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 September 30, 2007
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
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(I.R.S. Employer Identification No.) |
incorporation or organization) |
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1004 N. Big Spring, Suite 400, |
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Midland, Texas
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79701 |
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(Address of Principal Executive Offices)
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(Zip Code) |
(432) 684-3727
(Registrants telephone number, including area code)
Not Applicable
(Former name, former address and former fiscal year, if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, or a non-accelerated filer. See definition of accelerated filer and large accelerated
filer in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ Accelerated filer o Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes o No þ
At
November 1, 2007, 38,252,644 shares of the Registrants Common Stock, $0.01 par value, were
outstanding.
PART
I. FINANCIAL INFORMATION
ITEM I. Financial Statements
PARALLEL
PETROLEUM CORPORATION
Consolidated Balance Sheets
(dollars in thousands, except share data)
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September 30, |
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December 31, |
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2007 |
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2006 |
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(unaudited) |
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Assets |
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Current assets: |
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Cash and cash equivalents |
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$ |
5,318 |
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$ |
5,910 |
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Accounts receivable: |
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Oil and natural gas sales |
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18,902 |
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|
18,605 |
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Joint interest owners and other, net of allowance for
doubtful account of $50 and $80 |
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3,507 |
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7,209 |
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Affiliates and joint ventures |
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3,335 |
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|
3,338 |
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|
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25,744 |
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29,152 |
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Other current assets |
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1,515 |
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2,863 |
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Deferred tax asset |
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|
6,514 |
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4,340 |
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Total current assets |
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39,091 |
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42,265 |
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Property and equipment, at cost: |
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Oil and natural gas properties, full cost method (including
$72,435 and $50,375 not
subject to depletion) |
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609,216 |
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501,405 |
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Other |
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2,839 |
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2,614 |
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612,055 |
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504,019 |
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Less accumulated depreciation, depletion and amortization |
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(137,064 |
) |
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(115,513 |
) |
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Net property and equipment |
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474,991 |
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388,506 |
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Restricted cash |
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53 |
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|
325 |
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Investment in pipelines and gathering system ventures |
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8,621 |
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6,454 |
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Other assets, net of accumulated amortization of
$1,386 and $760 |
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2,820 |
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5,268 |
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$ |
525,576 |
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$ |
442,818 |
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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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$ |
42,556 |
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$ |
36,171 |
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Asset retirement obligations |
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583 |
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|
701 |
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Derivative obligations |
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19,867 |
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14,109 |
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Total current liabilities |
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63,006 |
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50,981 |
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Revolving credit facility |
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89,000 |
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115,000 |
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Term loan |
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50,000 |
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Senior notes (principal amount $150,000) |
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145,300 |
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Asset retirement obligations |
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4,219 |
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4,362 |
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Derivative obligations |
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5,471 |
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14,386 |
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Deferred tax liability |
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28,493 |
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24,307 |
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Total long-term liabilities |
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272,483 |
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208,055 |
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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 $0.01 per share, authorized 60,000,000
shares, issued and outstanding 38,231,144 and 37,547,010 |
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382 |
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375 |
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Additional paid-in capital |
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142,991 |
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140,353 |
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Retained earnings |
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46,714 |
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43,054 |
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Total stockholders equity |
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190,087 |
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183,782 |
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$ |
525,576 |
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$ |
442,818 |
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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 |
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Nine Months Ended |
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September 30, |
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September 30, |
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2007 |
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2006 |
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2007 |
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2006 |
|
Oil and natural gas revenues: |
|
|
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|
|
|
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|
|
|
|
|
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Oil and natural gas sales |
|
$ |
29,487 |
|
|
$ |
29,490 |
|
|
$ |
79,957 |
|
|
$ |
82,360 |
|
Loss on hedging |
|
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|
(3,279 |
) |
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|
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|
(9,264 |
) |
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Total revenues |
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29,487 |
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26,211 |
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79,957 |
|
|
|
73,096 |
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Cost and expenses: |
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Lease operating expense |
|
|
6,445 |
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|
|
5,323 |
|
|
|
16,420 |
|
|
|
12,639 |
|
Production taxes |
|
|
1,448 |
|
|
|
1,538 |
|
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|
3,696 |
|
|
|
4,116 |
|
Production tax refund |
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(1,209 |
) |
|
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General and administrative |
|
|
2,492 |
|
|
|
2,405 |
|
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|
7,737 |
|
|
|
7,147 |
|
Depreciation, depletion and amortization |
|
|
7,821 |
|
|
|
7,420 |
|
|
|
21,680 |
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|
17,848 |
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Total costs and expenses |
|
|
18,206 |
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|
|
16,686 |
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|
48,324 |
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41,750 |
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Operating income |
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11,281 |
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9,525 |
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|
31,633 |
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31,346 |
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Other income (expense), net: |
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|
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|
|
|
|
|
|
|
|
|
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|
Gain (loss) on derivatives not classified as hedges |
|
|
(4,556 |
) |
|
|
10,323 |
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|
(11,161 |
) |
|
|
116 |
|
Gain on ineffective portion of hedges |
|
|
|
|
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|
305 |
|
|
|
|
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|
500 |
|
Interest and other income |
|
|
55 |
|
|
|
29 |
|
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|
163 |
|
|
|
122 |
|
Interest expense |
|
|
(5,429 |
) |
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|
(3,345 |
) |
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|
(13,449 |
) |
|
|
(8,944 |
) |
Cost of debt retirement |
|
|
(760 |
) |
|
|
|
|
|
|
(760 |
) |
|
|
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|
Other expense |
|
|
(76 |
) |
|
|
(96 |
) |
|
|
(91 |
) |
|
|
(164 |
) |
Equity in loss of pipelines and gathering system ventures |
|
|
(69 |
) |
|
|
(39 |
) |
|
|
(663 |
) |
|
|
(68 |
) |
|
|
|
|
|
|
|
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|
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Total other income (expense), net |
|
|
(10,835 |
) |
|
|
7,177 |
|
|
|
(25,961 |
) |
|
|
(8,438 |
) |
|
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Income before income taxes |
|
|
446 |
|
|
|
16,702 |
|
|
|
5,672 |
|
|
|
22,908 |
|
Income tax expense, deferred |
|
|
(153 |
) |
|
|
(5,706 |
) |
|
|
(2,011 |
) |
|
|
(7,837 |
) |
|
|
|
|
|
|
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|
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|
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|
Net income |
|
$ |
293 |
|
|
$ |
10,996 |
|
|
$ |
3,661 |
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|
$ |
15,071 |
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Net income per common share: |
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Basic |
|
$ |
0.01 |
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|
$ |
0.30 |
|
|
$ |
0.10 |
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|
$ |
0.43 |
|
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Diluted |
|
$ |
0.01 |
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$ |
0.30 |
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|
$ |
0.09 |
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|
$ |
0.42 |
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Weighted average common shares outstanding: |
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Basic |
|
|
38,033 |
|
|
|
36,215 |
|
|
|
37,791 |
|
|
|
35,340 |
|
|
|
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Diluted |
|
|
38,767 |
|
|
|
36,919 |
|
|
|
38,806 |
|
|
|
36,027 |
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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
Nine Months Ended September 30, 2007 and 2006
(unaudited)
(dollars in thousands)
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2007 |
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2006 |
|
Cash flows from operating activities: |
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|
Net income |
|
$ |
3,661 |
|
|
$ |
15,071 |
|
Adjustments to reconcile net income to net cash
provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
21,680 |
|
|
|
17,848 |
|
Gain on sale of automobiles |
|
|
(25 |
) |
|
|
|
|
Accretion of asset retirement obligation |
|
|
243 |
|
|
|
172 |
|
Accretion of senior notes discount |
|
|
114 |
|
|
|
|
|
Deferred income tax |
|
|
2,011 |
|
|
|
7,837 |
|
(Gain) loss on derivatives not classified as hedges |
|
|
11,161 |
|
|
|
(116 |
) |
Gain on ineffective portion of hedges |
|
|
|
|
|
|
(500 |
) |
Cost of debt retirement |
|
|
760 |
|
|
|
|
|
Common stock issued in lieu of cash for directors fees |
|
|
96 |
|
|
|
100 |
|
Stock option expense |
|
|
161 |
|
|
|
435 |
|
Equity in loss of pipelines and gathering system ventures |
|
|
663 |
|
|
|
68 |
|
Bad debt expense |
|
|
(30 |
) |
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|
|
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|
|
|
|
|
|
|
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|
Changes in assets and liabilities: |
|
|
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Other assets, net |
|
|
226 |
|
|
|
1,140 |
|
Restricted cash |
|
|
272 |
|
|
|
(50 |
) |
Decrease (increase) in accounts receivable |
|
|
3,438 |
|
|
|
(12,084 |
) |
Decrease (increase) in other current assets |
|
|
713 |
|
|
|
(151 |
) |
Increase in accounts payable and accrued liabilities |
|
|
6,385 |
|
|
|
14,880 |
|
Federal tax deposit |
|
|
|
|
|
|
(40 |
) |
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
51,529 |
|
|
|
44,610 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
Additions to oil and natural gas properties |
|
|
(110,015 |
) |
|
|
(147,058 |
) |
Use of restricted cash for acquisition of oil and natural gas properties |
|
|
|
|
|
|
2,366 |
|
Proceeds from disposition of oil and natural gas properties and other property and equipment |
|
|
1,711 |
|
|
|
130 |
|
Additions to other property and equipment |
|
|
(340 |
) |
|
|
(800 |
) |
Settlements on derivative instruments |
|
|
(9,875 |
) |
|
|
(3,568 |
) |
Investment in pipelines and gathering system ventures |
|
|
(2,830 |
) |
|
|
(9,688 |
) |
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(121,349 |
) |
|
|
(158,618 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Borrowings from bank line of credit |
|
|
68,500 |
|
|
|
90,000 |
|
Payments on bank line of credit |
|
|
(94,500 |
) |
|
|
(43,000 |
) |
Payment on term loan |
|
|
(50,000 |
) |
|
|
|
|
Senior notes (principal amount $150,000) |
|
|
145,186 |
|
|
|
|
|
Deferred financing cost |
|
|
(2,346 |
) |
|
|
(179 |
) |
Proceeds (net) from common stock issued |
|
|
|
|
|
|
60,315 |
|
Proceeds from exercise of stock options |
|
|
2,388 |
|
|
|
766 |
|
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
69,228 |
|
|
|
107,902 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents |
|
|
(592 |
) |
|
|
(6,106 |
) |
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of period |
|
|
5,910 |
|
|
|
6,418 |
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
5,318 |
|
|
$ |
312 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash financing and investing activities: |
|
|
|
|
|
|
|
|
Oil and natural gas properties asset retirement obligations |
|
$ |
(505 |
) |
|
$ |
1,957 |
|
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 |
|
$ |
10,451 |
|
|
$ |
9,065 |
|
The accompany notes are an integral part of these Consolidated Financial Statements.
(3)
PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Comprehensive Income
(unaudited)
(dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
Net income |
|
$ |
293 |
|
|
$ |
10,996 |
|
|
$ |
3,661 |
|
|
$ |
15,071 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive loss: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gain (loss) on derivatives |
|
|
|
|
|
|
634 |
|
|
|
|
|
|
|
(1,750 |
) |
Reclassification adjustments for losses
on derivatives included in net income |
|
|
|
|
|
|
3,240 |
|
|
|
|
|
|
|
9,191 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of derivatives |
|
|
|
|
|
|
3,874 |
|
|
|
|
|
|
|
7,441 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense |
|
|
|
|
|
|
(1,317 |
) |
|
|
|
|
|
|
(2,530 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive income |
|
|
|
|
|
|
2,557 |
|
|
|
|
|
|
|
4,911 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
$ |
293 |
|
|
$ |
13,553 |
|
|
$ |
3,661 |
|
|
$ |
19,982 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these Consolidated Financial Statements.
(4)
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. DESCRIPTION OF BUSINESS NATURE OF OPERATIONS AND BASIS OF PRESENTATION
Parallel Petroleum Corporation, or Parallel, was incorporated in Texas on November 26, 1979,
and reincorporated in the State of Delaware on December 18, 1984.
Parallel is engaged in the acquisition, development and exploitation of long life oil and
natural gas reserves and, to a lesser extent, the exploration for new oil and natural gas reserves.
The majority of our current producing properties are in the:
|
|
|
Permian Basin of west Texas and New Mexico; |
|
|
|
|
Fort Worth Basin of north Texas; and |
|
|
|
|
the onshore gulf coast area of south Texas. |
The financial information included herein is unaudited. The balance sheet as of December 31,
2006 has been derived from our audited Consolidated Financial Statements as of December 31, 2006.
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 2006 amounts
have been conformed to the 2007 financial statement presentation.
Certain information, accounting policies and footnote disclosures normally included in
financial statements prepared in accordance with accounting principles generally accepted in the
United States of America have been condensed or omitted in this Quarterly Report on Form 10-Q
pursuant to certain rules and regulations of the Securities and Exchange Commission. These
financial statements should be read in conjunction with the audited Consolidated Financial
Statements and notes included in our Annual Report on Form 10-K/A for the year ended December 31,
2006.
Unless otherwise indicated or unless the context otherwise requires, all references to
Parallel, we, us, and our are to Parallel Petroleum Corporation and its consolidated
subsidiaries, Parallel
L.P. and Parallel, L.L.C.
On July 12, 2007, our subsidiaries, Parallel L.P. and Parallel L.L.C., were merged with and
into Parallel Petroleum Corporation.
NOTE
2. STOCKHOLDERS EQUITY
Options
We account 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)).
For the nine months ended September 30, 2007 and 2006, we recognized compensation expense of
approximately $161,000 and $493,000, respectively, with a tax benefit of approximately $55,000 and
(5)
$168,000, 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 included a cumulative adjustment for amounts previously expensed associated with
options estimated to be forfeited or surrendered.
During the second quarter of 2006, we determined that stock options to purchase 30,000 shares
of common stock, which were granted in 2003, were not available for grant under our existing stock
option plans. In June 2006, these excess options were cancelled in exchange for our payment to
four employees of cash totaling approximately $511,000. This amount was charged to expense during
the second quarter of 2006.
The following table presents future stock-based compensation expense expected to be recognized
over the vesting period of:
|
|
|
|
|
|
|
(in thousands) |
|
Fourth quarter 2007 |
|
|
86 |
|
2008 |
|
|
228 |
|
2009 through 2011 |
|
|
122 |
|
|
|
|
|
Total |
|
$ |
436 |
|
|
|
|
|
Options to purchase a total of 137,500 shares of common stock were outstanding and unvested as
of September 30, 2007. During the nine months ended September 30, 2007, options to purchase 17,500
shares of common stock were granted to one individual, options to purchase 597,000 shares of common
stock were exercised and options to purchase 40,000 shares were forfeited and no options expired.
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 September 30, 2007 and that had option
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 historical volatility of the stock. The expected term of the options granted used in the model
represent the period of time that options granted are expected to be outstanding.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2005 |
|
|
2001 |
|
Expected volatility |
|
|
52.52 |
% |
|
|
54.20 |
% |
|
|
57.95 |
% |
Expected dividends |
|
|
0.00 |
|
|
|
0.00 |
|
|
|
0.00 |
|
Expected term (in years) |
|
|
6 |
|
|
|
7 |
|
|
|
8 |
|
Risk-free rate |
|
|
4.89 |
% |
|
|
4.20 |
% |
|
|
5.05 |
% |
(6)
A summary of the option activity as of September 30, 2007 is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remaining |
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
Contractual |
|
|
Aggregate |
|
|
|
Options |
|
|
Exercise Price |
|
|
Term |
|
|
Intrinsic Value |
|
|
|
(in thousands) |
|
|
|
|
|
(years) |
|
|
(in thousands) |
|
Outstanding December 31, 2006 |
|
|
1,199 |
|
|
$ |
5.40 |
|
|
|
|
|
|
|
|
|
Granted |
|
|
17 |
|
|
$ |
22.89 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(597 |
) |
|
$ |
4.00 |
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
(40 |
) |
|
$ |
12.27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding September 30, 2007 |
|
|
579 |
|
|
$ |
6.90 |
|
|
|
6.1 |
|
|
$ |
5,844 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at September 30, 2007 |
|
|
442 |
|
|
$ |
5.30 |
|
|
|
5.2 |
|
|
$ |
5,163 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
Intrinsic Value of Options Exercised Nine Months Ended September 30, 2007 |
|
$ |
9,705 |
|
Intrinsic Value of Options Exercised Nine Months Ended September 30, 2006 |
|
$ |
2,855 |
|
|
|
|
|
|
Fair Market Value of Options Granted Nine Months Ended September 30, 2007 |
|
$ |
218 |
|
Fair Market Value of Options Granted Nine Months Ended September 30, 2006 |
|
$ |
|
|
We have outstanding stock options granted under five separate plans. Generally, 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.
