2005) |
|
|
|
10.27
|
|
Guaranty, dated as of December 23, 2005, made by Parallel, L.L.C. to and in favor of
Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.23 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2006) |
|
|
|
10.28
|
|
Third Amended and Restated Pledge Agreement, dated as of December 23, 2005, between
Parallel, L.L.C. and Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.24 of Form
10-K of the Registrant for the fiscal year ended December 31, 2006) |
|
|
|
10.29
|
|
Second Lien Guarantee and Collateral Agreement, dated as of November 15, 2005, made by
Parallel Petroleum Corporation and Parallel, L.P. to and in favor of BNP Paribas (Incorporated
by reference to Exhibit 10.25 of Form 10-K of the Registrant for the fiscal year ended
December 31, 2006) |
|
|
|
10.30
|
|
Third Amendment to Third Amended and Restated Credit Agreement, dated as of July 31, 2007,
among the Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank,
Comerica Bank, Bank of Scotland, and Fortis Capital Corp. (Incorporated by reference to
Exhibit 10.3 of the Registrants Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
10.31
|
|
Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of November 30,
2007, among the Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank,
Comerica Bank, Bank of Scotland, and Fortis Capital Corp. (Incorporated by reference to
Exhibit 10.27 of Form S-4 of the Registrant, Registration No. 333-148465) |
|
|
|
10.32
|
|
Hagerman Gas Gathering System Joint Venture Agreement, dated as of January 16, 2007, among
the Registrant, Feagan Gathering Company and Capstone Oil and Gas Company, L.P. (Incorporated by reference to Exhibit 10.28 of Form 10-K of the Registrant for the fiscal
year ended December 31, 2007) |
|
|
|
10.33
|
|
Fourth Amended and Restated Credit Agreement, dated as of May 16, 2008, among the
Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank, Comerica Bank,
Bank of Scotland plc, and Texas Capital Bank, N.A. (Incorporated by reference to Exhibit 10.1
of the Registrants Current Report on Form 8-K filed on May 22, 2008) |
(47)
|
|
|
No. |
|
Description of Exhibit |
|
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) |
|
|
|
*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. |
(48)
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.
|
|
|
|
|
|
PARALLEL PETROLEUM CORPORATION
|
|
|
BY: |
/s/ Larry C. Oldham
|
|
Date: August 4, 2008 |
|
Larry C. Oldham |
|
|
|
President and Chief Executive Officer |
|
|
|
|
|
Date: August 4, 2008 |
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 10.1 of the Registrants Current
Report on Form 8-K filed on November 30, 2007) |
|
|
|
3.3
|
|
Certificate of Formation of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.3 of
the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004) |
|
|
|
3.4
|
|
Limited Liability Company Agreement of Parallel, L.L.C. (Incorporated by reference to Exhibit
No. 3.4 of the Registrants Statement on Form S-3, No. 333-119725 filed on October 13, 2004) |
|
|
|
3.5
|
|
Certificate of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit
No. 3.5 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on
October 13, 2004) |
|
|
|
3.6
|
|
Agreement of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No.
3.6 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October
13, 2004) |
|
|
|
4.1
|
|
Certificate of Designations, Preferences and Rights of Serial Preferred Stock 6%
Convertible Preferred Stock (Incorporated by reference to Exhibit 4.1 of Form 10-Q of the
Registrant for the fiscal quarter ended June 30, 2004) |
|
|
|
4.2
|
|
Certificate of Designations, Preferences and Rights of Series A Preferred Stock (Incorporated
by reference to Exhibit 4.2 of Form 10-K of the Registrant for the fiscal year ended December
31, 2000) |
|
|
|
4.3
|
|
Rights Agreement, dated as of October 5, 2000, between the Registrant and Computershare Trust
Company, Inc., as Rights Agent (Incorporated by reference to Exhibit 1 of Form 8-A of the
Registrant filed with the Securities and Exchange Commission on October 10, 2000) |
|
|
|
4.4
|
|
Form of common stock certificate of the Registrant (Incorporated by reference to Exhibit No.
