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, 2006 or
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o |
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Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the Transition period from to
Commission File Number 0-13305
PARALLEL PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
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DELAWARE
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75-1971716 |
(State of other jurisdiction
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(I.R.S. Employer Identification |
of incorporation or organization)
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Number) |
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1004 N. Big Spring, Suite 400
Midland, Texas
(Address of principal executive offices)
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79701
(Zip Code) |
(432) 684-3727
(Registrants telephone number, including area code)
Not Applicable
(Former name, former address and former fiscal year,
if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, or a non-accelerated filer. See definition of accelerated filer and large accelerated
filer in Rule 12b-2 of the Exchange Act. (Check one):
Large
accelerated filer o
Accelerated filer
þ Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act).
Yes o No þ
At
November 6, 2006, 37,464,991 shares of the Registrants Common Stock, $0.01 par value, were
outstanding.
Part I. Financial Information
Item I. Financial Statements
PARALLEL PETROLEUM CORPORATION
Consolidated Balance Sheets
(dollars in thousands, except per share amounts)
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September 30, |
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December 31, |
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2006 |
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2005 |
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(unaudited) |
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Assets |
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Current assets: |
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Cash and cash equivalents |
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$ |
312 |
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$ |
6,418 |
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Accounts receivable: |
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Oil and natural gas |
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16,625 |
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13,183 |
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Other, net of allowance for doubtful account of $80 and $9 |
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9,524 |
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877 |
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Affiliates |
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7 |
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12 |
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26,156 |
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14,072 |
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Other current assets |
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3,026 |
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2,364 |
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Deferred tax asset |
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4,762 |
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5,241 |
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Total current assets |
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34,256 |
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28,095 |
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Property and equipment, at cost: |
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Oil and natural gas properties, full cost method
(including $42,036 and $19,869 not
subject to depletion) |
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452,704 |
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303,819 |
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Other |
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3,204 |
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2,404 |
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455,908 |
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306,223 |
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Less accumulated depreciation, depletion and amortization |
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(108,674 |
) |
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(90,826 |
) |
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Net property and equipment |
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347,234 |
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215,397 |
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Restricted cash |
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324 |
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2,640 |
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Investment in pipelines and gathering system ventures |
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12,946 |
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3,326 |
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Other assets, net of accumulated amortization of $1,236 and $901 |
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3,785 |
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3,550 |
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$ |
398,545 |
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$ |
253,008 |
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Liabilities and Stockholders Equity |
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Current liabilities: |
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Accounts payable and accrued liabilities |
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$ |
25,721 |
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$ |
10,841 |
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Asset retirement obligations |
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384 |
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214 |
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Derivative obligations |
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15,514 |
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16,607 |
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Total current liabilities |
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41,619 |
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27,662 |
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Revolving credit facility |
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97,000 |
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50,000 |
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Term loan |
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50,000 |
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50,000 |
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Asset retirement obligations |
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4,241 |
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2,281 |
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Derivative obligations |
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16,702 |
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25,527 |
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Deferred tax liability |
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17,883 |
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8,036 |
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Total long-term liabilities |
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185,826 |
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135,844 |
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Commitments and contingencies |
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Stockholders equity: |
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Series A preferred stock par value $0.10 per share, authorized 50,000 shares |
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Preferred stock 6% convertible preferred stock par value of $0.10 per share
(liquidation preference of $10 per share), authorized 10,000,000 shares |
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Common stock par value $0.01 per share, authorized 60,000,000 shares,
issued and outstanding 37,464,991 and 34,748,916 |
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374 |
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347 |
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Additional paid-in capital |
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140,288 |
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78,699 |
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Retained earnings |
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31,970 |
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16,899 |
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Accumulated other comprehensive loss |
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(1,532 |
) |
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(6,443 |
) |
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Total stockholders equity |
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171,100 |
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89,502 |
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$ |
398,545 |
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$ |
253,008 |
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The accompanying notes are an integral part of these Consolidated Financial Statements.
(1)
PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Operations
(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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2006 |
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2005 |
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2006 |
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2005 |
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Oil and natural gas revenues: |
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Oil and natural gas sales |
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$ |
29,490 |
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$ |
25,501 |
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$ |
82,360 |
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$ |
53,474 |
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Loss on hedging |
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(3,279 |
) |
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(3,664 |
) |
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(9,264 |
) |
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(8,960 |
) |
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Total revenues |
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26,211 |
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21,837 |
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73,096 |
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44,514 |
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Cost and expenses: |
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Lease operating expense |
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5,323 |
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2,663 |
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12,639 |
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7,399 |
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Production taxes |
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1,538 |
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1,334 |
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4,116 |
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2,615 |
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General and administrative |
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2,405 |
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1,735 |
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7,147 |
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4,771 |
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Depreciation, depletion and amortization |
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|
7,420 |
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3,104 |
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17,848 |
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8,159 |