NOTE 3. CREDIT ARRANGEMENTS
In the past, we have maintained two separate credit facilities. One of these credit facilities
is our Third Amended and Restated Credit Agreement, as amended, or Revolving Credit Agreement,
with a group of bank lenders which, at September 30, 2007, provided us with a revolving line of
credit having a borrowing base limitation of $150.0 million. The total amount that we can borrow
and have outstanding at any one time is limited to the lesser of $350.0 million or the borrowing
base established by the lenders. At September 30, 2007, the principal amount outstanding under our
revolving credit facility was $89.0 million, excluding $445,000 reserved for our letters of credit.
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 Term Loan Agreement was paid off and terminated on July 31, 2007 with our payment to
the lenders of $50.2 million, including interest. This payment was made with proceeds from our
sale of unsecured senior notes, or senior notes, in the principal amount of $150.0 million that
we completed on July 31, 2007.
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 amount is redetermined by
the lenders semi-annually on or about April 1 and October 1 of each year or at other times required
by the lenders or at our request. If, as a result of the lenders redetermination of the borrowing
base, the outstanding principal amount of our loans exceeds the borrowing base, we must either
provide additional collateral to the lenders or repay the outstanding principal of our loans in an
amount equal to the excess. Except for the
(7)
principal payments that may be required because of our
outstanding loans being in excess of the borrowing base, interest
only is payable monthly.
Loans made to us under this revolving credit facility bear interest at the base rate of
Citibank, N.A. or the LIBOR rate, at our election. Generally, Citibanks base rate is equal to
its prime rate as announced from time to time by Citibank.
The LIBOR rate is generally equal to the sum of (a) the rate designated as British Bankers
Association Interest Settlement Rates and offered in one, two, three, six or twelve month interest
periods for deposits of $1.0 million, and (b) a margin ranging from 2.00% to 2.50%, depending upon
the outstanding principal amount of our loans. If the principal amount outstanding is equal to or
greater than 75% of the borrowing base, the margin is 2.50%. If the principal amount outstanding is
equal to or greater than 50%, but less than 75% of the borrowing base, the margin is 2.25%. If the
principal amount outstanding is less than 50% of the borrowing base, the margin is 2.00%.
The interest rate we are required to pay on our borrowings, including the applicable margin,
may never be less than 5.00%. At September 30, 2007, our weighted average base rate and LIBOR rate,
plus the applicable margin, was 7.64% on $89.0 million, the outstanding principal amount of our
revolving loan on that same date.
In the case of base rate loans, interest is payable on the last day of each month. In the case
of LIBOR loans, interest is payable on the last day of each applicable interest period.
If the total outstanding borrowings under the revolving credit facility are less than the
borrowing base, we are required to pay an unused commitment fee to the lenders in an amount equal
to .25% of the daily average of the unadvanced portion of the borrowing base. The fee is payable
quarterly.
If the borrowing base is increased, we are also required to pay a fee of .375% on the amount
of any such increase.
All outstanding principal and accrued and unpaid interest under the revolving credit facility
is due and payable on October 31, 2010. The maturity date of our outstanding loans may be
accelerated by the lenders upon the occurrence of an event of default under the Revolving Credit
Agreement.
The Revolving Credit Agreement 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.
As of September 30, 2007 we were in compliance with all of the covenants in our Revolving
Credit Agreement.
Second Lien Term Loan Facility
Until July 31, 2007, we also had a $50.0 million term loan made available to us under our
Second Lien Agreement. Similar to our Revolving Credit Agreement, interest on loans made to us
under this credit facility accrued, at our election, either at an alternate base rate or a rate
designated in the Second Lien Agreement as the LIBO rate. The alternate base rate was the greater
of (a) the prime rate in effect on any day and (b) the Federal Funds Effective Rate in effect on
such day plus 1/2 of 1%, plus a margin of 3.50% per annum.
The LIBO rate was generally equal to the sum of (a) a rate appearing in the Dow Jones Market
(8)
Service for the applicable interest periods offered in one, two, three or six month periods and (b)
an applicable margin rate per annum equal to 4.50%.
Our producing oil and natural gas properties were also pledged to secure payment of our
indebtedness under this facility, but the liens granted to the lender under the Second Lien
Agreement were second and junior to the rights of the first lienholders under the Revolving Credit
Agreement.
In the case of alternate base rate loans, interest was payable the last day of each March,
September, September and December. In the case of LIBO loans, interest was payable on the last day
of the interest period applicable to each tranche, but not to exceed intervals of three months.
Upon completion of our senior notes offering, we paid off and terminated this facility on July
31, 2007 with $50.2 million of the net proceeds from the offering. As a result we charged to
earnings $760,000 of previously capitalized debt issuance cost.
Senior Notes
On July 31, 2007, we completed a private offering of unsecured senior notes (the senior
notes) in the principal amount of $150.0 million. The senior notes were recorded at the
principal amount net of underwriters discount and related expenses of $4.8 million. The senior
notes mature on August 1, 2014 and bear interest at 10.25% which is payable semi-annually beginning
on February 1, 2008. Considering the discount on the senior
notes, the effective interest rate is
10.92%. 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.
We have agreed, pursuant to a Registration Rights Agreement with the initial purchasers of the
senior notes to use our commercially reasonable efforts to prepare and file with the Securities and
Exchange Commission, within 180 days after July 31, 2007, a registration statement with respect to
a registered offer to exchange freely tradable notes having substantially identical terms as the
senior notes and to use our reasonable best efforts to cause the registration statement to be
declared effective within 210 days after July 31, 2007. If we fail to meet these obligations under
the Registration Rights Agreement we may be required to pay additional interest to holders of the
senior notes. The rate of additional interest will be .25% per year for the first 90-day period
immediately following a determination that the provisions of the Registration Rights Agreement have
not been fulfilled, with the rate increasing by an additional .25% for each subsequent 90 day
period up to a maximum additional interest rate of 1.0% per year. Under this agreement, the maximum
additional interest that we could be required to pay over the life of
the senior
(9)
notes is
approximately $9.4 million. No amounts of additional interest have been accrued as a liability as
we have no belief that we will not be able to fulfill the requirements of the Registration Rights
Agreement.
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.
The net proceeds, after payment of typical transaction expenses, of approximately $143.5
million were used first to retire our second lien term loan with the remainder being applied to our
revolving credit facility.
Interest Accrued
For the nine months ended September 30, 2007, the aggregate interest accrued under our
Revolving Credit Agreement, Second Lien Agreement and our senior notes was approximately $13.5
million. Of this amount, approximately $393,000 was capitalized.
NOTE 4. PROPERTY EXCHANGE
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
will be 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 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.
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 over the ceiling, is generally written off as an expense. Under rules and
regulations of the SEC, the excess above the ceiling is not written off if, subsequent to the end
of the quarter or year but prior to the release of the financial results, prices have increased
sufficiently that such excess above the ceiling would not have existed if the increased prices were
used in the calculations.
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 nine month periods ended September 30, 2007 and 2006, overhead costs
capitalized were approximately $1.1 million and $1.3 million, respectively.
(10)
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. Our Revolving Credit
Agreement requires us to maintain derivative financial instruments covering at least 50% of our
estimated monthly production of oil and natural gas extending 24 months into the future.
Derivative contracts not designated as cash flow hedges are marked-to-market at each period
end and the increases or decreases in fair values recorded to earnings. No derivative instruments
entered into subsequent to June 30, 2004 have been designated as cash flow hedges.
We are exposed to credit risk in the event of nonperformance by the counterparty to these
contracts, BNP Paribas and Citibank, N.A. However, we periodically assess the creditworthiness of
the counterparty to mitigate this credit risk.
Interest Rate Sensitivity
We completed a fixed interest rate swap contract with BNP Paribas, based on the 90-day LIBOR
rates at the time we entered into the contract in January 2003. This interest rate swap was
treated as a cash flow hedge as defined by Statement of Financial Accounting Standards No. 133,
Accounting for Derivative Instruments and Hedging Activities, as amended (SFAS 133), and
covered $10.0 million of our variable rate debt for all of 2006. As of December 31, 2006 this
interest rate swap had expired.
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 September 30, 2007, the fair market value of these interest
rate swaps was a liability of approximately $591,000.
The table below recaps the nature of these interest rate swaps and the fair market value of
these contracts as of September 30, 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
Notional |
|
|
Fixed |
|
|
Fair |
|
Period of Time |
|
Amounts |
|
|
Interest Rates |
|
|
Market Value |
|
|
|
($ in millions) |
|
|
|
|
|
|
($ in thousands) |
|
October 1, 2007 thru December 31, 2007 |
|
$ |
100 |
|
|
|
4.62 |
% |
|
$ |
161 |
|
January 1, 2008 thru December 31, 2008 |
|
$ |
100 |
|
|
|
4.86 |
% |
|
|
(323 |
) |
January 1, 2009 thru December 31, 2009 |
|
$ |
50 |
|
|
|
5.06 |
% |
|
|
(283 |
) |
January 1, 2010 thru October 31, 2010 |
|
$ |
50 |
|
|
|
5.15 |
% |
|
|
(146 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
$ |
(591 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
(11)
Commodity Price Sensitivity
All of our commodity derivatives are accounted for using mark-to-market accounting as
prescribed in SFAS 133.
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 September 30, 2007 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
Barrles of |
|
NyMex Oil Prices |
|
Fair Market |
Period of Time |
|
Oil |
|
Floor |
|
Cap |
|
Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
October 1, 2007 thru December 31, 2007 |
|
|
73,600 |
|
|
$ |
55.63 |
|
|
$ |
84.88 |
|
|
$ |
(108 |
) |
January 1, 2008 thru December 31, 2008 |
|
|
237,900 |
|
|
$ |
60.38 |
|
|
$ |
81.08 |
|
|
|
(553 |
) |
January 1, 2009 thru December 31, 2009 |
|
|
620,500 |
|
|
$ |
63.53 |
|
|
$ |
80.21 |
|
|
|
(473 |
) |
January 1, 2010 thru October 31, 2010 |
|
|
486,400 |
|
|
$ |
63.44 |
|
|
$ |
78.26 |
|
|
|
(80 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Houston Ship |
|
|
|
|
|
|
M M Btu of |
|
Channel Gas Prices |
|
|
|
|
|
|
Natural Gas |
|
Floor |
|
Cap |
|
|
|
|
October 1, 2007 thru October 31, 2007 |
|
|
31,000 |
|
|
$ |
6.00 |
|
|
$ |
11.05 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
M M Btu of |
|
|
WAHA Gas Prices |
|
|
|
|
|
|
|
Natural Gas |
|
|
Floor |
|
|
Cap |
|
|
|
|
|
October 1, 2007 thru October 31, 2007 |
|
|
93,000 |
|
|
$ |
6.25 |
|
|
$ |
8.90 |
|
|
|
75 |
|
October 1, 2007 thru March 31, 2008 |
|
|
1,098,000 |
|
|
$ |
6.50 |
|
|
$ |
9.50 |
|
|
|
472 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(667 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 us if the reference price for any settlement period is less than
the swap or fixed price for such contract, and we are required to make a payment to the
counterparty if the reference price for any settlement period is greater than the swap or fixed
price for such contract.
We have entered into oil swap contracts with BNP Paribas. A summary of our commodity swaps at
September 30, 2007 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
Number of |
|
|
NyMex Oil |
|
|
Fair Market |
|
Period of Time |
|
Barrels of Oil |
|
|
Swap Price |
|
|
Value |
|
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
|
October 1, 2007 thru December 31, 2007 |
|
|
119,600 |
|
|
$ |
34.36 |
|
|
$ |
(5,411 |
) |
January 1, 2008 thru December 31, 2008 |
|
|
439,200 |
|
|
$ |
33.37 |
|
|
|
(17,923 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total fair market value |
|
|
|
|
|
|
|
|
|
$ |
(23,334 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
(12)
NOTE 7. NET INCOME PER COMMON SHARE
Basic earnings per share (EPS) exclude any dilutive effects of options, warrants and
convertible securities and is computed by dividing income available to common stockholders by the
weighted average number of common shares outstanding for the period. Diluted earnings per share are
computed similar to basic earnings per share. However, diluted earnings per share reflect the
assumed conversion of all potentially dilutive securities.
The following table provides the computation of basic and diluted earnings per share for the
three and nine months ended September 30, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
|
(dollars in thousands, except per share data) |
|
Basic EPS Computation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income |
|
$ |
293 |
|
|
$ |
10,996 |
|
|
$ |
3,661 |
|
|
$ |
15,071 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding |
|
|
38,033 |
|
|
|
36,215 |
|
|
|
37,791 |
|
|
|
35,340 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per share |
|
$ |
0.01 |
|
|
$ |
0.30 |
|
|
$ |
0.10 |
|
|
$ |
0.43 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS Computation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income |
|
$ |
293 |
|
|
$ |
10,996 |
|
|
$ |
3,661 |
|
|
$ |
15,071 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding |
|
|
38,033 |
|
|
|
36,215 |
|
|
|
37,791 |
|
|
|
35,340 |
|
Employee stock options |
|
|
521 |
|
|
|
596 |
|
|
|
749 |
|
|
|
581 |
|
Warrants |
|
|
213 |
|
|
|
108 |
|
|
|
266 |
|
|
|
106 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares for diluted
earnings per share assuming conversion |
|
|
38,767 |
|
|
|
36,919 |
|
|
|
38,806 |
|
|
|
36,027 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income per share |
|
$ |
0.01 |
|
|
$ |
0.30 |
|
|
$ |
0.09 |
|
|
$ |
0.42 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(13)
NOTE 8. ASSET RETIREMENT OBLIGATIONS
The following table summarizes our asset retirement obligation transactions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Beginning asset retirement obligation |
|
$ |
4,842 |
|
|
$ |
4,420 |
|
|
$ |
5,063 |
|
|
$ |
2,495 |
|
|
Additions related to new properties |
|
|
85 |
|
|
|
123 |
|
|
|
151 |
|
|
|
314 |
|
|
Revisions in estimated cash flows |
|
|
(130 |
) |
|
|
11 |
|
|
|
(297 |
) |
|
|
1,674 |
|
|
Deletions related to property disposals |
|
|
(74 |
) |
|
|
|
|
|
|
(358 |
) |
|
|
(30 |
) |
|
Accretion expense |
|
|
79 |
|
|
|
71 |
|
|
|
243 |
|
|
|
172 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending asset retirement obligation |
|
$ |
4,802 |
|
|
$ |
4,625 |
|
|
$ |
4,802 |
|
|
$ |
4,625 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 9. RECENTLY ANNOUNCED ACCOUNTING PRONOUNCEMENTS
We adopted the provisions of Financial Accounting Standards Board (FASB) Interpretation No.
48, Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109 (FIN
48), on January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes
recognized in an enterprises financial statements in accordance with FASB Statement 109,
Accounting for Income Taxes, and prescribes a recognition threshold and measurement process for
financial statement recognition and measurement of a tax position taken or expected to be taken in
a tax return. FIN 48 also provides guidance on derecognition, classification, interest and
penalties, accounting in interim periods, disclosure and transition.
Based on our evaluation, we have concluded that there are no significant uncertain tax
positions requiring recognition in our financial statements. Our evaluation was performed for the
tax years ended December 31, 2003, 2004, 2005 and 2006, the tax years which remain subject to
examination by major tax jurisdictions as of September 30, 2007.
We may from time to time be assessed interest or penalties by major tax jurisdictions,
although any such assessments historically have been minimal and immaterial to our financial
results.
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair
Value Measurements (FAS 157). FAS 157 defines fair value as used in numerous accounting
pronouncements, establishes a framework for measuring fair value in accordance with generally
accepted accounting principles and expands disclosure requirements related to the use of fair value
measures in financial statements. FAS 157 will be effective for our financial statements for the
fiscal year beginning January 1, 2008; however, earlier application is encouraged. We are currently
evaluating the timing of adoption and the impact that adoption might have on our financial position
or results of operations.