4.6 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October
13, 2004) |
|
|
|
4.5
|
|
Warrant Purchase Agreement, dated November 20, 2001, between the Registrant and Stonington
Corporation (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant for the
fiscal year ended December 31, 2004) |
|
|
|
4.6
|
|
Warrant Purchase Agreement, dated December 23, 2003, between the Registrant and Stonington
Corporation (Incorporated by reference to Exhibit 4.8 of Form 10-K of the Registrant for the
fiscal year ended December 31, 2004) |
|
|
|
4.7
|
|
Purchase Warrant Agreement, dated as of October 1, 1980, between the Registrant and American
Stock Transfer, Inc. (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant
for the fiscal year ended December 31, 2006) |
|
|
|
4.8
|
|
First Amendment to Warrant Agreement, dated as of February 22, 2007, among the Registrant,
Computershare Shareholder Services, Inc. and Computershare Trust Company, N.A. |
|
|
|
No. |
|
Description of Exhibit |
|
|
|
(Incorporated by reference to Exhibit 4.8 of Form 10-K of the Registrant for the fiscal year
ended December 31, 2006) |
|
|
|
4.9
|
|
Form of Rule 144A 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.2 to the
Registrants Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
4.10
|
|
Form of IAI 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.3 to the
Registrants Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
4.11
|
|
Form of Regulation S 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.4 to
the Registrants Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
4.12
|
|
Indenture, dated as of July 31, 2007, among the Registrant as Issuer and Wells Fargo Bank,
National Association as Trustee (Incorporated by reference to Exhibit 4.1 to the Registrants
Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
4.13
|
|
Registration Rights Agreement, dated as of July 31, 2007, by and among the Registrant,
Jefferies & Company, Inc., Merrill Lynch, Pierce, Fenner and Smith Incorporated and BNP
Paribas Securities Corp. (Incorporated by reference to Exhibit 10.2 to the Registrants
Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
4.14
|
|
Purchase Agreement, dated as of July 26, 2007, by and among the Registrant, Jefferies &
Company, Inc., Merrill Lynch, Pierce, Fenner and Smith Incorporated and BNP Paribas Securities
Corp. (Incorporated by reference to Exhibit 4.2 to the Registrants Current Report on Form 8-K
filed on August 1, 2007) |
|
|
|
4.15
|
|
Form of 101/4% Unrestricted Senior Note due 2014 (Incorporated by reference to Exhibit 4.13 of
Form S-4 of the Registrant, Registration No. 333-148465) |
|
|
|
Executive Compensation Plans and Arrangements (Exhibit No.s 10.1 through 10.11): |
|
|
|
10.1
|
|
1992 Stock Option Plan (Incorporated by reference to Exhibit 10.1 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2004) |
|
|
|
10.2
|
|
Merrill Lynch, Pierce, Fenner & Smith Incorporated Prototype Simplified Employee Pension Plan
(Incorporated by reference to Exhibit 10.6 of the Registrants Form 10-K for the fiscal year
ended December 31, 1995) |
|
|
|
10.3
|
|
Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.3 of the
Registrants Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2005) |
|
|
|
10.4
|
|
1998 Stock Option Plan (Incorporated by reference to Exhibit 10.4 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2006) |
|
|
|
10.5
|
|
2001 Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.7 of
the Registrants Form 10-Q Report for the fiscal quarter ended March 31, 2004) |
|
|
|
10.6
|
|
2004 Non-Employee Director Stock Grant Plan (Incorporated by reference to Exhibit 10.1 of the
Registrants Form 8-K Report dated September 22, 2004) |
|
|
|
10.7
|
|
Incentive and Retention Plan (Incorporated by reference to Exhibit 10.7 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2006) |
|
|
|
No. |
|
Description of Exhibit |
|
10.8
|
|
2008 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.1 of the Registrants
Form 8-K Report dated March 27, 2008) |
|
|
|
10.9
|
|
Form of Nonqualified Stock Option Agreement for nonqualified stock options granted under the
Registrants 2008 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.2 of the
Registrants Current Report on Form 8-K filed on June 18, 2008) |
|
|
|
10.10
|
|
Form of Outside Director Stock Award Agreement for stock awards granted under the