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Total costs and expenses |
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16,686 |
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8,836 |
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41,750 |
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22,944 |
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Operating income |
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9,525 |
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13,001 |
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31,346 |
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21,570 |
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Other income (expense), net: |
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Change in fair market value of derivative instruments |
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10,323 |
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(9,388 |
) |
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116 |
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(33,086 |
) |
Gain (loss) on ineffective portion of hedges |
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305 |
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404 |
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500 |
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(456 |
) |
Interest and other income |
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29 |
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83 |
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122 |
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124 |
|
Interest expense |
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(3,345 |
) |
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(1,060 |
) |
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(8,944 |
) |
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(3,101 |
) |
Other expense |
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(96 |
) |
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(75 |
) |
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(164 |
) |
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(77 |
) |
Equity in gain (loss) of pipelines and gathering system ventures |
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(39 |
) |
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22 |
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(68 |
) |
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(72 |
) |
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Total other income (expense), net |
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7,177 |
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(10,014 |
) |
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(8,438 |
) |
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(36,668 |
) |
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Income (loss) before income taxes |
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|
16,702 |
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|
2,987 |
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22,908 |
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(15,098 |
) |
Income tax benefit (expense), deferred |
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(5,706 |
) |
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(998 |
) |
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(7,837 |
) |
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5,137 |
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Net income (loss) |
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10,996 |
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|
1,989 |
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15,071 |
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(9,961 |
) |
Cumulative preferred stock dividend |
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(271 |
) |
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Net income (loss) available to common stockholders |
|
$ |
10,996 |
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$ |
1,989 |
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$ |
15,071 |
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$ |
(10,232 |
) |
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Net income (loss) per common share: |
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Basic |
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$ |
0.30 |
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$ |
0.06 |
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$ |
0.43 |
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$ |
(0.32 |
) |
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Diluted |
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$ |
0.30 |
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$ |
0.06 |
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$ |
0.42 |
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$ |
(0.32 |
) |
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Weighted average common share outstanding: |
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Basic |
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36,215 |
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|
34,033 |
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35,340 |
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|
31,585 |
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Diluted |
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36,919 |
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|
34,951 |
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36,027 |
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31,585 |
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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, 2006 and 2005
(unaudited)
(dollars in thousands)
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2006 |
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2005 |
|
Cash flows from operating activities: |
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Net income (loss) |
|
$ |
15,071 |
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|
$ |
(9,961 |
) |
Adjustments to reconcile net income (loss) to net cash
provided by operating activities: |
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Depreciation, depletion and amortization |
|
|
17,848 |
|
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|
8,159 |
|
Accretion of asset retirement obligation |
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|
172 |
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|
82 |
|
Deferred income tax |
|
|
7,837 |
|
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|
(5,137 |
) |
Change in fair value of derivative instruments |
|
|
(116 |
) |
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|
33,086 |
|
(Gain) loss on ineffective portion of hedges |
|
|
(500 |
) |
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|
456 |
|
Common stock issued in lieu of cash for directors fees |
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|
100 |
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|
99 |
|
Stock option expense |
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|
435 |
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|
119 |
|
Equity in loss of pipelines and gathering system ventures |
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|
68 |
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|
72 |
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|
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|
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Changes in assets and liabilities: |
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Other assets, net |
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|
1,140 |
|
|
|
186 |
|
Restricted cash |
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(50 |
) |
|
|
(149 |
) |
Increase in accounts receivable |
|
|
(12,084 |
) |
|
|
(7,927 |
) |
(Increase) decrease in other current assets |
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|
(151 |
) |
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|
61 |
|
Increase in accounts payable and accrued liabilities |
|
|
14,880 |
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|
3,988 |
|
Federal tax deposit |
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(40 |
) |
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|
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Net cash provided by operating activities |
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|
44,610 |
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|
23,134 |
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Cash flows from investing activities: |
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|
Additions to oil and natural gas properties |
|
|
(147,058 |
) |
|
|
(37,888 |
) |
Use of restricted cash for acquisition of oil and natural gas properties |
|
|
2,366 |
|
|
|
2,287 |
|
Proceeds from disposition of oil and natural gas properties |
|
|
130 |
|
|
|
3,028 |
|
Additions to other property and equipment |
|
|
(800 |
) |
|
|
(421 |
) |
Settlements on derivative instruments |
|
|
(3,568 |
) |
|
|
(3,424 |
) |
Purchase of derivative instruments |
|
|
|
|
|
|
(598 |
) |
Investment in pipelines and gathering system ventures |
|
|
(9,688 |
) |
|
|
(1,686 |
) |
|
|
|
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|
Net cash used in investing activities |
|
|
(158,618 |
) |
|
|
(38,702 |
) |
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|
|
|
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|
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|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Net borrowings (payments) on revolving line of credit |
|
|
47,000 |
|
|
|
(11,000 |
) |
Deferred financing cost |
|
|
(179 |
) |
|
|
|
|
Proceeds (net) from common stock issued |
|
|
60,315 |
|
|
|
27,743 |
|
Proceeds from exercise of stock options |
|
|
766 |
|
|
|
450 |
|
Payment of preferred stock dividend |
|
|
|
|
|
|
(271 |
) |
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
107,902 |
|
|
|
16,922 |
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
(6,106 |
) |
|
|
1,354 |
|
Cash and cash equivalents at beginning of period |
|
|
6,418 |
|
|
|
4,781 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
312 |
|
|
$ |
6,135 |
|
|
|
|
|
|
|
|
Non-cash financing and investing activities: |
|
|
|
|
|
|
|
|
Oil and natural gas properties asset retirement obligations |
|
$ |
1,957 |
|
|
$ |
73 |
|
Conversion of preferred stock |
|
$ |
|
|
|
$ |
95 |
|
Other transactions: |
|
|
|
|
|
|
|
|
Interest paid |
|
$ |
9,065 |
|
|
$ |
3,319 |
|
The accompany notes are an integral part of these Consolidated Financial Statements.
(3)
PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Comprehensive Income (Loss)
(unaudited)
(dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
Net income (loss) |
|
$ |
10,996 |
|
|
$ |
1,989 |
|
|
$ |
15,071 |
|
|
$ |
(9,961 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gain (loss) on derivatives |
|
|
634 |
|
|
|
(3,702 |
) |
|
|
(1,750 |
) |
|
|
(12,175 |
) |
Reclassification adjustments for losses
on derivatives included in net income (loss) |
|
|
3,240 |
|
|
|
3,694 |
|
|
|
9,191 |
|
|
|
9,112 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of derivatives |
|
|
3,874 |
|
|
|
(8 |
) |
|
|
7,441 |
|
|
|
(3,063 |
) |
Income tax benefit (expense) |
|
|
(1,317 |
) |
|
|
3 |
|
|
|
(2,530 |
) |
|
|
1,041 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive income (loss) |
|
|
2,557 |
|
|
|
(5 |
) |
|
|
4,911 |
|
|
|
(2,022 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income (loss) |
|
$ |
13,553 |
|
|
$ |
1,984 |
|
|
$ |
19,982 |
|
|
$ |
(11,983 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these Consolidated Financial Statements.
(4)
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. DESCRIPTION OF BUSINESS NATURE OF OPERATIONS AND BASIS OF PRESENTATION
Parallel was incorporated in Texas on November 26, 1979, and reincorporated in the State of
Delaware on December 18, 1984.
We are engaged in the acquisition, development and exploitation of long life oil and natural
gas reserves and, to a lesser extent, the exploration for new oil and natural gas reserves. Our
activities are focused in the Permian Basin of west Texas and New Mexico, the Fort Worth Basin of
north Texas and the onshore Gulf Coast area of south Texas. We are actively evaluating, leasing
and drilling new projects located in the Cotton Valley Reef trend of east Texas and the Uinta Basin
of Utah.