In February 2007, the FASB issued SFAS 159, The Fair Value Option for Financial Assets and
Financial Liabilities, Including an Amendment of FASB Statement No. 115, (FAS 159) which will
become effective on January 1, 2008. FAS 159 permits entities to measure eligible financial assets,
financial liabilities and firm commitments at fair value, on an instrument-by-instrument basis,
that are otherwise not permitted to be accounted for at fair value under other generally accepted
accounting principles. The
(14)
fair value measurement election is irrevocable and subsequent changes in
fair value must be recorded in earnings. We will adopt this statement in the first quarter of 2008
and we do not expect to elect the fair value option for any eligible financial instruments and
other items.
NOTE 10. INVESTMENT IN GAS GATHERING SYSTEMS
We have invested in three separate partnerships that own and construct pipeline systems for
gathering natural gas, primarily on our leaseholds in the Barnett Shale area. These partnerships
include West Fork Pipeline Company I, L.P., West Fork Pipeline Company II, L.P. and West Fork
Pipeline Company V, L.P. These investments were recorded as equity investments in the
accompanying consolidated balance sheet. During the fourth quarter 2006, substantially all of the
assets of West Fork Pipeline I and West Fork Pipeline V were sold. As of September 30, 2007, we
had invested $306,000 in West Fork Pipeline II. West Fork Pipeline II is currently acquiring the
necessary easements and permits to begin transmission of natural gas.
As of September 30, 2007, we also invested $8.3 million in a joint venture known as the
Hagerman Gas Gathering System (Hagerman) to construct pipelines on certain of our leaseholds in
New Mexico. The Hagerman gathering system is currently being extended to additional productive
areas.
Our current investment percentage in the two remaining ventures is as follows:
|
|
|
|
|
West Fork Pipeline Company II, L.P. |
|
|
35.8750 |
% |
Hagerman Gas Gathering System |
|
|
76.5000 |
% |
Our investment in Hagerman is accounted for by the equity method since we do not have voting
control. All significant actions taken by Hagerman must be approved by Parallel, plus one of the
two other equity owners. Consequently, the remaining equity owners can prevent voting control by
Parallel.
Our equity investments consisted of the following as of the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2007 |
|
|
2006 |
|
|
|
($ in thousands) |
|
West Fork Pipeline Company II, L.P. |
|
$ |
306 |
|
|
$ |
280 |
|
Hagerman Gas Gathering System |
|
|
8,315 |
|
|
|
6,174 |
|
|
|
|
|
|
|
|
|
|
$ |
8,621 |
|
|
$ |
6,454 |
|
|
|
|
|
|
|
|
Our losses from equity investments were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
|
($ in thousands) |
|
|
($ in thousands) |
|
West Fork Pipeline Company I, L.P. |
|
$ |
|
|
|
$ |
169 |
|
|
$ |
|
|
|
$ |
195 |
|
West Fork Pipeline Company II, L.P. |
|
|
|
|
|
|
(15 |
) |
|
|
5 |
|
|
|
(35 |
) |
West Fork Pipeline Company V, L.P. |
|
|
|
|
|
|
(22 |
) |
|
|
|
|
|
|
(57 |
) |
Hagerman Gas Gathering System |
|
|
(69 |
) |
|
|
(171 |
) |
|
|
(668 |
) |
|
|
(171 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(69 |
) |
|
$ |
(39 |
) |
|
$ |
(663 |
) |
|
$ |
(68 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
(15)
Summarized combined financial information for our equity investments (listed above) is
reported below. Amounts represent 100% of the investees financial information:
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
December 31, |
|
|
2007 |
|
2006 |
|
|
($ in thousands) |
Balance Sheet |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
601 |
|
|
$ |
1,408 |
|
Non-current assets |
|
|
11,032 |
|
|
|
8,351 |
|
Current liabilities |
|
|
541 |
|
|
|
1,329 |
|
Owners equity |
|
|
11,092 |
|
|
|
8,430 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
|
($ in thousands) |
|
|
($ in thousands) |
|
Income Statement |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
181 |
|
|
$ |
1,276 |
|
|
$ |
346 |
|
|
$ |
2,383 |
|
Costs and expenses |
|
|
(426 |
) |
|
|
(963 |
) |
|
|
(1,234 |
) |
|
|
(1,971 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(245 |
) |
|
$ |
313 |
|
|
$ |
(888 |
) |
|
$ |
412 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 11. COMMITMENTS AND CONTINGENCIES
From time to time, we are party to ordinary routine litigation incidental to our business. We
are not presently a defendant in any judicial or other proceedings, nor are we aware of any
threatened litigation and we have not been a party to any bankruptcy, receivership, reorganization,
adjustment or similar proceeding.
Effective January 1, 2005, we established a 401(k) Plan and Trust for eligible employees.
Employees may not participate in the former SEP plan with the establishment of the 401(k) Plan and
Trust. As of the fiscal quarters ended September 30, 2007 and 2006, Parallel had made
contributions to the 401(k) Plan and Trust of approximately $201,000 and $170,000, respectively.
On May 21, 2007, we received a Notice of Proposed Adjustment, or the Notice, from the
Internal Revenue Service, or the Service, advising us of proposed adjustments to our calculations
of federal income tax resulting in a proposed alternative minimum tax liability in the aggregate
amount of approximately $2.0 million for the years 2004 and 2005. After advising the Service that
we intended to appeal the Notice, we received correspondence from the Service on July 10, 2007
stating that the issue remains in development pending receipt of additional documents requested and
any proposed tax adjustment would not be made until after reviewing
the documents requested. On November 5, 2007, we received an
examination report related to this matter which reduces the amount of
proposed adjustment to approximately $1.1 million, which includes
interest. We
intend to vigorously contest the adjustment proposed by the Service and believe that we will
ultimately prevail in our position. We would expect the recording of any adjustment, if later
determined to be required, to entail a reclassification from our deferred tax liability accounts to
a current liability for federal income taxes payable. Such an adjustment would generally not
result in a charge to earnings except for amounts which might be
assessed for penalties or interest
on underpayment
(16)
of current tax for our fiscal years ending December 31, 2004 and 2005. If a
liability for penalties or interest were determined to be probable, the amounts of such penalties
and/or interest would be charged to earnings. We believe that the effects of this matter would not
have a material adverse effect on our financial position or results of operations for any fiscal
year, but could have a material adverse effect on our results of operations for the fiscal quarter
in which we actually incur or establish a reserve account for penalties or interest.
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 2006 Annual Report on Form 10-K/A, 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.
Accelerate Horizontal Drilling and Fracture Stimulation Activities in Gas Resource Plays. We
believe the use of horizontal drilling and fracture stimulations has enabled us to develop reserves
economically, 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
nascent 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.
(17)
Conduct Exploratory Activities. Although we do not emphasize exploratory drilling, we will
selectively undertake exploratory projects that have known geological and reservoir
characteristics, are in close proximity to existing wells so data from the existing wells can be
correlated with seismic data on or near the prospect being evaluated, and that could have a
potentially meaningful impact on our reserves.
The extent to which we are able to implement and follow through with our business strategy
will be influenced by:
|
|
|
the prices we receive for the oil and natural gas we produce; |
|
|
|
|
the results of reprocessing and reinterpreting our 3-D seismic data; |
|
|
|
|
the results of our drilling activities; |
|
|
|
|
the costs of obtaining high quality field services; |
|
|
|
|
our ability to find and consummate acquisition opportunities; and |
|
|
|
|
our ability to negotiate and enter into work to earn arrangements, joint venture or
other similar agreements on terms acceptable to us. |
Significant changes in the prices we receive for the oil and natural gas we produce, or the
occurrence of unanticipated events beyond our control may cause us to defer or deviate from our
business plan, including the amounts we have budgeted for our activities.
Operating Performance
Our operating performance is influenced by several factors, the most significant of which are
the prices we receive for our oil and natural gas and our production volumes. The world price for
oil has overall influence on the prices that we receive for our oil production. The prices
received for different grades of oil are based upon the world price for oil, which is then adjusted
based upon the particular grade. Typically, light oil is sold at a premium, while heavy grades of
crude are discounted. Natural gas prices we receive are influenced by:
|
|
|
seasonal demand; |
|
|
|
|
weather; |
|
|
|
|
hurricane conditions in the Gulf of Mexico; |
|
|
|
|
availability of pipeline transportation to end users; |
|
|
|
|
proximity of our wells to major transportation pipeline infrastructures; and |
|
|
|
|
to a lesser extent, world oil prices. |
Additional factors influencing our overall operating performance include:
|
|
|
production expenses; |
|
|
|
|
overhead requirements; |
|
|
|
|
costs of capital; and |
|
|
|
|
effects of derivative contracts. |
(18)
Our oil and natural gas exploration, development and acquisition activities require
substantial and continuing capital expenditures. Historically, the sources of financing to fund
our capital expenditures have included:
|
|
|
cash flow from operations; |
|
|
|
|
sales of our equity and debt securities; |
|
|
|
|
bank borrowings; and |
|
|
|
|
industry joint ventures. |
For the three months ended September 30, 2007 the sale price we received for our crude oil
production (excluding hedges) averaged $69.45 per barrel compared with $64.53 per barrel for the
three months ended September 30, 2006. The average sales price we received for natural gas for the
three months ended September 30, 2007, was $5.81 per Mcf compared with $5.64 per Mcf for the three
months ended September 30, 2006. Hedge costs for oil were $3.3 million for the three months
ended September 30, 2006. The ineffective portion showed a gain of approximately $305,000 for the
three months ended September 30, 2006. We settled all remaining derivatives classified as cash
flow hedges in December 2006. Therefore, no ineffectiveness on hedges was identified in 2007. For
information regarding prices received including our hedges, you should refer to the selected
operating data table under Results of Operations on page
20.
For the nine months ended September 30, 2007, the sale price we received for our crude oil
production (excluding hedges) averaged $59.98 per barrel compared with $61.88 per barrel for the
nine months ended September 30, 2006. The average sales price we received for natural gas for the
nine months ended September 30, 2007, was $6.14 per Mcf compared with $6.11 per Mcf for the nine
months ended September 30, 2006. Hedge costs for oil and natural gas was $9.3 million for the
nine months ended September 30, 2006. The ineffective portion showed a gain approximately $500,000
for the nine months ended September 30, 2006. We settled all remaining derivatives classified as
cash flow hedges in December 2006. Therefore, no ineffectiveness on hedges was identified in 2007.
For information regarding prices received including our hedges, you should refer to the selected
operating data table under Results of Operations on page
20.
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. Depletion per BOE through
September 30, 2007 and 2006 was $12.84 and $10.53 respectively.
(19)
Results of Operations
Our business activities are characterized by frequent, and sometimes significant, changes in
our:
|
|
|
reserve base; |
|
|
|
|
sources of production; |
|
|
|
|
product mix (gas versus oil volumes); and |
|
|
|
|
the prices we receive for our oil and natural gas production. |
Year-to-year or other periodic comparisons of the results of our operations can be difficult
and may not fully and accurately describe our condition. The following table shows selected
operating data for each of the three and nine months ended September 30, 2007 and September 30,
2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
9/30/2007 |
|
|
9/30/2006 |
|
|
9/30/2007 |
|
|
9/30/2006 |
|
|
|
|
|
|
|
(in thousands, except per unit data) |
|
|
|
|
|
Production Volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
254 |
|
|
|
282 |
|
|
|
797 |
|
|
|
848 |
|
Natural gas (Mcf) |
|
|
2,043 |
|
|
|
2,001 |
|
|
|
5,243 |
|
|
|
4,894 |
|
BOE (1) |
|
|
595 |
|
|
|
616 |
|
|
|
1,671 |
|
|
|
1,664 |
|
BOE per day |
|
|
6.5 |
|
|
|
6.7 |
|
|
|
6.1 |
|
|
|
6.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per
Bbl) (2) |
|
$ |
69.45 |
|
|
$ |
64.53 |
|
|
$ |
59.98 |
|
|
$ |
61.88 |
|
Natural gas (per Mcf) |
|
$ |
5.81 |
|
|
$ |
5.64 |
|
|
$ |
6.14 |
|
|
$ |
6.11 |
|
BOE price (2) |
|
$ |
49.62 |
|
|
$ |
47.91 |
|
|
$ |
47.86 |
|
|
$ |
49.50 |
|
BOE price (3) |
|
$ |
49.62 |
|
|
$ |
42.58 |
|
|
$ |
47.86 |
|
|
$ |
43.93 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
17,619 |
|
|
$ |
18,194 |
|
|
$ |
47,786 |
|
|
$ |
52,478 |
|
Oil hedge |
|
|
|
|
|
|
(3,279 |
) |
|
|
|
|
|
|
(9,264 |
) |
Natural gas |
|
|
11,868 |
|
|
|
11,296 |
|
|
|
32,171 |
|
|
|
29,882 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
29,487 |
|
|
$ |
26,211 |
|
|
$ |
79,957 |
|
|
$ |
73,096 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
|
$ |
6,445 |
|
|
$ |
5,323 |
|
|
$ |
16,420 |
|
|
$ |
12,639 |
|
Production taxes |
|
|
1,448 |
|
|
|
1,538 |
|
|
|
3,696 |
|
|
|
4,116 |
|
Production tax refund |
|
|
|
|
|
|
|
|
|
|
(1,209 |
) |
|
|
|
|
General and administrative |
|
|
2,492 |
|
|
|
2,405 |
|
|
|
7,737 |
|
|
|
7,147 |
|
Depreciation, depletion and amortization |
|
|
7,821 |
|
|
|
7,420 |
|
|
|
21,680 |
|
|
|
17,848 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
18,206 |
|
|
$ |
16,686 |
|
|
$ |
48,324 |
|
|
$ |
41,750 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
11,281 |
|
|
$ |
9,525 |
|
|
$ |
31,633 |
|
|
$ |
31,346 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
A BOE means one barrel of oil equivalent using the ratio of six Mcf of gas
to one barrel of oil. |
|
(2) |
|
Unhedged price is the actual price received at the wellhead for our oil. |
|
(3) |
|
Hedged price is the actual price received at the wellhead for our oil and natural
gas plus or minus the settlements on our cash flow hedges. |
(20)
RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2007 AND 2006:
Our oil and natural gas revenues and production product mix are displayed in the following
table for the three months ended September 30, 2007 and September 30, 2006.
Oil
and Gas Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues(1) |
|
Production |
|
|
2007 |
|
2006 |
|
2007 |
|
2006 |
Oil (Bbls) |
|
|
60 |
% |
|
|
57 |
% |
|
|
43 |
% |
|
|
46 |
% |
Natural gas (Mcf) |
|
|
40 |
% |
|
|
43 |
% |
|
|
57 |
% |
|
|
54 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes hedge transactions |
The following table shows our production volumes, product sales prices and operating revenues
for the following periods.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Increase |
|
|
% Increase |
|
|
|
2007 |
|
|
2006 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
|
|
|
|
(in thousands except per unit data) |
|
|
|
|
|
Production Volumes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
254 |
|
|
|
282 |
|
|
|
(28 |
) |
|
|
(10 |
)% |
Natural gas (Mcf) |
|
|
2,043 |
|
|
|
2,001 |
|
|
|
42 |
|
|
|
2 |
% |
BOE |
|
|
595 |
|
|
|
616 |
|
|
|
(22 |
) |
|
|
(3 |
)% |
BOE/Day |
|
|
6.5 |
|
|
|
6.7 |
|
|
|
(0.2 |
) |
|
|
(3 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)(1) |
|
$ |
69.45 |
|
|
$ |
64.53 |
|
|
$ |
4.92 |
|
|
|
8 |
% |
Natural gas (per Mcf) |
|
$ |
5.81 |
|
|
$ |
5.64 |
|
|
$ |
0.17 |
|
|
|
3 |
% |
BOE price(1) |
|
$ |
49.62 |
|
|
$ |
47.91 |
|
|
$ |
1.71 |
|
|
|
4 |
% |
BOE price(2) |
|
$ |
49.62 |
|
|
$ |
42.58 |
|
|
$ |
7.04 |
|
|
|
17 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
17,619 |
|
|
$ |
18,194 |
|
|
$ |
(575 |
) |
|
|
(3 |
)% |
Oil hedges |
|
|
|
|
|
|
(3,279 |
) |
|
|
3,279 |
|
|
|
(100 |
)% |
Natural gas |
|
|
11,868 |
|
|
|
11,296 |
|
|
|
572 |
|
|
|
5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
29,487 |
|
|
$ |
26,211 |
|
|
$ |
3,276 |
|
|
|
12 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Excludes hedge transactions. |
|
(2) |
|
Includes hedge transactions. |
Oil revenues
Average oil prices, excluding hedges, for the three months ended September 30, 2006 were
$64.53, as compared to $69.45 for the three months ended September 30, 2007. Average oil prices
were up $4.92 Bbl. When applied to current production, this accounts for an additional $1.2 million
in revenue. Oil production decreased 10% or 28,000 Bbls. These decreases occurred primarily in
the Carm-Ann of 11,000 Bbls, Diamond M Deep of 11,000 Bbls and the Wilcox area in south Texas of
4,000 Bbls. These decreases were as a result of natural declines and limited developmental
activity occurring in 2007 in these areas. The volume decline accounted for a reduction of $1.8
million in revenue.