Registrants 2008 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.3 of the
Registrants Current Report on Form 8-K filed on June 18, 2008) |
|
|
|
10.11
|
|
Form of Outside Director Restricted Stock Agreement for restricted stock grants under the
Registrants 2008 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.4 of the
Registrants Current Report on Form 8-K filed on June 18, 2008) |
|
|
|
10.12
|
|
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) |
|
|
|
10.13
|
|
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) |
|
|
|
10.14
|
|
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) |
|
|
|
10.15
|
|
Second Amended and Restated Credit Agreement, dated September 27, 2004, by and among
Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB,
BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit
10.1 of the Registrants Form 8-K Report dated September 27, 2004 and filed with the
Securities and Exchange Commission on October 1, 2004) |
|
|
|
10.16
|
|
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) |
|
|
|
10.17
|
|
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) |
|
|
|
10.18
|
|
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) |
|
|
|
10.19
|
|
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) |
|
|
|
No. |
|
Description of Exhibit |
|
10.20
|
|
Purchase and Sale Agreement, dated as of October 14, 2005, 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) |
|
|
|
10.21
|
|
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) |
|
|
|
10.22
|
|
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) |
|
|
|
10.23
|
|
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) |
|
|
|
10.24
|
|
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) |
|
|
|
10.25
|
|
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) |
|
|
|
10.26
|
|
Intercreditor and Subordination Agreement, dated November 15, 2005, among Citibank Texas,
N.A., BNP Paribas, Parallel Petroleum Corporation, Parallel, L.P. and Parallel, L.L.C.
(Incorporated by reference to Exhibit No. 10.5 of the Registrants Form 8-K Report, dated
November 15, 2005, as filed with the Securities and Exchange Commission on November 21, 2005) |
|
|
|
10.27
|
|
Guaranty, dated as of December 23, 2005, made by Parallel, L.L.C. to and in favor of
Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.23 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2006) |
|
|
|
10.28
|
|
Third Amended and Restated Pledge Agreement, dated as of December 23, 2005, between
Parallel, L.L.C. and Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.24 of Form
10-K of the Registrant for the fiscal year ended December 31, 2006) |
|
|
|
10.29
|
|
Second Lien Guarantee and Collateral Agreement, dated as of November 15, 2005, made by
Parallel Petroleum Corporation and Parallel, L.P. to and in favor of BNP Paribas (Incorporated
by reference to Exhibit 10.25 of Form 10-K of the Registrant for the fiscal year ended
December 31, 2006) |
|
|
|
10.30
|
|
Third Amendment to Third Amended and Restated Credit Agreement, dated as of July 31, 2007,
among the Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank, |
|
|
|
No. |
|
Description of Exhibit |
|
|
|
Comerica Bank, Bank of Scotland, and Fortis Capital Corp. (Incorporated by reference to
Exhibit 10.3 of the Registrants Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
10.31
|
|
Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of November 30,
2007, among the Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank,
Comerica Bank, Bank of Scotland, and Fortis Capital Corp. (Incorporated by reference to
Exhibit 10.27 of Form S-4 of the Registrant, Registration No. 333-148465) |
|
|
|
10.32
|
|
Hagerman Gas Gathering System Joint Venture Agreement, dated as of January 16, 2007, among
the Registrant, Feagan Gathering Company and Capstone Oil and Gas Company, L.P. (Incorporated
by reference to Exhibit 10.28 of Form 10-K of the Registrant for the fiscal year ended
December 31, 2007) |
|
|
|
10.33
|
|
Fourth Amended and Restated Credit Agreement, dated as of May 16, 2008, among the
Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank, Comerica Bank,
Bank of Scotland plc, and Texas Capital Bank, N.A. (Incorporated by reference to Exhibit 10.1
of the Registrants Current Report on Form 8-K filed on May 22, 2008) |
|
|
|
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) |
|
|
|
*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. |