The financial information included herein is unaudited, except the balance sheet as of
December 31, 2005 which has been derived from our audited Consolidated Financial Statements as of
December 31, 2005. However, such information includes all adjustments (consisting solely of normal
recurring adjustments), which are, in the opinion of management, necessary for a fair statement of
the results of operations for the interim periods. The results of operations for the interim period
are not necessarily indicative of the results to be expected for an entire year. Certain 2005
amounts have been conformed to the 2006 financial statement presentation.
Certain information, accounting policies and footnote disclosures normally included in
financial statements prepared in accordance with accounting principles generally accepted in the
United States of America have been condensed or omitted in this Form 10-Q Report pursuant to
certain rules and regulations of the Securities and Exchange Commission. These financial statements
should be read in conjunction with the audited consolidated financial statements and notes included
in our Annual Report on Form 10-K for the year ended December 31, 2005.
Unless otherwise indicated or unless the context otherwise requires, all references to
Parallel, we, us, and our are to Parallel Petroleum Corporation and its consolidated
subsidiaries, Parallel L.P. and Parallel, L.L.C.
NOTE 2. STOCKHOLDERS EQUITY
Options
In September, 2003, Parallel adopted the provisions of Statement of Financial Accounting
Standards No. 148, Accounting for Stock-Based Compensation Transition and Disclosure, an
amendment to SFAS No. 123, whereby certain transitional alternatives are available for a voluntary
change to the fair value based method of accounting for stock-based employee compensation.
Parallel used the prospective method which applied prospectively the fair value recognition method
to all employee and director awards granted, modified or settled after the beginning of the fiscal
year in which the fair value based method of accounting for stock-based compensation was adopted.
In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment (SFAS 123(R)). The
standard amends SFAS 123 Accounting for Stock Based Compensation and concludes that services
received from employees in exchange for stock-based compensation results is a cost to the employer
that must be recognized in the financial statements. The cost of such awards should be measured at
fair value at grant date.
Parallel adopted SFAS 123(R) effective January 1, 2006, and is applying the modified
prospective method, whereby compensation cost will be recognized for the unvested portion of awards
granted during the period of June 2001 to August 2005. No options that were granted prior to June
2001 remain unvested at January 1, 2006. Such costs will be recognized in the financial statements
of Parallel over the remaining vesting periods. Under this method, prior periods are not revised
for comparative purposes.
For the nine months ended September 30, 2006 and 2005, Parallel recognized compensation
expense of approximately $0.49 million and $0.12 million, with a tax benefit of $0.17 million and
$0.04 million, respectively,
(5)
associated with its stock option grants.
During
the second quarter of 2006, Parallel determined that stock options to purchase an aggregate
of 30,000 shares of common stock that had been granted under Parallels 1998 Stock Option Plan to
four non-officer employees during 2003 were not available for grant under the 1998 Stock Option
Plan. In June 2006, the Board of Directors approved a Settlement Agreement and Release whereby
these excess options were cancelled in exchange for Parallels payment to each employee of cash
in an amount equal to the difference between the fair market value of the stock ($20.11) and the
exercise price of the options ($3.09), multiplied by the number of excess options held by the
employees. The total amount paid by Parallel was approximately $0.51 million. This amount was
charged to expense during the second quarter of 2006.
The following table presents the future stock-based compensation expense expected to be
recognized over the vesting period of:
|
|
|
|
|
|
|
(in thousands) |
|
Fourth quarter 2006 |
|
|
96 |
|
2007 |
|
|
324 |
|
2008 through 2011 |
|
|
338 |
|
|
|
|
|
Total |
|
$ |
758 |
|
|
|
|
|
Nonvested options were 197,500 at September 30, 2006. During the nine months ended
September 30, 2006, 176,250 options were exercised; however, no options were granted, expired or
forfeited.
The fair value of each option award is estimated on the date of grant. The fair value of
stock options granted prior to and remaining outstanding at January 1, 2006 and that had option
shares subject to future vesting at that date was determined using the Black-Scholes option
valuation method assumptions noted in the following table. Expected volatilities are based on
historical volatility of our common stock. The expected term of the options granted used in the
model represent the period of time that options granted are expected to be outstanding.
|
|
|
|
|
|
|
|
|
|
|
2001 |
|
2005 |
Expected volatility |
|
|
57.95 |
% |
|
|
54.20 |
% |
Expected dividends |
|
|
0.00 |
|
|
|
0.00 |
|
Expected term (in years) |
|
|
8 |
|
|
|
7 |
|
Risk-free rate |
|
|
5.050 |
% |
|
|
4.200 |
% |
A summary of the option activity for the nine months ended September 30, 2006 is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
Remaining |
|
|
|
|
|
|
|
|
|
|
Average |
|
|
Contractual |
|
|
Aggregate |
|
|
|
Options |
|
|
Exercise Price |
|
|
Term |
|
|
Intrinsic Value |
|
|
|
(in thousands) |
|
|
(years) |
|
|
(in thousands) |
|
Outstanding December 31, 2005 |
|
|
1,405 |
|
|
$ |
5.22 |
|
|
|
|
|
|
|
|
|
Granted |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(176 |
) |
|
$ |
4.35 |
|
|
|
|
|
|
|
|
|
Surrendered |
|
|
(30 |
) |
|
$ |
3.09 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding September 30, 2006 |
|
|
1,199 |
|
|
$ |
5.40 |
|
|
|
5.6 |
|
|
$ |
17,571 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at September 30, 2006 |
|
|
1,001 |
|
|
$ |
4.32 |
|
|
|
4.6 |
|
|
$ |
15,759 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6)
|
|
|
|
|
|
|
(in thousands) |
Intrinsic Value of Options Exercised Nine Months Ending September 30, 2006 |
|
$ |
2,855 |
|
Intrinsic Value of Options Exercised Nine Months Ending September 30, 2005 |
|
$ |
897 |
|
|
|
|
|
|
Fair Market Value of Options Granted Nine Months Ending September 30, 2006 |
|
$ |
|
|
Fair Market Value of Options Granted Nine Months Ending September 30, 2005 |
|
$ |
1,423 |
|
There were no stock options granted for the quarter ended September 30, 2006. For the
quarter ended September 30, 2005 there were 200,000 options granted with a fair market value of
$1.42 million.