(21)
Natural gas revenues
Average natural gas prices for three months ended September 30, 2006 was $5.64 compared to the
three months ended September 30, 2007 of $5.81. Average natural
gas prices received were up $0.17 per Mcf, when applied to current production this accounted for an increase of approximately
$347,000 in revenue. Natural gas production increased 2%, primarily due to an increase in the New Mexico Wolfcamp of
approximately 412,000 Mcf. This was as of a result of the developmental program in this area. This volume increase
was offset with decreases in south Texas of approximately 302,000 Mcf which is as a result of
normal decline and Parallel refocusing activity away from this area. In addition there was a
decline of approximately 45,000 Mcf in the Permian area where limited developmental drilling
activity has occurred during 2007. This volume increase accounted for an increase in revenue of
approximately $225,000.
Oil hedges
We settled all remaining derivatives classified as cash flow hedges in December 2006.
Therefore, oil hedge losses were $0 for three months ended September 30, 2007 compared to a loss of
$3.2 million for three months ended September 30, 2006.
Cost
and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, |
|
|
Increase |
|
|
% Increase |
|
|
|
2007 |
|
|
2006 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
|
|
|
|
(dollars in thousands) |
|
|
|
|
|
Lease operating expense |
|
$ |
6,445 |
|
|
$ |
5,323 |
|
|
$ |
1,122 |
|
|
|
21 |
% |
Production taxes |
|
|
1,448 |
|
|
|
1,538 |
|
|
|
(90 |
) |
|
|
(6 |
)% |
General and administrative |
|
|
2,492 |
|
|
|
2,405 |
|
|
|
87 |
|
|
|
4 |
% |
Depreciation, depletion and amortization |
|
|
7,821 |
|
|
|
7,420 |
|
|
|
401 |
|
|
|
5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
18,206 |
|
|
$ |
16,686 |
|
|
$ |
1,520 |
|
|
|
9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
Lease operating expenses are up primarily due to workover expenditures incurred in 2007. We
are currently performing workovers on several of our older oil properties and this has led to an
increase in this category of approximately $610,000. As we begin our drilling program on these oil
properties, we expect these costs to go down. In addition we incurred approximately $691,000 in
charges on new wells during the third quarter 2007 that had not been drilled in 2006. As we drill
additional wells our lease operating expenses will go up. Lifting costs (excluding production
taxes) were $10.84 per BOE in 2007 compared to $8.64 per BOE in 2006, a 25% increase in our per BOE
lifting costs.
Production taxes
Production taxes decreased 6% or $90,000 in 2007, associated with an approved reduced tax rate
on non-operated wells in the Wilcox area of south Texas. We were notified of these rates in June
2007. Production taxes are a function of product mix, production volumes and product prices.
General and administrative
General and administrative expenses increased 4%, or approximately $87,000, in 2007 as
compared to 2006. This increase was primarily due to increases in legal fees of approximately
$150,000. Salary costs were up $86,000 which offset a reduction in contract labor costs of
$105,000. On a BOE basis, general and administrative expenses were $4.20 per BOE in 2007 compared to
$3.90 per BOE in 2006.
(22)
Depreciation, depletion and amortization
Depreciation, depletion and amortization expense increased 5%, or $401,000, for 2007 as
compared to 2006. This increase is attributable to an overall increase in actual and anticipated
drilling costs and related oilfield service costs. Increased cost levels affect both the
depletable amounts of capitalized costs in 2007 and the depletion attributable to amounts of
estimated future development costs on proved undeveloped properties. Throughout 2007, our actual
drilling activity and a majority of our newly identified proved undeveloped locations have been in
our natural gas resource projects in the Permian Basin of west Texas and the Barnett Shale areas.
These areas have higher associated per BOE drilling and development costs due to the use of horizontal drilling and multi-stage stimulation techniques. These
factors, when combined with the increase in the absolute level of our capital expenditures during
this time period have led to increases in our depletion rate per BOE.
Other
income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, |
|
|
Increase |
|
|
% Increase |
|
|
|
2007 |
|
|
2006 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
|
|
|
|
(dollars in thousands) |
|
|
|
|
|
Gain (loss) on derivatives not classified as hedges |
|
$ |
(4,556 |
) |
|
$ |
10,323 |
|
|
|
(14,879 |
) |
|
|
(144 |
)% |
Gain on ineffective portion of hedges |
|
|
|
|
|
|
305 |
|
|
|
(305 |
) |
|
|
(100 |
)% |
Interest and other income |
|
|
55 |
|
|
|
29 |
|
|
|
26 |
|
|
|
90 |
% |
Interest expense, net |
|
|
(5,429 |
) |
|
|
(3,345 |
) |
|
|
(2,084 |
) |
|
|
62 |
% |
Cost of debt retirement |
|
|
(760 |
) |
|
|
|
|
|
|
(760 |
) |
|
|
N/A |
|
Other expense |
|
|
(76 |
) |
|
|
(96 |
) |
|
|
20 |
|
|
|
(21 |
)% |
Equity in loss of pipelines
and gathering system ventures |
|
|
(69 |
) |
|
|
(39 |
) |
|
|
(30 |
) |
|
|
77 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(10,835 |
) |
|
$ |
7,177 |
|
|
$ |
(18,012 |
) |
|
|
(251 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives not classified as hedges
We recorded a loss of $4.6 million in 2007 for derivatives not classified as hedges, as
compared to a gain of $10.3 million for 2006. Future gains or losses on derivatives not classified
as hedges will be impacted by the volatility of commodity prices and interest rates, as well as by
the terms of any new derivative contracts.
Interest expense
Interest expense increased $2.0 million with the $92 million increase in principal amount of
our debt from $147.0 million at September 30, 2006 to $239.0 million at September 30, 2007 along
with an increase in our weighted average interest rates for 2007.
Cost of debt retirement
Cost of debt retirement represent the write off of previously capitalized debt issuance costs
associated with our Second Lien Term Loan that was retired with the proceeds of our senior notes
offering.
Equity in loss of pipelines and gathering system ventures
During 2006, we and two other unaffiliated parties formed a joint venture known as the
Hagerman Gas Gathering System, which was formed for the purpose of constructing, owning and
operating a
(23)
gas gathering system in New Mexico. For the quarter ended September 30, 2007, the loss
from the investment was approximately $69,000. This loss was offset by an insignificant amount of
income from our equity investment in West Fork Pipeline II. We recognize our share of net loss
from negative net operating income as an investment loss.
Federal income tax
Federal income tax expense was approximately $153,000 in 2007 compared to $5.7 million in
2006. Income tax expense for 2007 will be dependent on our earnings and is expected to be
approximately 35% of income before income taxes.
Basic and diluted net income
We had basic and diluted net income per share of $0.01 and $.30 for 2007 and 2006,
respectively. Basic weighted average common shares outstanding increased from 36.2 million shares
in 2006 to 38.0 million shares in 2007. The increase in common shares was primarily due to our
public offering of 2.5 million shares of common stock in August 2006 and the exercise of employee and non-employee
stock options.
RESULTS OF OPERATIONS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2007 AND 2006:
Our oil and natural gas revenues and production product mix are displayed in the following
table for the nine months ended September 30, 2007 and September 30, 2006.
Oil
and Gas Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues(1) |
|
Production |
|
|
2007 |
|
2006 |
|
2007 |
|
2006 |
Oil (Bbls) |
|
|
60 |
% |
|
|
59 |
% |
|
|
48 |
% |
|
|
51 |
% |
Natural gas (Mcf) |
|
|
40 |
% |
|
|
41 |
% |
|
|
52 |
% |
|
|
49 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes hedge transactions |
(24)
The following table shows our production volumes, product sale prices and operating revenues
for the following periods.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
Increase |
|
|
% Increase |
|
|
|
2007 |
|
|
2006 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
|
|
|
|
(in thousands except per unit data) |
|
|
|
|
|
Production Volumes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
797 |
|
|
|
848 |
|
|
|
(51 |
) |
|
|
(6 |
)% |
Natural gas (Mcf) |
|
|
5,243 |
|
|
|
4,894 |
|
|
|
349 |
|
|
|
7 |
% |
BOE |
|
|
1,671 |
|
|
|
1,664 |
|
|
|
7 |
|
|
|
0 |
% |
BOE/Day |
|
|
6.1 |
|
|
|
6.1 |
|
|
|
|
|
|
|
0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)(1) |
|
$ |
59.98 |
|
|
$ |
61.88 |
|
|
$ |
(1.90 |
) |
|
|
(3 |
)% |
Natural gas (per Mcf) |
|
$ |
6.14 |
|
|
$ |
6.11 |
|
|
$ |
0.03 |
|
|
|
0 |
% |
BOE price(1) |
|
$ |
47.86 |
|
|
$ |
49.50 |
|
|
$ |
(1.64 |
) |
|
|
(3 |
)% |
BOE price(2) |
|
$ |
47.86 |
|
|
$ |
43.93 |
|
|
$ |
3.93 |
|
|
|
9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
47,786 |
|
|
$ |
52,478 |
|
|
|
(4,692 |
) |
|
|
(9 |
)% |
Oil hedges |
|
|
|
|
|
|
(9,264 |
) |
|
|
9,264 |
|
|
|
(100 |
)% |
Natural gas |
|
|
32,171 |
|
|
|
29,882 |
|
|
|
2,289 |
|
|
|
8 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
79,957 |
|
|
$ |
73,096 |
|
|
$ |
6,861 |
|
|
|
9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Excludes hedge transactions. |
|
(2) |
|
Includes hedge transactions. |
Oil revenues
Average wellhead realized crude oil prices decreased $1.90 per Bbl, or 3%, to $59.98 per Bbl
for 2007, as compared to 2006. This price decrease caused our revenues to go down by approximately
$1.5 million in 2007, as compared to 2006. Oil production decreased 6% attributable to a decline
of approximately 35,000 Bbls, 31,000 Bbls and 28,000 Bbls in the Diamond M Deep, Carm-Ann and south
Texas area, respectively comparing the nine months ended September 30, 2007 to nine months ended
2006. These decreases were as a result of natural declines and limited developmental activity
occurring. We are currently refocusing our efforts away from the south Texas area. These
decreases were partially offset with increases in the Harris field where we benefited from our
development program in 2006. The decrease in oil production decreased revenue approximately $3.2
million for 2007.
Natural gas revenues
Average realized wellhead natural gas prices received were up slightly to $6.14 per Mcf for
the nine months ended September 30, 2007 from $6.11 per Mcf received for the nine months ended
September 30, 2006. This slight price increase accounted for an increase in revenue of
approximately $200,000. Natural gas production increased 7% primarily due to new wells in New
Mexico Wolfcamp area where volumes were up 1.3 million Mcf and the Barnett Shale area where volumes
were up approximately 260,000 Mcf offset by a decline of approximately 1.1 million Mcf in our south Texas
wells comparing nine months ended September 30, 2007 to nine months ended 30, 2006. The increase in
natural gas volumes increased revenue approximately $2.1 million for 2007.
(25)
Oil hedges
We settled all remaining derivatives classified as cash flow hedges in December 2006.
Therefore, oil hedge losses were $0 in 2007 compared to a loss of approximately $9.3 million in
2006. On a BOE basis, hedges accounted for a realized loss of $5.57 per BOE in 2006.
Cost
and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, |
|
|
Increase |
|
|
% Increase |
|
|
|
2007 |
|
|
2006 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
|
|
|
|
(dollars in thousands) |
|
|
|
|
|
Lease operating expense |
|
$ |
16,420 |
|
|
$ |
12,639 |
|
|
$ |
3,781 |
|
|
|
30 |
% |
Production taxes |
|
|
3,696 |
|
|
|
4,116 |
|
|
|
(420 |
) |
|
|
(10 |
)% |
Production tax refund |
|
|
(1,209 |
) |
|
|
|
|
|
|
(1,209 |
) |
|
|
N/A |
|
General and administrative |
|
|
7,737 |
|
|
|
7,147 |
|
|
|
590 |
|
|
|
8 |
% |
Depreciation, depletion and amortization |
|
|
21,680 |
|
|
|
17,848 |
|
|
|
3,832 |
|
|
|
21 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
48,324 |
|
|
$ |
41,750 |
|
|
$ |
6,574 |
|
|
|
16 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
Lease operating expenses are primarily higher due to new wells being put on line. Of the $3.8
million increase, $2.3 million of these charges are on wells that have been completed in the past
year or completed late in the year during 2006; therefore costs are higher for the nine months
ended September 30, 2007 compared to the same period 2006. Well repair and workover expenses
increased approximately $1.5 million to $2.4 million for the nine months ended September 30, 2007
compared to approximately $900,000 for the nine months ended September 30, 2006. This is as a
result of higher overall costs for such items and as we have refocused our efforts on lease
maintenance and away from developmental activity during 2007 on our oil properties. Lifting costs
(excluding production taxes) were $9.83 per BOE in 2007 compared to $7.60 per BOE in 2006.
Production taxes
Production taxes decreased 10% or $420,000 in 2007. The decrease is a result of a reduction of
our oil production during 2007 compared to 2006. Production taxes in the future periods will be a
function of product mix, production volumes and product prices.
A production tax refund was received in June 2007 in the amount of $1.2 million for gas
production taxes on non-operated wells in the Wilcox area of south Texas for production periods
March 2005 through January 2007. This refund was received by the operator of these wells only
after the operators application for tax abatement was approved by state regulatory agencies. The
reduction in our production tax expense was recognized only when approval of the application for
tax abatement was granted by the state.
General and administrative
General and administrative expenses increased 8%, or approximately $590,000, in 2007 as
compared to 2006. This increase is due primarily to consulting and legal fees associated with
accounting and other public reporting requirements. These associated costs were up $674,000.
Also, higher salary expenses of $365,000 associated with a larger staff and increased salary rates
were incurred in 2007. In addition, insurance premiums increased that we pay for our directors and
officers insurance. As a result, we incurred additional expenditures of $104,000 for this
insurance. Finally, we reduced the amount of capitalized general and administrative expenses
during 2007 by $230,000 from $1.3 million to $1.1 million.
(26)
The above general and administrative increases were partially offset by decreases in bonus
expenditures and stock option expenses. During the second quarter of 2006, we determined that
stock options to purchase 30,000 shares of common stock, which were granted in 2003, were not
available for grant under our existing stock option plans. In June 2006, these excess options
were cancelled in exchange for our payment to four employees of cash totaling approximately
$511,000. This amount was charged to expense during the second quarter 2006. During the second
quarter of 2007, we revised our estimates of expected forfeitures of stock options granted to
directors due to the resignation of a director and the subsequent forfeiture of 40,000 stock
options held by him. As a result, we revised our estimate of the grant date fair value of shares
expected to ultimately vest under our stock option plan by approximately $283,000.
Depreciation, depletion and amortization
Depreciation, depletion and amortization expense increased 21%, or $3.8 million, for 2007 as
compared to 2006. Depletion per BOE was $12.84 for 2007 and $10.53 for 2006. This increase is
attributable to an overall increase in actual and anticipated drilling costs and related oilfield
service costs. Increased cost levels affect both the depletable amounts of capitalized costs in
2007 and the depletion attributable to amounts of estimated future development costs on proved
undeveloped properties. Throughout 2007, our actual drilling activity and a majority of our newly
identified proved undeveloped locations have been in our natural gas resource projects in the
Permian Basin of west Texas and the Barnett Shale areas. These areas have higher associated per
BOE drilling and development costs due to the use of horizontal drilling and multi-stage
stimulation techniques. These factors, when combined with the increase in the absolute level of
our capital expenditures during this time period have led to a significant increase in our
depletion rate per BOE.