The following table illustrates the effect on net income and earnings per share if we had
applied the fair value recognition provisions of Statement No 123(R) to options under our
stock-based compensation plans in all periods presented.
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Nine Months Ended |
|
|
|
September 30, 2005 |
|
|
September 30, 2005 |
|
|
|
(in thousands, except per share data) |
|
Net income (loss), as reported |
|
$ |
1,989 |
|
|
$ |
(9,961 |
) |
Add: |
|
|
|
|
|
|
|
|
Expense recorded in 2005, net of related tax effects |
|
|
49 |
|
|
|
119 |
|
Deduct: |
|
|
|
|
|
|
|
|
Total stock-based employee compensation expense
determined under fair value based method for all awards,
net of related tax effects |
|
|
(35 |
) |
|
|
(106 |
) |
|
|
|
|
|
|
|
Pro forma net income (loss) |
|
$ |
2,003 |
|
|
$ |
(9,948 |
) |
|
|
|
|
|
|
|
Income (loss) per share: |
|
|
|
|
|
|
|
|
Basic as reported |
|
$ |
0.06 |
|
|
$ |
(0.32 |
) |
|
|
|
|
|
|
|
Basic pro forma |
|
$ |
0.06 |
|
|
$ |
(0.32 |
) |
|
|
|
|
|
|
|
Diluted as reported |
|
$ |
0.06 |
|
|
$ |
(0.32 |
) |
|
|
|
|
|
|
|
Diluted pro forma |
|
$ |
0.06 |
|
|
$ |
(0.32 |
) |
|
|
|
|
|
|
|
We have outstanding stock options granted under three separate plans. Options expire 10
years from the date of grant and become exercisable at a rate of 10% each year under one and at a
rate of 20% each year under the other two plans. The exercise price of the options is equal to the
fair market value per share of common stock on the date of grant.
Sale of Equity Securities
On February 9, 2005, we sold 5,750,000 shares of our common stock, $.01 par value per share,
pursuant to a public offering at a price of $5.27 per share. Gross cash proceeds were $30.3
million, and net proceeds were approximately $28.0 million. The common shares were issued under
Parallels $100.0 million Universal Shelf Registration Statement on Form S-3 which became effective
in November 2004. The proceeds were used to reduce the revolving credit facility.
On August 16, 2006, we sold 2,500,000 shares of our common stock, $.01 par value per share,
pursuant to a public offering at a price of $25.25 per share. Gross cash proceeds were $63.1
million, and net proceeds were approximately $60.3 million. The common shares were issued under
Parallels $100.0 million Universal Shelf Registration Statement on Form S-3 which became effective
in November 2004. The proceeds were used for general corporate purposes, including debt repayment
and the acceleration of our drilling and completion operations in certain core areas such as the
Barnett Shale gas, New Mexico Wolfcamp gas and Permian Basin west Texas oil properties
Preferred Stock
On June 6, 2005, outstanding shares of Parallels 6% Convertible Preferred Stock, $0.10 par
value per share, were converted to common stock. Under terms of the preferred stock, all of the
holders of the preferred stock elected to convert their shares into shares of Parallel common stock
based on a conversion rate of $10.00 divided by $3.50. The holders of the preferred stock received
approximately 2.8571 shares of common stock of Parallel for each share of preferred stock.
Dividends on the preferred stock ceased to accrue, and as of June 6, 2005 the preferred stock was
no longer outstanding.
(7)
NOTE 3. CREDIT FACILITIES
We have two separate credit facilities. Our Third Amended and Restated Credit Agreement or the
Revolving Credit Agreement, dated as of December 23, 2005, with a group of bank lenders provides
a revolving line of credit having a borrowing base limitation of $156.0 million at October 1,
2006. The total amount that we can borrow and have outstanding at any one time is limited to the
lesser of $350.0 million or the borrowing base established by the lenders. At September 30, 2006,
the principal amount outstanding under our revolving credit facility was $97.0 million, excluding
$0.49 million reserved for our letters of credit. The second credit facility is a five year term
loan facility provided to us under a Second Lien Term Loan Agreement (the Second Lien Agreement),
dated as of November 15, 2005, with a group of banks and other lenders. At September 30, 2006, our
term loan under this facility was fully funded in the principal amount of $50.0 million, which was
outstanding on that same date.
Revolving Credit Facility
The Revolving Credit Agreement provides for a credit facility that allows us to borrow, repay
and reborrow amounts available under the revolving credit facility. The amount of the borrowing
base is based primarily upon the estimated value of our oil and natural gas reserves. The borrowing
base amount is redetermined by the lenders semi-annually on or about April 1 and October 1 of each
year or at other times required by the lenders or at our request. If, as a result of the lenders
redetermination of the borrowing base, the outstanding principal amount of our loans exceeds the
borrowing base, we must either provide additional collateral to the lenders or repay the
outstanding principal of our loans in an amount equal to the excess. Except for the principal
payments that may be required because of our outstanding loans being in excess of the borrowing
base, interest only is payable monthly.
Loans made to us under this revolving credit facility bear interest at the base rate of
Citibank, N.A. or the LIBOR rate, at our election. Generally, Citibanks base rate is equal to its
prime rate as announced from time to time by Citibank.
The LIBOR rate is generally equal to the sum of (a) the rate designated as British Bankers
Association Interest Settlement Rates and offered on one, two, three, six or twelve month interest
periods for deposits of $1.0 million, and (b) a margin ranging from 2.00% to 2.50%, depending upon
the outstanding principal amount of the loans. If the principal amount outstanding is equal to or
greater than 75% of the borrowing base, the margin is 2.50%. If the principal amount outstanding is
equal to or greater than 50%, but less than 75% of the borrowing base, the margin is 2.25%. If the
principal amount outstanding is less than 50% of the borrowing base, the margin is 2.00%.
The interest rate we are required to pay on our borrowings, including the applicable margin,
may never be less than 5.00%. At September 30, 2006, our weighted average base and LIBOR rates,
plus margin, were 7.64% on $97.0 million.
In the case of base rate loans, interest is payable on the last day of each month. In the case
of LIBOR loans, interest is payable on the last day of each applicable interest period.
If the total outstanding borrowings under the revolving credit facility are less than the
borrowing base, an unused commitment fee is required to be paid to the lenders. The amount of the
fee is .25% of the daily average of the unadvanced amount of the borrowing base. The fee is payable
quarterly.
If the borrowing base is increased, we are required to pay a fee of .375% on the amount of any
increase in the borrowing base.
All outstanding principal under the revolving credit facility is due and payable on October
31, 2010. The maturity date of our outstanding loans may be accelerated by the lenders upon the
occurrence of an event of default under the Revolving Credit Agreement.
As of September 30, 2006 we were in compliance with our debt covenants.
Second Lien Term Loan Facility
The Second Lien Agreement provides a $50.0 million term loan. Loans made to us under this
credit facility bear interest at an alternate base rate or the LIBOR rate, at our election. The
alternate base rate is the greater of (a) the prime rate in effect on such day and (b) the Federal
Funds Effective Rate in effect on such day plus 1/2 of 1%, plus a margin of
(8)
3.50% per annum.
The LIBOR rate is generally equal to the sum of a (a) the rate designated as British Bankers
Association Interest Settlement Rates and offered on one, two, three or six month interest periods
for deposits of $1.0 million and (b) an applicable margin rate per annum equal to 4.50%.
At September 30, 2006, our Libor interest rate, plus the applicable margin, was 9.9375% on
$50.0 million.
In the case of alternate base rate loans, interest is payable the last day of each March,
June, September and December. In the case of LIBOR loans, interest is payable the last day of the
tranche period not to exceed a three month period.
All outstanding principal under the Second Lien Agreement is due and payable on November 15,
2010. The maturity date may be accelerated by the lenders upon the occurrence of an event of
default under the Second Lien Agreement.
Prepayments in whole or in part if made prior to the first anniversary date will bear a
premium of 1% of the amount prepaid. There is no premium after the first anniversary date.
As of September 30, 2006 we were in compliance with our debt covenants.
Interest expense for the nine months ending September 30, 2006, for both facilities, was
approximately $9.2 million not including approximately $0.55 million for interest capitalized
associated with drilling projects.
NOTE 4. ACQUISITIONS
In October and December 2004, we purchased properties in the Carm-Ann San Andres and North
Means Queen Unit located in Andrews and Gaines counties, Texas. The combined net purchase price
was approximately $16.5 million. In the first quarter of 2005, we acquired additional interest in
these properties for a net purchase price of approximately $2.3 million.
In November 2005 and January 2006, we purchased properties in the Harris San Andres located in
Andrews and Gaines County, Texas. The combined net purchase price was approximately $44.2 million.
In March 2006, we purchased additional interests in our Barnett Shale Gas Project located in
Tarrant County, Texas. The additional interests were acquired from five unaffiliated parties for a
total cash purchase price of approximately $5.5 million. In April 2006, we acquired an additional
interest in the Barnett Shale Gas Project located in Tarrant County, Texas from one other
unaffiliated third party for approximately $0.57 million.
The table below reflects our consolidated pro forma results of operations assuming the 2006
acquisitions were consummated on January 1, 2005 and January 1, 2006, and assuming the 2005
acquisition occurred January 1, 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30, |
|
September 30, |
|
|
Pro Forma |
|
Pro Forma |
|
Pro Forma |
|
Pro Forma |
|
|
2006 |
|
2005 |
|
2006 |
|
2005 |
|
|
(in thousands, except per share data) |
Oil and natural gas sales, net of hedge losses |
|
$ |
26,211 |
|
|
$ |
24,640 |
|
|
$ |
73,652 |
|
|
$ |
50,760 |
|
Operating income |
|
$ |
9,525 |
|
|
$ |
15,021 |
|
|
$ |
31,666 |
|
|
$ |
26,012 |
|
Net income (loss) available to common stockholder |
|
$ |
10,996 |
|
|
$ |
2,661 |
|
|
$ |
15,207 |
|
|
$ |
(9,277 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.30 |
|
|
$ |
0.08 |
|
|
$ |
0.43 |
|
|
$ |
(0.29 |
) |
Diluted |
|
$ |
0.30 |
|
|
$ |
0.08 |
|
|
$ |
0.42 |
|
|
$ |
(0.29 |
) |
(9)
NOTE 5. PREFERRED STOCK
At March 31, 2005, we had outstanding 950,000 shares of 6% Convertible Preferred Stock, $0.10
par value per share. Cumulative annual dividends of $0.60 per share are payable semi-annually on
June 15 and December 15 of each year. Each share of preferred stock was entitled to be converted,
at the option of the holder, into 2.8571 shares of common stock at an initial conversion price of
$3.50 per share, subject to adjustment in certain events. The preferred stock has a liquidation
preference of $10 per share and had no voting rights, except as required by law.
On May 4, 2005, we notified the holders of the preferred stock that all 950,000 outstanding
shares of our 6% preferred stock would be redeemed on June 6, 2005. All of the holders of the
preferred stock elected to convert their shares of preferred stock into shares of Parallel common
stock based on a conversion rate of $10 divided by $3.50. The holders of the preferred stock
received approximately 2.8571 shares of common stock of Parallel for each share of preferred stock.
Dividends on the preferred stock ceased to accrue, and as of June 6, 2005 the preferred stock was
no longer outstanding.
NOTE 6. FULL COST CEILING TEST
We use the full cost method to account for our oil and natural gas producing activities. Under
the full cost method of accounting, the net book value of oil and natural gas properties, less
related deferred income taxes, may not exceed a calculated ceiling. The ceiling limitation is the
discounted estimated after-tax future net cash flows from proved oil and natural gas properties. In
calculating future net cash flows, current prices and costs are generally held constant
indefinitely as adjusted for qualifying cash flow hedges. The net book value of oil and natural
gas properties, less related deferred income taxes is compared to the ceiling on a quarterly and
annual basis. Any excess of the net book value, less related deferred income taxes, is generally
written off as an expense. Under rules and regulations of the SEC, the excess above the ceiling may
not be written off if, subsequent to the end of the quarter or year but prior to the release of the
financial results, prices have increased sufficiently that such excess above the ceiling would not
have existed if the increased prices were used in the calculations.
At September 30, 2006, we had a cushion (i.e. the excess of the ceiling over our capitalized
cost) in excess of $120.0 million. As a result, we were not required to record a reduction of our
oil and natural gas properties under the full cost method of accounting at that time.