Other
income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, |
|
|
Increase |
|
|
% Increase |
|
|
|
2007 |
|
|
2006 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
|
|
|
|
(dollars in thousands) |
|
|
|
|
|
Gain (loss) on derivatives not classified as hedges |
|
$ |
(11,161 |
) |
|
$ |
116 |
|
|
$ |
(11,277 |
) |
|
|
(9,722 |
)% |
Gain on ineffective portion of hedges |
|
|
|
|
|
|
500 |
|
|
|
(500 |
) |
|
|
(100 |
)% |
Interest and other income |
|
|
163 |
|
|
|
122 |
|
|
|
41 |
|
|
|
34 |
% |
Interest expense, net |
|
|
(13,449 |
) |
|
|
(8,944 |
) |
|
|
(4,505 |
) |
|
|
50 |
% |
Cost of debt retirement |
|
|
(760 |
) |
|
|
|
|
|
|
(760 |
) |
|
|
N/A |
|
Other expense |
|
|
(91 |
) |
|
|
(164 |
) |
|
|
73 |
|
|
|
(45 |
)% |
Equity in loss of pipelines
and gathering system ventures |
|
|
(663 |
) |
|
|
(68 |
) |
|
|
(595 |
) |
|
|
875 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(25,961 |
) |
|
$ |
(8,438 |
) |
|
$ |
(17,523 |
) |
|
|
208 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives not classified as hedges
We recorded a loss of $11.1 million in 2007 for derivatives not classified as hedges, as
compared to a gain of $116,000 for 2006. Future gains or losses on derivatives not classified as
hedges will be impacted by the volatility of commodity prices and interest rates, as well as by the
terms of any new derivative contracts.
(27)
Interest expense
Interest expense increased with the $92.0 million increase in the principal amount of our debt
from approximately $147.0 million at September 30, 2006 to $239.0 million at September 30, 2007
along with an increase in our weighted average loan interest rate for 2007.
Capitalized interest on work in progress decreased interest expense by $393,000 in 2007, a
decrease of $153,000 compared to 2006.
Cost of debt retirement
Cost of debt retirement represent the write off of previously capitalized debt issuance costs
associated with our Second Lien Term Loan that was retired with the proceeds of our senior notes
offering.
Equity in loss of pipelines and gathering system venturers
The loss associated with our equity investments increased $595,000 from $68,000
in 2006 to $663,000 in 2007. This change was primarily due to the Hagerman Gas Gathering System in New Mexico being operational
for the entire nine months of 2007 versus a few months in 2006.
During both 2006 and the 2007, production levels and related
transportation volumes were not sufficient for profitable operation
of this system. This resulted in an increase in our equity loss for this investment of
$496,000. In addition, substantially all of the assets of West Fork
Pipeline Company I and West Fork Pipeline Company V were sold in the fourth
quarter of 2006. Without the operating results of these investments, our equity investment loss increased $139,000 for 2007.
Federal income tax
Federal income tax expense was $2.0 million in 2007 compared to $7.8 million in 2006. Income
tax expense for 2007 will be dependent on our earnings and is expected to be approximately 35% of
income before income taxes.
Basic and diluted net income
We had basic net income per share of $0.10 and $0.43 and diluted net income per share of
$0.09 and $0.42 for 2007 and 2006, respectively. Basic weighted average common shares
outstanding increased from approximately 35.3 million shares in 2006 to approximately 37.8 million
shares in 2007. The increase was primarily due to our public offering of 2.5 million shares of
common stock in August 2006 and the exercise of employee and nonemployee stock options during 2007.
LIQUIDITY AND CAPITAL RESOURCES
Our capital resources consist primarily of cash flows from our oil and natural gas properties
and bank borrowings supported by our oil and natural gas reserves. Our level of earnings and cash
flows depends on many factors, including the prices we receive for oil and natural gas we produce.
Working capital decreased approximately $15.1 million as of September 30, 2007 compared with
December 31, 2006. Current liabilities exceeded current assets by $23.9 million at September 30,
2007. The working capital decrease was due to a decrease in cash and cash equivalents of
approximately $592,000, and by a decrease in accounts receivable of approximately $3.4 million, an
increase in accounts payable of approximately $6.4 million and an increase in current derivative
obligations of $5.8 million.
(28)
We incurred net property costs of $111.5 million for the nine months ended September 30, 2007
compared to $155.1 million for the same period in 2006. The decrease is primarily related to the
Harris acquisition in 2006. Our property expenditures were $110.0 million for the nine months of
2007. Included in our increased property basis for the nine months of 2007 and 2006 were net asset
retirement costs of approximately ($505,000) and $2.0 million, respectively (see Note 8 to
Consolidated Financial Statements). Historically, we have financed capital expenditures primarily
with cash generated by operations, proceeds from bank borrowings and sales of our equity
and debt securities. In addition, we have sold and may consider selling additional assets to raise
additional operating capital. From time to time, we may also reduce our ownership interests in our
projects in order to reduce our capital expenditure requirements.
If our revenues or the borrowing base under our revolving credit facility decreases 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 September 30, 2007 was $190.1 million, as compared to $183.8 million
at December 31, 2006. The increase is primarily attributable to our net income of approximately
$3.7 million and the exercise of employee options of approximately $2.4 million.
Credit Arrangements
In the past, we have maintained two separate credit facilities. One of these credit facilities
is our Third Amended and Restated Credit Agreement, as amended, or the Revolving Credit
Agreement, with a group of bank lenders which, at September 30, 2007, provided us with a revolving
line of credit having a borrowing base limitation of $150.0 million. The total amount that we can
borrow and have outstanding at any one time is limited to the lesser of $350.0 million or the
borrowing base established by the lenders. At September 30, 2007, the principal amount outstanding
under our revolving credit facility was $89.0 million, excluding $445,000 reserved for our letters
of credit. 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 Term Loan Agreement was paid off and terminated on July 31, 2007, with our
payment to the lenders of $50.2 million, including interest. This payment was made with proceeds
from our sale of unsecured senior notes, or senior notes.
On July 31, 2007, we completed a private offering of unsecured senior notes
in the principal amount of $150.0 million.
As described below, in connection with our recent senior notes offering we entered into a
Third Amendment to our Revolving Credit Agreement and paid off and terminated our Second Lien
Agreement.
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 amount is redetermined by
the lenders semi-annually on or about April 1 and October 1 of each year or at other times required
by the lenders or at our request. If, as a result of the lenders redetermination of the borrowing
base, the outstanding principal amount of our loans exceeds the borrowing base, we must either
provide additional collateral to the lenders or repay the outstanding principal of our loans in an
amount equal to the excess. Except for the
(29)
principal payments that may be required because of our
outstanding loans being in excess of the borrowing base, interest only is payable monthly.
Loans made to us under this revolving credit facility bear interest at the base rate of
Citibank, N.A. or the LIBOR rate, at our election. Generally, Citibanks base rate is equal to its
prime rate as announced from time to time by Citibank.
The LIBOR rate is generally equal to the sum of (a) the rate designated as British Bankers
Association Interest Settlement Rates and offered on one, two, three, six or twelve month interest
periods for deposits of $1.0 million, and (b) a margin ranging from 2.00% to 2.50%, depending upon
the outstanding principal amount of the loans. If the principal amount outstanding is equal to or
greater than 75% of the borrowing base, the margin is 2.50%. If the principal amount outstanding is
equal to or greater than 50%, but less than 75% of the borrowing base, the margin is 2.25%. If the
principal amount outstanding is less than 50% of the borrowing base, the margin is 2.00%.
The interest rate we are required to pay on our borrowings, including the applicable margin,
may never be less than 5.00%. At September 30, 2007, our weighted average base and LIBOR rate,
plus margin, was 7.64% on $89.0 million, the outstanding principal amount of our revolving loan on
that date.
In the case of base rate loans, interest is payable on the last day of each month. In the case
of LIBOR loans, interest is payable on the last day of each applicable interest period.
If the total outstanding borrowings under the revolving credit facility are less than the
borrowing base, we are required to pay an unused commitment fee to the lenders in an amount equal
to .25% of the daily average of the unadvanced portion of the borrowing base. The fee is payable
quarterly.
If the borrowing base is increased, we are required to pay a fee of .375% on the amount of any
increase.
All outstanding principal and accrued and unpaid interest under the revolving credit facility
is due and payable on October 31, 2010. The maturity date of our outstanding loans may be
accelerated by the lenders upon the occurrence of an event of default under the Revolving Credit
Agreement.
The Revolving Credit Agreement 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.
As of September 30, 2007, we were in compliance with all of the covenants in our Revolving
Credit Agreement.
On July 31, 2007, we entered into a Third Amendment to the Revolving Credit Agreement upon
completing our senior notes offering. This Third Amendment amended the Revolving Credit Agreement
by, among other things:
|
|
|
reducing the borrowing base from $190.0 million to $150.0 million; |
|
|
|
providing that our ratio of Consolidated Funded Debt to Consolidated EBITDA (as
defined in the Revolving Credit Agreement) shall not exceed (i) 4.25 to 1.00 during the
year 2007; (ii) 4.00 to 1.00 during the year 2008; or (iii) 3.50 to 1.00 during the
year 2009 and thereafter, in |
(30)
|
|
|
each case calculated at the end of each fiscal quarter
using the results of the twelve-month period immediately preceding the end of each such
fiscal quarter; |
|
|
|
allowing for the issuance and sale of the senior notes; |
|
|
|
providing that an event of default under the senior notes will also constitute an
event of default under the Revolving Credit Agreement. |
Second Lien Term Loan Facility
Until July 31, 2007, we also had a $50.0 million term loan available to us under our Second
Lien Term Loan Agreement, or the Second Lien Agreement. Similar to our Revolving Credit
Agreement, interest on loans made to us under this credit facility were, at our election, either an
alternate base rate or a rate designated in the Second Lien Agreement as the LIBO rate. The
alternate base rate is the greater of (a) the prime rate in effect on any day and (b) the Federal
Funds Effective Rate in effect on such day plus -1/2 of 1%, plus a margin of 3.50% per annum.
The LIBO rate was generally equal to the sum of (a) a rate appearing in the Dow Jones Market
Service for the applicable interest periods offered in one, two, three or six month periods and (b)
an applicable margin rate per annum equal to 4.50%.
Our producing oil and natural gas properties were also pledged to secure payment of our
indebtedness under this facility, but the liens granted to the lenders under the Second Lien
Agreement were second and junior to the rights of the lienholders under the Revolving Credit
Agreement.
In the case of alternate base rate loans, interest was payable the last day of each March,
June, September and December. In the case of LIBO loans, interest was payable the last day of the
interest period applicable to each tranche, but not to exceed intervals of three months.
Upon completion of our senior notes offering, we paid off and terminated this facility with
$50.2 million of the net proceeds from the offering. As a result
we charged to earnings $760,000 of previously capitalized debt
issuance cost.
Senior Notes
On July 31, 2007, we completed a private offering of unsecured senior notes (the senior
notes) in the principal amount of $150.0 million. The senior notes were recorded at the
principal amount net of underwriters discount and related expenses of $4.8 million. The senior
notes mature on August 1, 2014 and bear interest at 10.25 % which is payable semi-annually
beginning on February 1, 2008. Considering the discount on the
senior notes, the effective interest
rate is 10.92%. 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.
We have agreed to use our reasonable best efforts to
exchange the senior notes for registered, freely tradable notes which otherwise have substantially
identical terms to the senior notes within 210 days of July 31, 2007.
(31)
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.
The net proceeds, after payment of typical transaction expenses, of the senior notes of
approximately $143.5 million were used first to retire our Second Lien Term Loan with the remainder
being applied to our Revolving Credit Facility.
Shelf Registration
On
October 17, 2007 we filed a registration statement on Form S-3 with the
Securities and Exchange Commission. The universal shelf registration statement
will allow us to issue common stock, preferred stock, warrants, senior debt and subordinated debt
up to an aggregate amount of $250 million.
Under
the registration statement, we may periodically offer one or more of
these securities in amounts, prices and on terms to be announced when and if the securities are
offered. At the time any of the securities covered by the registration statement are offered for
sale, a prospectus supplement will be prepared and filed with the Securities and Exchange
Commission containing specific information about the terms of any such offering.
Interest Accrued
Interest
accrued for the nine months ended September 30, 2007, on our
credit arrangements, was
approximately $13.5 million. Of this amount, approximately $393,000 was capitalized.
Commodity Price Risk Management Transactions and Effects of Derivative Instruments
The purpose of our derivative transactions is to provide a measure of stability in our cash
flows. The derivative trade arrangements we have employed include collars, costless collars,
floors or purchased puts, and oil, natural gas and interest rate swaps. In 2003, we designated our
derivative trades as cash flow hedges under the provisions of SFAS 133, as amended. Although our
purpose for entering into derivative trades has remained the same, contracts entered into after
June 30, 2004 have not been designated as cash flow hedges.
At December 31, 2006, we had no derivatives in place that were designated as cash flow hedges.
All commodity derivative contracts at December 31, 2006 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), net. To the extent these trades relate to production in 2007 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 2007 and beyond are accounted for by
mark-to-market accounting as prescribed in SFAS 133.
We are exposed to credit risk in the event of nonperformance by the counterparties to our
derivative trade instruments. However, we periodically assess the creditworthiness of the
counterparties to mitigate this credit risk.
(32)
Certain of our commodity price risk management arrangements have required us to deliver cash
collateral or other assurances of performance to the counterparties in the event that our payment
obligations with respect to our commodity price risk management transactions exceed certain levels.
Contractual Obligations, Commitments and Off-Balance Sheet Arrangements
We have contractual obligations and commitments that affect our financial position. Based on
our assessment of the provisions and circumstances of our contractual obligations and commitments,
we do not believe these obligations and commitments will materially adversely affect our
consolidated results of operations, financial condition or liquidity.
The following table is a summary of significant contractual obligations as of September 30,
2007:
|
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|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Obligation Due in Period |
|
|
|
Three months |
|
|
|
|
|
|
|
|
|
|
|
|
ending |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
Periods ending December 31, |
|
|
After |
|
|
|
|
Contractual Cash Obligations |
|
2007 |
|
|
2008 |
|
|
2009 |
|
|
2010 |
|
|
2011 |
|
|
5 years |
|
|
Total |
|
|
|
(in thousands) |
|
Revolving Credit Facility
(secured)(1) |
|
$ |
1,714 |
|
|
$ |
6,818 |
|
|
$ |
6,800 |
|
|
$ |
94,663 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
109,995 |
|
|
Senior Notes (unsecured)(2) |
|
|
|
|
|
|
15,418 |
|
|
|
15,375 |
|
|
|
15,375 |
|
|
|
15,375 |
|
|
|
196,125 |
|
|
|
257,668 |
|
|
Office Lease (Dinero Plaza) |
|
|
51 |
|
|
|
210 |
|
|
|
216 |
|
|
|
36 |
|
|
|
|
|
|
|
|
|
|
|
513 |
|
|
Andrews and Snyder Field
Offices(3) |
|
|
5 |
|
|
|
14 |
|
|
|
14 |
|
|
|
14 |
|
|
|
14 |
|
|
|
598 |
|
|
|
659 |
|
|
Asset retirement
obligations(4) |
|
|
474 |
|
|
|
150 |
|
|
|
103 |
|
|
|
122 |
|
|
|
53 |
|
|
|
3,900 |
|
|
|
4,802 |
|
|
Derivative Obligations |
|
|
5,520 |
|
|
|
18,813 |
|
|
|
780 |
|
|
|
225 |
|
|
|
|
|
|
|
|
|
|
|
25,338 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
7,764 |
|
|
$ |
41,423 |
|
|
$ |
23,288 |
|
|
$ |
110,435 |
|
|
$ |
15,442 |
|
|
$ |
200,623 |
|
|
$ |
398,975 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Outstanding principal of $89.0 million due October 31, 2010 and estimated interest obligation
calculated using the weighted average rate at September 30, 2007 of 7.64% |
|
(2) |
|
Principal of $150.0 million due August 1, 2014 bearing interest at 10.25% which is payable
semi-annually beginning February 1, 2008. |
|
(3) |
|
The Snyder office lease expires up on the cessation of
production from the Diamond M area
wells. The Andrews office lease would have expired in December 2007, however, Parallel exercised
an option to purchase this office lease at the end of October 2007. The lease cost for these two
office facilities are billed to nonaffiliated third party working interest owners under our joint
agreements with these third parties. |
|
(4) |
|
Assets retirement obligations of oil and natural gas assets, excluding salvage value and
accretion. |
Deferred taxes are not included in the table above. The utilization of net operating loss
carryforwards combined with our plans for development and acquisitions may offset any major cash
outflows. However, the ultimate timing of the settlements cannot be precisely determined.
We have no off-balance sheet arrangements.