Under the full cost method of accounting, all costs incurred in the acquisition, exploration
and development of oil and natural gas properties, including a portion of our overhead and interest
expense, are capitalized. In the nine month periods ended September 30, 2006 and 2005, overhead
costs capitalized were approximately $1.31 million and $0.92 million, respectively and capitalized
interest expense was $0.55 million and $0.10 million, respectively.
NOTE 7. DERIVATIVE INSTRUMENTS
General
We enter into derivative contracts to provide a measure of stability in the cash flows
associated with our oil and natural gas production and interest rate payments and to manage
exposure to commodity price and interest rate risk. Our objective is to lock in a range of oil and
natural gas prices and to limit variability in our cash interest payments. Our line of credit
agreement as of September 30, 2006, required us to maintain derivative financial instruments which
limit our exposure to fluctuating commodity prices covering at least 50% of our estimated monthly
production of oil and natural gas extending 24 months into the future.
We designated all of our interest rate swaps, collars, puts and commodity swaps entered into
in 2002 through June 30, 2004 as cash flow hedges (hedges). The effective portion of the
unrealized gain or loss on cash flow hedges is recorded in other comprehensive income (loss) until
the forecasted transaction occurs. During the term of a cash flow hedge, the effective portion of
the quarterly change in the fair value of the derivatives is recorded in stockholders equity as
other comprehensive income (loss) and then transferred to oil and natural gas revenues when the
production is sold and interest expense as the interest accrues. Ineffective portions of hedges
(changes in fair value resulting from changes in realized prices that do not match the changes in
the hedge or reference price) are recognized in gain (loss) on ineffective portion of hedges as
they occur.
(10)
As of September 30, 2006, we have recorded unrealized losses of $2.3 million ($1.5 million,
net of tax) related to our derivative instruments designated as hedges, which represented the
estimated aggregate fair values of our open hedge contracts as of that date. These unrealized
losses are presented in stockholders equity in the Consolidated Balance Sheet as accumulated other
comprehensive loss.
Derivative contracts not designated as hedges are marked-to-market at each period end and
the increases or decreases in fair values recorded to earnings. No derivative instruments entered
into subsequent to June 30, 2004 have been designated as cash flow hedges.
We are exposed to credit risk in the event of nonperformance by the counterparty to these
contracts, BNP Paribas and Citibank, N.A. However, we periodically assess the creditworthiness of
the counterparty to mitigate this credit risk.
Interest Rate Sensitivity
We entered into fixed interest rate swap contracts with BNP Paribas, based on the 90-day LIBOR
rates at the time of the contracts. These interest rate swaps are treated as cash flow hedges as
defined by Statement of Financial Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities, as amended (SFAS 133), and are on $10.0 million of our
variable rate debt for all of 2006. We will continue to pay the variable interest rates for this
portion of our borrowing under the Credit Agreement, but due to the interest rate swaps, we have
fixed the rate at 4.05%. As of September 30, 2006, the fair market value of these interest rate
swaps was $0.03 million.
We have employed additional fixed interest rate swap contracts with BNP Paribas and Citibank,
N.A. based on the 90-day LIBOR rates at the time of the contracts. However, these contracts are
accounted for by mark-to-market accounting as prescribed in SFAS 133. Nonetheless, we view these
contracts as additional protection against future interest rate volatility.
The table below recaps the nature of these interest rate swaps and the fair market value of
these contracts as of September 30, 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional |
|
|
|
|
|
|
Fair |
|
Period of Time |
|
Amounts |
|
|
Fixed Interest Rates |
|
|
Market Value |
|
|
|
($ in millions) |
|
|
|
|
|
|
($ in thousands) |
|
October 1, 2006 thru December 31, 2006 (1) |
|
$ |
10 |
|
|
|
4.05 |
% |
|
$ |
30 |
|
October 1, 2006 thru December 31, 2006 |
|
$ |
50 |
|
|
|
4.41 |
% |
|
|
307 |
|
January 1, 2007 thru December 31, 2007 |
|
$ |
100 |
|
|
|
4.62 |
% |
|
|
469 |
|
January 1, 2008 thru December 31, 2008 |
|
$ |
100 |
|
|
|
4.86 |
% |
|
|
(119 |
) |
January 1, 2009 thru December 31, 2009 |
|
$ |
50 |
|
|
|
5.06 |
% |
|
|
(82 |
) |
January 1, 2010 thru October 31, 2010 |
|
$ |
50 |
|
|
|
5.15 |
% |
|
|
(59 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
$ |
546 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Designated as cash flow hedge. |
Commodity Price Sensitivity
Except for the one commodity swap noted in the table below under Commodity Swaps that is
designated as a hedge, all of our commodity derivatives are accounted for using mark-to-market
accounting as prescribed in SFAS 133.
Put Options. In 2005 we purchased put options or floors on volumes of 3,000 MMBtu
per day for a total of 642,000 MMBtu during the seven month period from April 1, 2006 through
October 31, 2006 at an average floor price of $7.17 per MMBtu for a total consideration of
approximately $0.23 million. The remaining put options volumes of 93,000 MMBtu have a fair market
value of $0.30 million as of September 30, 2006.
Collars. Collars are contracts which combine both a put option or floor and a call
option or ceiling. These contracts may or may not involve payment or receipt of cash at
inception, depending on the ceiling and floor pricing.