Outlook
The oil and natural gas industry is capital intensive. We make, and anticipate that we will
continue to make, substantial capital expenditures in the exploration for, development and
acquisition of oil and natural gas reserves. Historically, our capital expenditures have been
financed primarily with:
|
|
|
internally generated cash from operations; |
(33)
|
|
|
proceeds from bank borrowings; and |
|
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|
|
proceeds from sales of equity securities. |
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:
|
|
|
increased bank borrowings; |
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|
|
sales of Parallels securities; |
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|
|
sales of non-core properties; or |
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|
other forms of financing. |
Except for the revolving credit facility we have with our bank lenders, we do not have
agreements for any future financing and there can be no assurance as to the availability or terms
of any such financing.
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.
During 2006, the average realized sales price for our oil and natural gas was $48.73
(unhedged) per BOE. For the nine months ended September 30, 2007, our average realized price was
$47.86 (unhedged) 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
(34)
and that a downward trend in our overall production could occur unless these
natural declines are offset by additional production from drilling, workover or recompletions
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. We expect the
completion of additional pipeline capacity to significantly ease these pipeline capacity restraints
beginning in the first half of 2008.
In recent periods, we have concentrated our drilling and development efforts on our resource
natural gas projects in the Barnett Shale and in New Mexico Wolfcamp. Due to limited development
our oil production has decreased in accordance with normal decline curves for our principal Permian
Basin and south Texas oil properties. We have increased our capital budget on the Harris San
Andres field for 2007. We expect our 2008 capital budget to increase on our Permian Basin oil
properties.
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 also 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 per BOE lease operating expense.
Interest Expense Trends
As described above, 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 based on
LIBOR interest rates applicable to our Second Lien Term Loan that was retired and the portion of
our Revolving Credit Facility that was repaid with the net proceeds of the senior notes offering,
we expect our annual interest expense will be increased by approximately $1.0 million. This
incremental effect will increase if LIBOR rates decrease and decrease if LIBOR rates increase in
subsequent periods.
Recent Accounting Pronouncements
We adopted the provisions of Financial Accounting Standards Board (FASB) Interpretation No.
48, Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109 (FIN
48), on January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes
recognized in an enterprises financial statements in accordance with FASB Statement 109,
Accounting for Income Taxes, and prescribes a recognition threshold and measurement process for financial statement
recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48
also provides guidance on derecognition, classification, interest and penalties, accounting in
interim periods, disclosure and transition.
Based on our evaluation, we have concluded that there are no significant uncertain tax
positions requiring recognition in our financial statements. Our evaluation was performed for the
tax years ended December 31, 2003, 2004, 2005 and 2006, the tax years which remain subject to
examination by
(35)
major tax
jurisdictions as of September 30, 2007.
We may from time to time be assessed interest or penalties by major tax jurisdictions,
although any such assessments historically have been minimal and immaterial to our financial
results.
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair
Value Measurements (FAS 157). FAS 157 defines fair value as used in numerous accounting
pronouncements, establishes a framework for measuring fair value in accordance with generally
accepted accounting principles and expands disclosure requirements related to the use of fair value
measures in financial statements. FAS 157 will be effective for our financial statements for the
fiscal year beginning January 1, 2008; however, earlier application is encouraged. We are currently
evaluating the timing of adoption and the impact that adoption might have on our financial position
or results of operations.
In February 2007, the FASB issued SFAS 159, The Fair Value Option for Financial Assets and
Financial Liabilities, Including an Amendment of FASB Statement No. 115, (FAS 159) which will
become effective on January 1, 2008. FAS 159 permits entities to measure eligible financial assets,
financial liabilities and firm commitments at fair value, on an instrument-by-instrument basis,
that are otherwise not permitted to be accounted for at fair value under other generally accepted
accounting principles. The fair value measurement election is irrevocable and subsequent changes in
fair value must be recorded in earnings. We will adopt this statement in the first quarter of 2008
and we do not expect to elect the fair value option for any eligible financial instruments and
other items.
Critical Accounting Policies
Our critical accounting policies are included and discussed in our Annual Report on Form
10-K/A for the year ended December 31, 2006, as filed with the Securities and Exchange Commission
on July 12, 2007. 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 also included in our Annual Report on Form 10-K/A
for the year ended December 31, 2006.
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; |
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|
availability of natural gas gathering and transmission facilities; |
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our business strategy; |
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market prices; |
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sources 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; |
(36)
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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, should, 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; |
|
|
|
|
demand for oil and natural gas; |
|
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|
|
losses due to future litigation; |
|
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|
|
future capital requirements and availability of financing; |
|
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|
|
geological concentration of our reserves; |
|
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|
|
risks associated with drilling and operating wells; |
|
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|
competition; |
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|
general economic conditions; |
|
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|
|
governmental regulations and liability for environmental matters; |
|
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|
|
receipt of amounts owed to us by customers and counterparties to our derivative
contracts; |
|
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|
|
derivative decisions, including whether or not to hedge; |
|
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|
|
terrorist attacks or war; |
|
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|
|
actions of third party co-owners of interests in properties in which we also own an
interest; and |
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|
|
fluctuations in interest rates and availability of capital. |
For these and other reasons, actual results may differ materially from those projected or
implied. We believe it is important to communicate our expectations of future performance to our
investors. However, events may occur in the future that we are unable to accurately predict, or
over which we have no control. We caution you against putting undue reliance on forward-looking
statements or projecting any future results based on such statements.
(37)
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/A for the year ended December 31, 2006.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The following quantitative and qualitative information is provided about market risks and
derivative instruments to which we were a party at September 30, 2007, 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 September 30, 2007
Financial instruments sensitive to changes in interest rates are our senior notes, bank debt and
interest rate swaps. The table below shows principal cash
flows and related weighted average interest rates by expected maturity dates. Weighted average
interest rates were determined using interest rates as of September 30, 2007. You should read Note
3 to the Consolidated Financial Statements for further discussion of our debt that is sensitive to
interest rates.
|
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|
|
|
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|
|
|
|
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|
|
|
|
|
|
|
|
2011 and |
|
|
|
|
2007 |
|
2008 |
|
2009 |
|
2010 |
|
after |
|
Total |
|
|
(in thousands, except interest rates) |
Revolving Facility (secured) |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
89,000 |
|
|
$ |
|
|
|
$ |
89,000 |
|
Average interest rate |
|
|
7.64 |
% |
|
|
7.64 |
% |
|
|
7.64 |
% |
|
|
7.64 |
% |
|
|
|
|
|
|
|
|
Senior notes |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
150,000 |
|
|
$ |
150,000 |
|
Average interest rate |
|
|
10.25 |
% |
|
|
10.25 |
% |
|
|
10.25 |
% |
|
|
10.25 |
% |
|
|
10.25 |
% |
|
|
|
|
As the interest rate is variable and reflects current market conditions, the carrying value of our bank debt approximates the fair value.
Interest
on our senior notes and their carrying value are not affected by
changes in interest rates. However, the fair value of the senior
notes increases as interest rates decrease and their fair value
decreases as interest rates increase. Because the Company has no
present plan or intent to redeem the senior notes, changes in their fair value are not expected to have any effect on
our cash flow in the foreseeable future.
We 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 September 30, 2007, the fair market
value of these interest rate swaps was a liability of approximately $591,000.
(38)
A recap for the period of time, notional amounts, fixed interest rates, and fair market value
of these contracts at September 30, 2007 follows:
|
|
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|
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|
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|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
Notional |
|
|
Fixed |
|
|
Fair |
|
Period of Time |
|
Amounts |
|
|
Interest Rates |
|
|
Market Value |
|
|
|
($ in millions) |
|
|
|
|
|
|
($ in thousands) |
|
October 1, 2007 thru December 31, 2007 |
|
$ |
100 |
|
|
|
4.62 |
% |
|
$ |
161 |
|
January 1, 2008 thru December 31, 2008 |
|
$ |
100 |
|
|
|
4.86 |
% |
|
|
(323 |
) |
January 1, 2009 thru December 31, 2009 |
|
$ |
50 |
|
|
|
5.06 |
% |
|
|
(283 |
) |
January 1, 2010 thru October 31, 2010 |
|
$ |
50 |
|
|
|
5.15 |
% |
|
|
(146 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
$ |
(591 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Price Sensitivity as of September 30, 2007
Our major market risk exposure is in the pricing applicable to our oil and natural gas
production. Market risk refers to the risk of loss from adverse changes in oil and natural gas
prices. Realized pricing is primarily driven by the prevailing domestic price for crude oil and
spot prices applicable to the region in which we produce natural gas. Historically, prices
received for oil and natural gas production have been volatile and unpredictable. We expect
pricing volatility to continue. Oil prices ranged from a low of $51.65 per barrel to a high of
$73.03 per barrel during 2006. Natural gas prices we received during 2006 ranged from a low of
$1.00 per Mcf to a high of $15.11 per Mcf. During the period from January 1, 2007 to September 30,
2007, oil prices ranged from a low of $47.62 to a high of $77.69. Natural gas prices we received
during this time ranged from a low of $1.37 per Mcf to a high of $12.69 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 commodity price
volatility. As of September 30, 2007, we had employed costless collars, collars, and swaps in
order to protect against this price volatility. Although all of the contracts that we have entered
into are viewed as protection against this price volatility, all contracts are accounted for by the
mark-to-market accounting method as prescribed in SFAS 133.
At
September 30, 2007 we had oil collars and swaps in place covering future oil production of
approximately 2.0 million barrels. Subsequent to September 30, 2007, oil futures prices have
increased significantly and have risen to a level that would exceed a substantial portion of the
capped price for each of our oil collars. If futures prices remain at this level, 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 table below. These increases in oil
price will also require us to make larger net settlement payments under commodity swap contracts.
While these payments should not significantly affect our cash flow since payments made to
counterparties to these contracts should be substantially offset by increased commodity prices
received on the sale of our production, the increase in oil prices, should they continue, will
negatively affect the fair value of our commodities contracts as recorded in our balance sheet at
December 31, 2007 and during future periods and, consequently, our reported net earnings. Changes
in the recorded fair value of commodity derivatives are marked to market through earnings and are
likely to result in substantial charges to earnings for the decrease in the fair value of these
contracts during the fourth quarter of 2007. If oil prices continue to increase, this negative
effect on earnings will become more significant. We are currently unable to estimate the effects
on earnings in the fourth quarter of 2007, but the effects may be substantial.
(39)
A description of our active commodity derivative contracts as of September 30, 2007 follows:
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 September 30, 2007 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
Barrles of |
|
NyMex Oil Prices |
|
Fair Market |
Period of Time |
|
Oil |
|
Floor |
|
Cap |
|
Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
October 1, 2007 thru December 31, 2007 |
|
|
73,600 |
|
|
$ |
55.63 |
|
|
$ |
84.88 |
|
|
$ |
(108 |
) |
January 1, 2008 thru December 31, 2008 |
|
|
237,900 |
|
|
$ |
60.38 |
|
|
$ |
81.08 |
|
|
|
(553 |
) |
January 1, 2009 thru December 31, 2009 |
|
|
620,500 |
|
|
$ |
63.53 |
|
|
$ |
80.21 |
|
|
|
(473 |
) |
January 1, 2010 thru October 31, 2010 |
|
|
486,400 |
|
|
$ |
63.44 |
|
|
$ |
78.26 |
|
|
|
(80 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Houston Ship |
|
|
|
|
|
|
M M Btu of |
|
Channel Gas Prices |
|
|
|
|
|
|
Natural Gas |
|
Floor |
|
Cap |
|
|
|
|
October 1, 2007 thru October 31, 2007 |
|
|
31,000 |
|
|
$ |
6.00 |
|
|
$ |
11.05 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
M M Btu of |
|
|
WAHA Gas Prices |
|
|
|
|
|
|
|
Natural Gas |
|
|
Floor |
|
|
Cap |
|
|
|
|
|
October 1, 2007 thru October 31, 2007 |
|
|
93,000 |
|
|
$ |
6.25 |
|
|
$ |
8.90 |
|
|
|
75 |
|
October 1, 2007 thru March 31, 2008 |
|
|
1,098,000 |
|
|
$ |
6.50 |
|
|
$ |
9.50 |
|
|
|
472 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(667 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 summary of our commodity swap
positions at September 30, 2007 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
Number of |
|
|
NyMex Oil |
|
|
Fair Market |
|
Period of Time |
|
Barrels of Oil |
|
|
Swap Price |
|
|
Value |
|
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
|
October 1, 2007 thru December 31, 2007 |
|
|
119,600 |
|
|
$ |
34.36 |
|
|
$ |
(5,411 |
) |
January 1, 2008 thru December 31, 2008 |
|
|
439,200 |
|
|
$ |
33.37 |
|
|
|
(17,923 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total fair market value |
|
|
|
|
|
|
|
|
|
$ |
(23,334 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
(40)
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 September 30, 2007 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. We
are not presently a defendant in any judicial proceedings, nor are we aware of any threatened
litigation and we have not been a party to any bankruptcy, receivership, reorganization, adjustment
or similar proceeding.
On May 21, 2007, we received a Notice of Proposed Adjustment, or the Notice from the
Internal Revenue Service, or the Service, advising us of proposed adjustments to our calculations
of federal income tax resulting in a proposed alternative minimum tax liability in the aggregate
amount of approximately $2.0 million for the years 2004 and 2005. After advising the Service that
we intended to appeal the Notice, we received correspondence from the Service on July 10, 2007
stating that the issue remains in development pending receipt of additional documents requested and
any proposed tax adjustment would not be made until after reviewing
the documents requested. On November 5, 2007, we received an
examination report related to this matter which reduces the amount of
proposed adjustment to approximately $1.1 million, which includes
interest. We
intend to vigorously contest the adjustment proposed by the Service and believe that we will
ultimately prevail in our position. We would expect the recording of any adjustment, if later
determined to be required, to entail a reclassification from our deferred tax liability accounts to
a current liability for federal income taxes payable. Such an adjustment would generally not
result in a charge to earnings except for amounts which might be assessed for penalties or interest
on underpayment of current tax for our fiscal years ending December 31, 2004 and 2005. If a
liability for penalties or interest were determined to be probable, the amounts of such penalties
and/or interest would be charged to earnings. We believe that the effects of this matter would not
have a material adverse effect on our financial position or results of operations for any fiscal
year, but could have a material adverse effect on our results of operations for the fiscal quarter
in which we actually incur or establish a reserve account for penalties or interest.
ITEM 1A. RISK FACTORS
Except as set below, there have been no material changes from the risk factors as previously
disclosed in our Form 10-K/A Report for the fiscal year ended December 31, 2006.
(41)
Risks Relating to the Senior Notes and Our Other Indebtedness
We have a substantial amount of indebtedness which may adversely affect our cash flow and our
ability to operate our business, remain in compliance with debt covenants and make payments on our
debt, including our senior notes.
As of September 30, 2007, our total debt was $239.0 million (of which $150.0 million consisted
of the senior notes due 2014 and $89.0 million consisted of borrowings under our revolving credit
facility). Our level of debt could have important consequences for you, including the following:
|
|
|
we may have difficulty borrowing money in the future for acquisitions, capital
expenditures or to meet our operating expenses or other general corporate obligations; |
|
|
|
|
we will need to use a substantial portion of our cash flows to pay principal and
interest on our debt, which will reduce the amount of money we have for operations,
working capital, capital expenditures, expansion, acquisitions or general corporate or
other business activities; |
|
|
|
we may have a higher level of debt than some of our competitors, which may put us at
a competitive disadvantage; |
|
|
|
|
we may be more vulnerable to economic downturns and adverse developments in our
industry or the economy in general, especially declines in oil and natural gas prices;
and |
|
|
|
|
our debt level could limit our flexibility in planning for, or reacting to, changes
in our business and the industry in which we operate. |
We may incur substantially more debt, which may intensify the risks described above, including
our ability to service our indebtedness.
We may be able to incur substantially more debt in the future. Although the indenture
governing the senior notes and the terms of our revolving credit facility contain restrictions on
our incurrence of additional indebtedness, these restrictions are subject to a number of
qualifications and exceptions, and under certain circumstances, indebtedness incurred in compliance
with these restrictions could be substantial. In addition, the indenture governing the senior notes
and the terms of our revolving credit facility will not prevent us from incurring obligations that
do not constitute indebtedness. To the extent new indebtedness is added to our current
indebtedness levels, the risks described above could substantially intensify.
To service our indebtedness, we will require a significant amount of cash. Our ability to
generate cash depends on many factors beyond our control, and any failure to meet our debt
obligations could harm our business, financial condition and results of operations.
Our ability to make payments on and to refinance our indebtedness, including the senior notes,
and to fund planned capital expenditures will depend on our ability to generate cash from
operations in the future. This, to a certain extent, is subject to general economic, financial,
competitive, legislative, regulatory and other factors that are beyond our control, including the
prices that we receive for oil and natural gas. We cannot assure you that our business will
generate sufficient cash flow from operations or that future borrowings will be available to us
under our revolving credit facility in an amount sufficient to enable us to pay our indebtedness,
including the senior notes, or to fund our other liquidity needs.
If our cash flow and capital resources are insufficient to fund our debt obligations, we may
be forced to sell assets, seek additional equity or debt capital or restructure our debt. The
indenture
(42)
governing the senior notes and the terms of our revolving credit facility restrict our
ability to dispose of assets and use the proceeds from the disposition. We cannot assure you that
any of these remedies could, if necessary, be effected on commercially reasonable terms, or at all.
In addition, any failure to make scheduled payments of interest and principal on our outstanding
indebtedness, including our revolving credit facility, would likely result in a reduction of our
credit rating, which could harm our ability to incur additional indebtedness on acceptable terms.
If we fail to meet our payment obligations under our revolving credit facility, those lenders would
be entitled to foreclose on substantially all of our assets and liquidate those assets. Under
those circumstances, our cash flow and capital resources would be insufficient for payment of
interest on and principal of our debt in the future, including payments on the senior notes, and
any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt
service obligations, which could cause us to default on our obligations, impair our liquidity, or
cause the holders of the senior notes to lose a portion of or the entire value of their investment.
A default on our obligations could result in:
|
|
|
our debt holders declaring all outstanding principal and interest due and payable; |
|
|
|
|
the lenders under our revolving credit facility terminating their commitments to
loan us money and foreclose against the assets securing their loans to us; and |
|
|
|
our bankruptcy or liquidation, which is likely to result in delays in the payment of
the senior notes or the revolving credit facility and in the exercise of enforcement
remedies under the senior notes or our revolving credit facility. |
In addition, provisions under the bankruptcy code or general principles of equity that could
result in the impairment of the rights of the holders of our debt instruments include the automatic
stay, avoidance of preferential transfers by a trustee or a debtor-in-possession, limitations of
collectibility of unmatured interest or attorneys fees and forced restructuring of our debt.
Restrictive debt covenants in the indenture and our revolving credit facility will restrict
our business in many ways.
The indenture governing the senior notes contains a number of significant covenants that,
among other things, restrict our ability to:
|
|
|
transfer or sell assets; |
|
|
|
|
make investments; |
|
|
|
|
pay dividends, redeem subordinated indebtedness or make other restricted payments; |
|
|
|
|
incur or guarantee additional indebtedness or issue disqualified capital stock; |
|
|
|
|
create or incur liens; |
|
|
|
|
incur dividend or other payment restrictions affecting certain subsidiaries; |
|
|
|
|
consummate a merger, consolidation or sale of all or substantially all of our
assets; |
|
|
|
|
enter into transactions with affiliates; and |
(43)
|
|
|
engage in businesses other than the oil and gas business. |
These covenants could limit our ability to obtain future financings, make needed capital
expenditures, withstand a future downturn in our business or the economy in general or otherwise
conduct necessary corporate activities. We may also be prevented from taking advantage of business
opportunities that arise because of the limitations that the restrictive covenants impose on us. A
breach of any of these covenants could result in a default under the senior notes which, if not
cured or waived, could result in acceleration of the senior notes.
In addition, our revolving credit facility contains restrictive covenants and requires us to
maintain specified financial ratios and satisfy other financial condition tests. Our ability to
meet those financial ratios and tests can be affected by events beyond our control, and we cannot
assure you that we will meet those tests. A breach of any of these covenants could result in a
default under the facility. Upon the occurrence of an event of default, under our indenture
governing the senior notes or our revolving credit facility, the lenders could elect to declare all
amounts outstanding under the revolving credit facility to be immediately due and payable and
terminate all commitments to extend further credit. If we were unable to repay those amounts, the
lenders could proceed against the collateral granted to them to secure that indebtedness. We have
pledged substantially all of our assets as collateral under the revolving credit facility. If the
lenders accelerate the repayment of borrowings, we cannot assure you that we will have sufficient
assets to repay our revolving credit facility and our other indebtedness, including the senior
notes.
Our borrowings under our revolving credit facility expose us to interest rate risk.
Our borrowings under our revolving credit facility are, and are expected to continue to be, at
variable rates of interest and expose us to interest rate risk. If interest rates increase, our
debt service obligations on the variable rate indebtedness would increase even though the amount
borrowed remained the same, and our net income would decrease.
The senior notes are structurally subordinated to liabilities and indebtedness of our
non-guarantor subsidiaries, if any, and are effectively subordinated to our secured indebtedness to
the extent of the assets securing such indebtedness.
Our obligations under the senior notes and the obligations of guarantors, if any, under their
guarantees of the senior notes are or will be unsecured, but our obligations under our revolving
credit facility are secured by a security interest in substantially all of our assets. Holders of
this indebtedness and any other secured indebtedness that we may incur in the future will have
claims with respect to our assets constituting collateral for such indebtedness that are prior to
claims under the senior notes. In the event of a default on such secured indebtedness or our
bankruptcy, liquidation or reorganization, those assets would be available to satisfy obligations
with respect to the indebtedness secured thereby before any payment could be made on the senior
notes. Accordingly, any such secured indebtedness will effectively be senior to the senior notes
to the extent of the value of the collateral securing the indebtedness. While the indenture
governing the senior notes places some limitations on our ability to create liens, there are
significant exceptions to these limitations that will allow us to secure some kinds of indebtedness
without equally and ratably securing the senior notes, including any future indebtedness we may
incur under a credit facility. To the extent the value of the collateral is not sufficient to
satisfy our secured indebtedness, the holders of that indebtedness would be entitled to share with
the holders of the senior notes and the holders of other claims against us with respect to our
other assets.
In addition, the senior notes may not in the future be guaranteed by all of our subsidiaries,
if any, and any non-guarantor subsidiaries can incur some indebtedness under the terms of the
indenture. As a result, holders of the senior notes are structurally subordinated to claims of
third party creditors of our
(44)
non-guarantor subsidiaries. Claims of those other creditors,
including trade creditors, holders of indebtedness, or guarantees issued by these non-guarantor
subsidiaries will generally have priority as to the assets of the non-guarantor subsidiary over our
claims and equity interests. As a result, holders of our indebtedness, including the holders of
the senior notes, are structurally subordinated to all those claims.
A subsidiary guarantee could be voided if it constitutes a fraudulent transfer under U.S.
bankruptcy or similar state laws, which would prevent the holders of senior notes from relying on
the subsidiary to satisfy our payment obligations under the senior notes.
Federal and state statutes allow courts, under specific circumstances, to void subsidiary
guarantees, or require that claims under the subsidiary guarantee be subordinated to all other
debts of the subsidiary guarantor, and to require creditors such as the senior note holders to
return payments received from subsidiary guarantors. Under federal bankruptcy law and comparable
provisions of state fraudulent transfer laws, a subsidiary guarantee could be voided or claims in
respect of a subsidiary guarantee could be subordinated to all other debts of that subsidiary
guarantor if, for example, the subsidiary guarantor, at the time it issued its subsidiary
guarantee:
|
|
|
was insolvent or rendered insolvent by making the subsidiary guarantee; |
|
|
|
|
was engaged in a business or transaction for which the subsidiary guarantors
remaining assets constituted unreasonably small capital; or |
|
|
|
intended to incur, or believed that it would incur, debts beyond its ability to pay
them as they mature. |
A guarantee may also be voided, without regard to the above factors, if a court found that the
guarantor entered into the guarantee with the actual intent to hinder, delay or defraud any present
or future creditor or received less than reasonably equivalent value or fair compensation for the
subsidiary guarantee. A court would likely find that a guarantor did not receive reasonably
equivalent value or fair compensation for its guarantee if the guarantor did not substantially
benefit directly or indirectly from the issuance of the guarantees.
The measures of insolvency for purposes of these fraudulent transfer laws will vary depending
upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred.
Generally, a subsidiary guarantor would be considered insolvent if:
|
|
|
the sum of its debts, including contingent liabilities, was greater than the fair
saleable value of all of its assets; |
|
|
|
|
the present fair saleable value of its assets was less than the amount that would be
required to pay its probable liability on its existing debts, including contingent
liabilities, as they become absolute and mature; or |
|
|
|
|
it could not pay its debts as they become due. |
To the extent a court voids a subsidiary guarantee as a fraudulent transfer or holds the
subsidiary guarantee unenforceable for any other reason, holders of senior notes would cease to
have any direct claim against the subsidiary guarantor. If a court were to take this action, the
subsidiary guarantors assets would be applied first to satisfy the subsidiary guarantors
liabilities, if any, before any portion of its
(45)
assets could be distributed to us to be applied to
the payment of the senior notes. We cannot assure you that a subsidiary guarantors remaining
assets would be sufficient to satisfy the claims of the holders of senior notes related to any
voided portions of the subsidiary guarantees.
We may not be able to repurchase the senior notes upon a change of control.
Upon the occurrence of a change of control, holders of senior notes will have the right to
require us to repurchase all or any part of such holders senior notes at a price equal to 101% of
the principal amount of the senior notes, plus accrued and unpaid interest, if any, to the date of
repurchase. We may not have sufficient funds at the time of the change of control to make the
required repurchases, or restrictions under our revolving credit facility may not allow such
repurchases. In addition, an event constituting a change of control (as defined in the
indenture governing the senior notes) could be an event of default under our revolving credit
facility that would, if it should occur, permit the lenders to accelerate that debt and that, in
turn, would cause an event of default under the indenture governing the senior notes, each of which
could have material adverse consequences for us and the holders of the senior notes. The source of
any funds for any repurchase required as a result of a change of control will be our available cash
or cash generated from our business operations or other sources, including borrowings, sales of
assets, sales of equity or funds provided by a new controlling entity. Sufficient funds may not be
available at the time of any change of control to make any required repurchases of the senior notes
tendered and to repay debt under our revolving credit facility.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
In January 2003, we engaged Stonington Corporation for the purpose of obtaining general
corporate financial advisory services and financial advisory services in the placement of our debt
or equity securities. In December 2003, and under the terms of our agreement with Stonington, we
issued to Stonington warrants to purchase an aggregate of 100,000 shares of our common stock as
partial payment for services rendered for financial and investment advice provided by Stonington.
The warrants were issued with an exercise price of $3.98 per share, the market value of our common
stock at the date of issuance, and were exercisable during the four-year period commencing one year
after the initial issuance of the warrants. The terms of the warrants provided for an expiration
date of December 23, 2008 and granted certain rights of registration for the common stock issuable
upon exercise of the warrants. The warrants contained customary antidilution provisions so as to
avoid dilution of the equity interests represented by the underlying common stock upon the
occurrence of certain events such as share dividends and splits. In the event of liquidation,
dissolution or winding up of Parallel, holders of the warrants were not entitled to participate in
the assets of Parallel. The warrants had no voting rights. The warrants were issued in a
transaction not involving a public offering and were issued in reliance upon the exemption from
registration under Section 4(2) of the Securities Act of 1933, as amended.
The warrants could be exercised in whole or in part at any time during the period from
December 23, 2004 to December 23, 2008 by payment in cash of an amount determined by multiplying
the exercise price by the number of shares of common stock as to which the warrants are being
exercised. The warrants also contained a net exercise provision entitling the holder to exercise
the warrants by receiving shares of common stock equal to the value of the warrants being
surrendered for exercise. Utilizing this net exercise feature, on July 11, 2007, warrants to
purchase 50,000 shares of our common stock were surrendered for exercise and the holder received
41,221 shares of common stock. The other 50,000 shares were exercised in April 2007 as previously
reported. No cash proceeds were received by Parallel. The common stock was issued in reliance upon
the exemptions from registration contained in Section 3(a)(9) and Section 4(2) of the Securities
Act. We currently have no outstanding warrants.
(46)
ITEM 6. EXHIBITS
|
(a) |
|
Exhibits |
|
|
|
|
The following exhibits are filed herewith or incorporated by reference, as indicated: |
|
|
|
No.
|
|
Description of Exhibit |
|
|
|
3.1 |
|
Certificate of Incorporation of Registrant (Incorporated by reference to Exhibit 3.1 to Form
10-Q of the Registrant for the fiscal quarter ended June 30, 2004) |
|
3.2 |
|
Bylaws of Registrant (Incorporated by reference to Exhibit No. 3.2 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2006) |
|
3.3 |
|
Certificate of Formation of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.3 of
the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004) |
|
3.4 |
|
Limited Liability Company Agreement of Parallel, L.L.C. (Incorporated by reference to Exhibit
No. 3.4 of the Registrants Statement on Form S-3, No. 333-119725 filed on October 13, 2004) |
|
3.5 |
|
Certificate of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit
No. 3.5 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on
October 13, 2004) |
|
3.6 |
|
Agreement of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No.
3.6 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October
13, 2004) |
4.1 |
|
Certificate of Designations, Preferences and Rights of Serial Preferred Stock 6%
Convertible Preferred Stock (Incorporated by reference to Exhibit 4.1 of Form 10-Q of the
Registrant for the fiscal quarter ended June 30, 2004) |
|
4.2 |
|
Certificate of Designation, Preferences and Rights of Series A Preferred Stock (Incorporated
by reference to Exhibit 4.2 of Form 10-K of the Registrant for the fiscal year ended December
31, 2000) |
|
4.3 |
|
Rights Agreement, dated as of October 5, 2000, between the Registrant and Computershare Trust
Company, Inc., as Rights Agent (Incorporated by reference to Exhibit 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 No. 4.7 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2006) |
(47)
|
|
|
No.
|
|
Description of Exhibit |
|
|
|
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 No. 4.8 of Form 10-K of the Registrant for the fiscal year ended
December 31, 2006) |
|
4.9 |
|
Indenture dated as of July 31, 2007 between the Registrant and Wells Fargo Bank, N.A.
(Incorporated by reference to Exhibit 4.1 of the Registrants Form 8-K Report dated July 26,
2007) |
|
4.10 |
|
Form of Rule 144A 10
1/4% Senior Notes due 2014 (Incorporated by reference to Exhibit 4.2 of
the Registrants Form 8-K Report dated July 26, 2007) |
|
4.11 |
|
Form of IAI Global Security 10 1/4% Senior Note due 2014 (Incorporated by reference to
Exhibit 4.3 of the Registrants Form 8-K Report dated July 26, 2007) |
|
4.12 |
|
Form of Regulation S 10 1/4% Senior Notes due 2014 (Incorporated by reference to Exhibit 4.4
of the Registrants Form 8-K Report dated July 26, 2007) |
|
|
|
Executive Compensation Plans and Arrangements (Exhibit No.s 10.1 through 10.7): |
|
10.1 |
|
1992 Stock Option Plan (Incorporated by reference to Exhibit 10.1 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2004) |
|
10.2 |
|
Merrill Lynch, Pierce, Fenner & Smith Incorporated Prototype Simplified Employee Pension Plan
(Incorporated by reference to Exhibit 10.6 of the Registrants Form 10-K for the fiscal year
ended December 31, 1995) |
|
10.3 |
|
Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.3 of the
Registrants Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2005) |
|
10.4 |
|
1998 Stock Option Plan (Incorporated by reference to Exhibit No. 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 No. 10.7 of the Registrant
for the fiscal year ended December 31, 2006) |
|
10.8 |
|
First Amended and Restated Credit Agreement, dated December 20, 2002, by and among Parallel
Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, Western
National Bank and BNP Paribas (Incorporated by reference to Exhibit 10.2 of Form 8-K of the
Registrant, dated December 20, 2002) |
|
10.9 |
|
Guaranty dated December 20, 2002, between Parallel, L.L.C. and First American Bank, SSB, as
Agent (Incorporated by reference to Exhibit 10.3 of Form 8-K of the Registrant, dated December
20, 2002) |
|
10.10 |
|
First Amendment to First Amended and Restated Credit Agreement, dated as of September 12,
2003, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First
American Bank, SSB, Western National Bank, and BNP Paribas (Incorporated by reference to
Exhibit 10.29 of Form 10-Q of the Registrant for the quarter ended September 30, 2003) |
(48)
|
|
|
No.