(11)
A summary of our collar positions at September 30, 2006 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
M M Btu |
|
|
Houston Ship |
|
|
|
|
|
|
|
|
|
|
Fair |
|
|
|
Barrels of |
|
|
NyMex Oil Prices |
|
|
of Natural |
|
|
Channel Gas Prices |
|
|
WAHA Gas Prices |
|
|
Market |
|
Period of Time |
|
Oil |
|
|
Floor |
|
|
Cap |
|
|
Gas |
|
|
Floor |
|
|
Cap |
|
|
Floor |
|
|
Cap |
|
|
Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ in |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
thousands) |
|
October 1, 2006 thru
December 31, 2006 |
|
|
99,000 |
|
|
$ |
53.12 |
|
|
$ |
80.87 |
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(246 |
) |
October 1, 2006 thru
October 31, 2006 |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
|
62,000 |
|
|
$ |
7.50 |
|
|
$ |
13.90 |
|
|
$ |
|
|
|
$ |
|
|
|
|
217 |
|
October 1, 2006 thru
October 31, 2006 |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
|
31,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
9.00 |
|
|
$ |
14.55 |
|
|
|
164 |
|
January 1, 2007 thru
December 31, 2007 |
|
|
292,000 |
|
|
$ |
55.63 |
|
|
$ |
84.88 |
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
146 |
|
April 1, 2007 thru
October 31, 2007 |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
|
214,000 |
|
|
$ |
6.00 |
|
|
$ |
11.05 |
|
|
$ |
|
|
|
$ |
|
|
|
|
51 |
|
January 1, 2008 thru
December 31, 2008 |
|
|
237,900 |
|
|
$ |
60.38 |
|
|
$ |
81.08 |
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
236 |
|
January 1, 2009 thru
December 31, 2009 |
|
|
620,500 |
|
|
$ |
63.53 |
|
|
$ |
80.21 |
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
1,583 |
|
January 1, 2010 thru
October 31, 2010 |
|
|
486,400 |
|
|
$ |
63.44 |
|
|
$ |
78.26 |
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
1,492 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
3,643 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
A recap for the period of time, number of barrels and swap prices are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nymex Oil |
|
|
Fair Market |
|
Period of Time |
|
Barrels of Oil |
|
|
Swap Price |
|
|
Value |
|
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
|
October 1, 2006 thru December 20, 2006 (1) |
|
|
60,750 |
|
|
$ |
23.04 |
|
|
$ |
(2,476 |
) |
October 1, 2006 thru December 31, 2006 |
|
|
46,000 |
|
|
$ |
36.35 |
|
|
|
(1,275 |
) |
January 1, 2007 thru December 31, 2007 |
|
|
474,500 |
|
|
$ |
34.36 |
|
|
|
(15,315 |
) |
January 1, 2008 thru December 31, 2008 |
|
|
439,200 |
|
|
$ |
33.37 |
|
|
|
(14,195 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total fair market value |
|
|
|
|
|
|
|
|
|
$ |
(33,261 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Designated as a cash flow hedge. |
NOTE 8. NET INCOME (LOSS) PER COMMON SHARE
Basic earnings per share (EPS) exclude any dilutive effects of option, warrants and
convertible securities and is computed by dividing income available to common stockholders by the
weighted average number of common shares outstanding for the period. Diluted earnings per share are
computed similar to basic earnings per share. However, diluted earnings per share reflect the
assumed conversion of all potentially dilutive securities.
(12)
The following table provides the computation of basic and diluted earnings per share for the
three and nine months ended September 30, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
|
|
(dollars in thousands, except per share data) |
|
Basic EPS Computation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) |
|
$ |
10,996 |
|
|
$ |
1,989 |
|
|
$ |
15,071 |
|
|
$ |
(9,961 |
) |
Preferred stock dividend |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(271 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) available to common stockholders |
|
$ |
10,996 |
|
|
$ |
1,989 |
|
|
$ |
15,071 |
|
|
$ |
(10,232 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding |
|
|
36,215 |
|
|
|
34,033 |
|
|
|
35,340 |
|
|
|
31,585 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) per share |
|
$ |
0.30 |
|
|
$ |
0.06 |
|
|
$ |
0.43 |
|
|
$ |
(0.32 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS Computation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) |
|
$ |
10,996 |
|
|
$ |
1,989 |
|
|
$ |
15,071 |
|
|
$ |
(9,961 |
) |
Preferred stock dividend |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(271 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) available to common stockholders |
|
$ |
10,996 |
|
|
$ |
1,989 |
|
|
$ |
15,071 |
|
|
$ |
(10,232 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding |
|
|
36,215 |
|
|
|
34,033 |
|
|
|
35,340 |
|
|
|
31,585 |
|
Employee stock options |
|
|
596 |
|
|
|
774 |
|
|
|
581 |
|
|
|
|
|
Warrants |
|
|
108 |
|
|
|
144 |
|
|
|
106 |
|
|
|
|
|
Preferred stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares for diluted
earnings per share assuming conversion |
|
|
36,919 |
|
|
|
34,951 |
|
|
|
36,027 |
|
|
|
31,585 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) per share |
|
$ |
0.30 |
|
|
$ |
0.06 |
|
|
$ |
0.42 |
|
|
$ |
(0.32 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Some stock options and the convertible preferred stock outstanding were not included in
the computation of diluted net income (loss) per share for the nine months ended September 30, 2005
because Parallel had a net loss from continuing operations and, therefore, the effect would be
antidilutive.
NOTE 9. ASSET RETIREMENT OBLIGATIONS
On January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143, Accounting
for Asset Retirement Obligations SFAS 143. SFAS 143 requires us to recognize a liability for
the present value of all obligations associated with the retirement of tangible long-lived assets
and to capitalize an equal amount as a cost of the related oil and natural gas properties.
(13)
The following table summarizes our asset retirement obligation transactions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Beginning asset retirement obligation |
|
$ |
4,420 |
|
|
$ |
2,251 |
|
|
$ |
2,495 |
|
|
$ |
2,132 |
|
Additions related to new properties |
|
|
123 |
|
|
|
37 |
|
|
|
314 |
|
|
|
166 |
|
Revisions in estimated cash flows |
|
|
11 |
|
|
|
(12 |
) |
|
|
1,674 |
|
|
|
(9 |
) |
Deletions related to property disposals |
|
|
|
|
|
|
(17 |
) |
|
|
(30 |
) |
|
|
(84 |
) |
Accretion expense |
|
|
71 |
|
|
|
28 |
|
|
|
172 |
|
|
|
82 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending asset retirement obligation |
|
$ |
4,625 |
|
|
$ |
2,287 |
|
|
$ |
4,625 |
|
|
$ |
2,287 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion expense is recognized as a component of lease operating expense.
NOTE 10. RECENTLY ANNOUNCED ACCOUNTING PRONOUNCEMENTS
In July 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income
Taxesan Interpretation of FASB Statement No. 109 (FIN 48). FIN 48 clarifies the accounting for
uncertainty in income taxes recognized in an entitys financial statements in accordance with SFAS
No. 109, Accounting for Income Taxes, and prescribes a recognition threshold and measurement
attribute for the financial statement recognition and measurement of a tax position taken or
expected to be taken in a tax return. Additionally, FIN 48 provides guidance on subsequent
derecognition of tax positions, financial statement classification, recognition of interest and
penalties, accounting in interim periods, and disclosure and transition requirements. FIN 48 is
effective for the Companys fiscal year beginning January 1, 2007, with early adoption permitted.