|
|
Description of Exhibit |
|
|
|
10.11 |
|
Second Amended and Restated Credit Agreement, dated September 27, 2004, by and among
Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB,
BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit
10.1 of the Registrants Form 8-K Report dated September 27, 2004 and filed with the
Securities and Exchange Commission on October 1, 2004) |
|
10.12 |
|
Agreement of Limited Partnership of West Fork Pipeline Company LP (Incorporated by reference
to Exhibit 10.21 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004) |
|
10.13 |
|
First Amendment to Second Amended and Restated Credit Agreement, dated as of December 27,
2004, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First
American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by
reference to Exhibit 10.1 of the Registrants Form 8-K Report dated December 30, 2004 and
filed with the Securities and Exchange Commission on December 30, 2004) |
|
10.14 |
|
Second Amendment to Second Amended and Restated Credit Agreement, dated as of April 1, 2005,
by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American
Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference
to Exhibit 10.1 of the Registrants Form 8-K Report dated April 4, 2005 and filed with the
Securities and Exchange Commission on April 8, 2005) |
|
10.15 |
|
Third Amendment to Second Amended and Restated Credit Agreement (Incorporated by reference
to Exhibit 10.1 of the Registrants Form 8-K Report dated October 4, 2005 and filed with the
Securities and Exchange Commission on October 20, 2005) |
|
10.16 |
|
Purchase and Sale Agreement, dated as of October 14, 1005, among Parallel, L.P., Lynx
Production Company, Inc., Elton Resources, Inc., Cascade Energy Corporation, Chelsea Energy,
Inc., William P. Sutter, Trustee, William P. Sutter Trust, J. Leroy Bell, E. L. Brahaney,
Brent Beck, Cavic Interests, LLC and Stanley Talbott (Incorporated by reference to Exhibit 10.2 of
the Registrants Form 8-K Report dated October 14, 2005 and filed with the Securities and
Exchange Commission on October 20, 2005) |
|
10.17 |
|
Ancillary Agreement to Purchase and Sale Agreement, dated October 14, 2005, between
Parallel, L.P. and Lynx Production Company, Inc. (Incorporated by reference to Exhibit 10.3 of
the Registrants Form 8-K Report dated October 14, 2005 and filed with the Securities and
Exchange Commission on October 20, 2005) |
|
10.18 |
|
Guarantee of Parallel, L.P., dated October 13, 2004 (Incorporated by reference to Exhibit
10.4 of the Registrants Form 8-K Report dated October 14, 2005 and filed with the Securities
and Exchange Commission on October 20, 2005) |
|
10.19 |
|
ISDA Master Agreement, dated as of October 13, 2005, between Parallel, L.P. and Citibank,
N.A. (Incorporated by reference to Exhibit 10.5 of the Registrants Form 8-K Report dated
October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005) |
|
10.20 |
|
Third Amended and Restated Credit Agreement, dated as of December 23, 2005, among Parallel
Petroleum Corporation, Parallel, L.P., Parallel, L.L.C. and Citibank Texas, N.A., BNP Paribas,
CitiBank F.S.B., Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland and
Fortis Capital Corp. (Incorporated by reference to Exhibit No. 10.1 of the Registrants Form
8-K Report, dated December 23, 2005, as filed with the Securities and Exchange Commission on
December 30, 2005) |
(49)
|
|
|
No.
|
|
Description of Exhibit |
|
|
|
10.21 |
|
Second Lien Term Loan Agreement, dated November 15, 2005, among Parallel Petroleum
Corporation, Parallel, L.P., BNP Paribas and Citibank Texas, N.A. (Incorporated by reference
to Exhibit No. 10.4 of the Registrants Form 8-K Report, dated November 15, 2005, as filed
with the Securities and Exchange Commission on November 21, 2005) |
|
10.22 |
|
Intercreditor and Subordination Agreement, dated November 15, 2005, among Citibank Texas,
N.A., BNP Paribas, Parallel Petroleum Corporation, Parallel, L.P. and Parallel, L.L.C.
(Incorporated by reference to Exhibit No. 10.5 of the Registrants Form 8-K Report, dated
November 15, 2005, as filed with the Securities and Exchange Commission on November 21, 2005) |
|
10.23 |
|
Guaranty, dated as of December 23, 2005, made by Parallel, L.L.C. to and in favor of
Citibank Texas, N.A. (Incorporated by reference to Exhibit No. 10.23 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2006) |
|
10.24 |
|
Third Amended and Restated Pledge Agreement, dated as of December 23, 2005, between
Parallel, L.L.C. and Citibank Texas, N.A. (Incorporated by reference to Exhibit No. 10.24 of
Form 10-K of the Registrant for the fiscal year ended December 31, 2006) |
|
10.25 |
|
Second Lien Guarantee and Collateral Agreement, dated as of November 15, 2005, made by
Parallel Petroleum Corporation and Parallel, L.P. to and in favor of BNP Paribas (Incorporated
by reference to Exhibit No. 10.25 of Form 10-K of the Registrant for the fiscal year ended
December 31, 2006) |
|
10.26 |
|
Purchase Agreement, dated July 26, 2007 (Incorporated by reference to Exhibit 10.1 of the
Registrants Form 8-K Report dated July 26, 2007) |
|
10.27 |
|
Registration Rights Agreement, dated July 31, 2007 (Incorporated by reference to Exhibit
10.2 of the Registrants Form 8-K Report dated July 26, 2007) |
|
10.28 |
|
Third Amendment to Third Amended and Restated Credit Agreement dated as of July 31, 2007
between Parallel Petroleum Corporation individually and as successor by merger to Parallel
L.P. and Parallel, L.L.C. and Citibank, N.A., successor by merger to
Citibank Texas, 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 Form 8-K Report
dated July 26, 2007)
|
|
14 |
|
Code of Ethics (Incorporated by reference to Exhibit No. 14 of the Registrants Form 10-K
Report for the fiscal year ended December 31, 2003 and filed with the Securities and Exchange
Commission on March 22, 2004) |
|
21 |
|
Subsidiaries (Incorporated by reference to Exhibit No. 21 of the Registrants Form 10-K
Report for the fiscal year ended December 31, 2003 and filed with the Securities and Exchange
Commission on March 22, 2004) |
|
*31.1 |
|
Certification of Principal Executive Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 302 of the Sarbanes -
Oxley Act of 2002. |
|
*31.2 |
|
Certification of Principal Financial Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 302 of the Sarbanes -
Oxley Act of 2002. |
|
*32.1 |
|
Certification of Chief Executive Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the Sarbanes -
Oxley Act of 2002. |
(50)
*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. |
(51)
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:
November 9, 2007
|
|
|
|
Larry C. Oldham
|
|
|
|
|
|
|
President and Chief Executive Officer |
|
|
|
|
|
|
|
|
|
Date:
November 9, 2007
|
|
|
|
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 No. 3.2 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2006) |
|
3.3 |
|
Certificate of Formation of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.3 of
the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004) |
|
3.4 |
|
Limited Liability Company Agreement of Parallel, L.L.C. (Incorporated by reference to Exhibit
No. 3.4 of the Registrants Statement on Form S-3, No. 333-119725 filed on October 13, 2004) |
|
3.5 |
|
Certificate of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit
No. 3.5 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on
October 13, 2004) |
|
3.6 |
|
Agreement of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No.
3.6 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October
13, 2004) |
|
4.1 |
|
Certificate of Designations, Preferences and Rights of Serial Preferred Stock 6%
Convertible Preferred Stock (Incorporated by reference to Exhibit 4.1 of Form 10-Q of the
Registrant for the fiscal quarter ended June 30, 2004) |
|
4.2 |
|
Certificate of Designation, Preferences and Rights of Series A Preferred Stock (Incorporated
by reference to Exhibit 4.2 of Form 10-K of the Registrant for the fiscal year ended December
31, 2000) |
|
4.3 |
|
Rights Agreement, dated as of October 5, 2000, between the Registrant and Computershare Trust
Company, Inc., as Rights Agent (Incorporated by reference to Exhibit 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 No. 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 No. 4.8 of Form 10-K of the Registrant for the fiscal year ended
December 31, 2006) |
|
|
|
No.
|
|
Description of Exhibit |
|
|
|
4.9 |
|
Indenture dated as of July 31, 2007 between the Registrant and Wells Fargo Bank, N.A.
(Incorporated by reference to Exhibit 4.1 of the Registrants Form 8-K Report dated July 26,
2007) |
|
4.10 |
|
Form of Rule 144A 10 1/4% Senior Notes due 2014 (Incorporated by reference to Exhibit 4.2 of
the Registrants Form 8-K Report dated July 26, 2007) |
|
4.11 |
|
Form of IAI Global Security 10 1/4% Senior Note due 2014 (Incorporated by reference to
Exhibit 4.3 of the Registrants Form 8-K Report dated July 26, 2007) |
|
4.12 |
|
Form of Regulation S 10 1/4% Senior Notes due 2014 (Incorporated by reference to Exhibit 4.4
of the Registrants Form 8-K Report dated July 26, 2007) |
|
|
|
Executive Compensation Plans and Arrangements (Exhibit No.s 10.1 through 10.7): |
|
10.1 |
|
1992 Stock Option Plan (Incorporated by reference to Exhibit 10.1 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2004) |
|
10.2 |
|
Merrill Lynch, Pierce, Fenner & Smith Incorporated Prototype Simplified Employee Pension Plan
(Incorporated by reference to Exhibit 10.6 of the Registrants Form 10-K for the fiscal year
ended December 31, 1995) |
|
10.3 |
|
Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.3 of the
Registrants Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2005) |
|
10.4 |
|
1998 Stock Option Plan (Incorporated by reference to Exhibit No. 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 No. 10.7 of the Registrant
for the fiscal year ended December 31, 2006) |
|
10.8 |
|
First Amended and Restated Credit Agreement, dated December 20, 2002, by and among Parallel
Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, Western
National Bank and BNP Paribas (Incorporated by reference to Exhibit 10.2 of Form 8-K of the
Registrant, dated December 20, 2002) |
|
10.9 |
|
Guaranty dated December 20, 2002, between Parallel, L.L.C. and First American Bank, SSB, as
Agent (Incorporated by reference to Exhibit 10.3 of Form 8-K of the Registrant, dated December
20, 2002) |
|
10.10 |
|
First Amendment to First Amended and Restated Credit Agreement, dated as of September 12,
2003, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First
American Bank, SSB, Western National Bank, and BNP Paribas (Incorporated by reference to
Exhibit 10.29 of Form 10-Q of the Registrant for the quarter ended September 30, 2003) |
|
10.11 |
|
Second Amended and Restated Credit Agreement, dated September 27, 2004, by and among
Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB,
BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit
10.1 of the Registrants Form 8-K Report dated September 27, 2004 and filed with the
Securities and Exchange Commission on October 1, 2004) |
|
10.12 |
|
Agreement of Limited Partnership of West Fork Pipeline Company LP (Incorporated by reference
to Exhibit 10.21 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004) |
|
|
|
No.
|
|
Description of Exhibit |
|
|
|
10.13 |
|
First Amendment to Second Amended and Restated Credit Agreement, dated as of December 27,
2004, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First
American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by
reference to Exhibit 10.1 of the Registrants Form 8-K Report dated December 30, 2004 and
filed with the Securities and Exchange Commission on December 30, 2004) |
|
10.14 |
|
Second Amendment to Second Amended and Restated Credit Agreement, dated as of April 1, 2005,
by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American
Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference
to Exhibit 10.1 of the Registrants Form 8-K Report dated April 4, 2005 and filed with the
Securities and Exchange Commission on April 8, 2005) |
|
10.15 |
|
Third Amendment to Second Amended and Restated Credit Agreement (Incorporated by reference
to Exhibit 10.1 of the Registrants Form 8-K Report dated October 4, 2005 and filed with the
Securities and Exchange Commission on October 20, 2005) |
|
10.16 |
|
Purchase and Sale Agreement, dated as of October 14, 1005, among Parallel, L.P., Lynx
Production Company, Inc., Elton Resources, Inc., Cascade Energy Corporation, Chelsea Energy,
Inc., William P. Sutter, Trustee, William P. Sutter Trust, J. Leroy Bell, E. L. Brahaney,
Brent Beck, Cavic Interests, LLC and Stanley Talbott (Incorporated by reference to Exhibit
10.2 of the Registrants Form 8-K Report dated October 14, 2005 and filed with the Securities
and Exchange Commission on October 20, 2005) |
|
10.17 |
|
Ancillary Agreement to Purchase and Sale Agreement, dated October 14, 2005, between
Parallel, L.P. and Lynx Production Company, Inc. (Incorporated by reference to Exhibit 10.3 of
the Registrants Form 8-K Report dated October 14, 2005 and filed with the Securities and
Exchange Commission on October 20, 2005) |
|
10.18 |
|
Guarantee of Parallel, L.P., dated October 13, 2004 (Incorporated by reference to Exhibit
10.4 of the Registrants Form 8-K Report dated October 14, 2005 and filed with the Securities
and Exchange Commission on October 20, 2005) |
|
10.19 |
|
ISDA Master Agreement, dated as of October 13, 2005, between Parallel, L.P. and Citibank,
N.A. (Incorporated by reference to Exhibit 10.5 of the Registrants Form 8-K Report dated
October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005) |
|
10.20 |
|
Third Amended and Restated Credit Agreement, dated as of December 23, 2005, among Parallel
Petroleum Corporation, Parallel, L.P., Parallel, L.L.C. and Citibank Texas, N.A., BNP Paribas,
CitiBank F.S.B., Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland and
Fortis Capital Corp. (Incorporated by reference to Exhibit No. 10.1 of the Registrants Form
8-K Report, dated December 23, 2005, as filed with the Securities and Exchange Commission on
December 30, 2005) |
|
10.21 |
|
Second Lien Term Loan Agreement, dated November 15, 2005, among Parallel Petroleum
Corporation, Parallel, L.P., BNP Paribas and Citibank Texas, N.A. (Incorporated by reference
to Exhibit No. 10.4 of the Registrants Form 8-K Report, dated November 15, 2005, as filed
with the Securities and Exchange Commission on November 21, 2005) |
|
10.22 |
|
Intercreditor and Subordination Agreement, dated November 15, 2005, among Citibank Texas,
N.A., BNP Paribas, Parallel Petroleum Corporation, Parallel, L.P. and Parallel, L.L.C.
(Incorporated by reference to Exhibit No. 10.5 of the Registrants Form 8-K Report, dated
November 15, 2005, as filed with the Securities and Exchange Commission on November 21,
2005) |
|
|
|
No.
|
|
Description of Exhibit |
|
|
|
10.23 |
|
Guaranty, dated as of December 23, 2005, made by Parallel, L.L.C. to and in favor of
Citibank Texas, N.A. (Incorporated by reference to Exhibit No. 10.23 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2006) |
|
10.24 |
|
Third Amended and Restated Pledge Agreement, dated as of December 23, 2005, between
Parallel, L.L.C. and Citibank Texas, N.A. (Incorporated by reference to Exhibit No. 10.24 of
Form 10-K of the Registrant for the fiscal year ended December 31, 2006) |
|
10.25 |
|
Second Lien Guarantee and Collateral Agreement, dated as of November 15, 2005, made by
Parallel Petroleum Corporation and Parallel, L.P. to and in favor of BNP Paribas (Incorporated
by reference to Exhibit No. 10.25 of Form 10-K of the Registrant for the fiscal year ended
December 31, 2006) |
|
10.26 |
|
Purchase Agreement, dated July 26, 2007 (Incorporated by reference to Exhibit 10.1 of the
Registrants Form 8-K Report dated July 26, 2007) |
|
10.27 |
|
Registration Rights Agreement, dated July 31, 2007 (Incorporated by reference to Exhibit
10.2 of the Registrants Form 8-K Report dated July 26, 2007) |
|
10.28 |
|
Third Amendment to Third Amended and Restated Credit Agreement dated as of July 31, 2007
between Parallel Petroleum Corporation individually and as successor by merger to Parallel
L.P. and Parallel, L.L.C. and Citibank, N.A., successor by merger to Citibank Texas, 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 Form 8-K Report
dated July 26, 2007) |
|
14 |
|
Code of Ethics (Incorporated by reference to Exhibit No. 14 of the Registrants Form 10-K
Report for the fiscal year ended December 31, 2003 and filed with the Securities and Exchange
Commission on March 22, 2004) |
|
21 |
|
Subsidiaries (Incorporated by reference to Exhibit No. 21 of the Registrants Form 10-K
Report for the fiscal year ended December 31, 2003 and filed with the Securities and Exchange
Commission on March 22, 2004) |
|
*31.1 |
|
Certification of Principal Executive Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 302 of the Sarbanes -
Oxley Act of 2002. |
|
*31.2 |
|
Certification of Principal Financial Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 302 of the Sarbanes -
Oxley Act of 2002. |
|
*32.1 |
|
Certification of Chief Executive Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the Sarbanes -
Oxley Act of 2002. |
|
*32.2 |
|
Certification of Chief Financial Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the Sarbanes -
Oxley Act of 2002. |