The Company is in the process of evaluating FIN 48.
In September 2006, the Securities and Exchange Commission (SEC) issued Staff Accounting
Bulletin No. 108 (SAB 108). Due to diversity in practice among registrants, SAB 108 expresses
SEC staff views regarding the process by which misstatements in financial statements are evaluated
for purposes of determining whether financial statement restatement is necessary, SAB 108 is
effective for fiscal years ending after November 15, 2006, and early application is encouraged.
Parallel does not believe SAB 108 will have a material impact on our financial position or results
from operations.
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair
Value Measurements (FAS 157). This Statement defines fair value as used in numerous accounting
pronouncements, establishes a framework for measuring fair value in generally accepted account
principles and expands disclosure related to the use of fair value measures in financial
statements. The Statement is to be effective for Parallels financial statements issued in 2008;
however, earlier application is encouraged. Parallel is currently evaluating the timing of
adoption and the impact that adoption might have on our financial position or results of
operations.
NOTE 11. INVESTMENT IN GAS GATHERING SYSTEM
Parallel has invested $5.6 million in an unincorporated joint venture which is constructing
and will operate a gas gathering system in Chaves County, New Mexico. Parallel owns approximately
76.5% of the joint venture interest. The joint venture is
managed by a three-member management committee consisting of one
member appointed by Parallel and two other members appointed by
the other two participants in the
joint venture. All significant actions of the joint venture must be approved by a vote
representing a majority of the joint venture ownership interest plus one other management committee
member. Therefore, either Parallel or the remaining two joint venturers acting in concert have the
power to veto any matter. As a result of this voting arrangement, Parallel does not have effective
voting control and, therefore, Parallels investment in the joint venture is accounted for by the
equity method.
(14)
NOTE 12. COMMITMENTS AND CONTINGENCIES
On December 30, 2005, Parallel was named as a defendant in a lawsuit filed in the 352nd
Judicial District Court of Tarrant County, Texas, Cause No. 352-215616-05, AFE Oil and Gas, L.L.C.
(aka AFE Oil and Gas, LLC) v. Premium Resources II, L.P., Premium Resources, Inc., Danay Covert,
Nick Morris, William D. Middleton, Dale Resources, L.L.C., and Parallel Petroleum, Inc.
In this suit, the plaintiff alleges breach of fiduciary duty, fraud and conspiracy to defraud,
breach of contract, constructive trust, suit to remove cloud from title, declaratory judgment,
alter ego, and statutory fraud and seeks recovery of an unspecified amount of actual damages,
special damages, consequential damages, exemplary damages, attorneys fees, pre-judgment and
post-judgment interest and costs. Generally, the plaintiff alleges that it owns a 5.5% overriding
royalty interest in certain oil and gas properties known as the Square Top LP and the West Fork
LP leases located in Tarrant County, Texas. The plaintiff alleges that the defendants (other than
Dale Resources and Parallel) wrongfully and intentionally allowed these original oil and gas leases
to terminate; causing the termination of plaintiffs overriding royalty interest in each lease. The
plaintiff further alleges that the defendants (other than Dale Resources and Parallel) failed to
drill wells necessary to maintain the original leases in force and that after the original leases
were allowed to terminate, the defendants (other than Dale Resources and Parallel) then acquired
new oil and gas leases covering these same oil and gas properties, which were subsequently assigned
to Dale Resources. Thereafter, Dale Resources allegedly assigned a portion of these new leases to
Parallel.
In addition to seeking unspecified monetary damages, the plaintiff also seeks to impose a
constructive trust for its benefit on the new oil and natural gas leases and seeks a judicial
declaration that either (1) the plaintiff is the owner of an overriding royalty interest in the new
leases or that (2) the original leases and plaintiffs interest in the original leases are still in
effect. The plaintiff also claims that the new leases constitute a cloud on plaintiffs title and
seeks to have that cloud removed. Based on Parallels present understanding of this case, Parallel
believes that it has substantial defenses to the plaintiffs claims and intends to vigorously
assert these defenses. However, if the plaintiff is awarded an interest in the new leases, then
Parallel could potentially become liable for the payment to plaintiff of the portion of production
proceeds attributable to plaintiffs interest received by Parallel. On the other hand, if the
plaintiff prevails on its claim that the original leases are still in effect, Parallels interest
in the new leases could become subject to forfeiture. Based on the information known to date,
Parallel has not established a reserve for this matter.
We are not aware of any other threatened litigation and we have not been a party to any
bankruptcy, receivership, reorganization, adjustment or similar proceeding.
Effective January 1, 2005, we established a 401(k) Plan and Trust for eligible employees.
Employees may not participate in the former SEP plan with the establishment of the 401(k) Plan and
Trust. As of the nine months ending September 30, 2006 and 2005 Parallel had made contributions to
the 401(k) Plan and Trust of approximately $0.17 million and $0.12 million, respectively.
ITEM 2. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
The following discussion and analysis should be read in conjunction with managements
discussion and analysis contained in our 2005 Annual Report on Form 10-K, as well as the unaudited
consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.
OVERVIEW
Strategy
Our primary objective is to increase shareholder value of our common stock through increasing
reserves, production, cash flow and earnings. We have shifted the balance of our investments from
properties having high rates of production in early years to properties expected to produce more
consistently over a longer term. We attempt to reduce our financial risks by dedicating a smaller
portion of our capital to high risk projects, while reserving the majority of our available capital
for exploitation and development drilling opportunities. Obtaining positions in long-lived oil and
natural gas reserves are given priority over properties that might provide more cash flow in the
early years of production, but which have shorter reserve lives. We also attempt to further reduce
risk by emphasizing acquisition possibilities over high risk
(15)
exploration projects.
Since the latter part of 2002, we have reduced our emphasis on high risk exploration efforts
and focused on established geologic trends where we utilize the engineering, operational, financial
and technical expertise of our entire staff. Although we anticipate participating in exploratory
drilling activities in the future, reducing financial, reservoir, drilling and geological risks and
diversifying our property portfolio are important criteria in the execution of our business plan.
In summary, our current business plan:
|
|
|
focuses on projects having less geological risk; |
|
|
|
|
emphasizes exploitation and enhancement activities; |
|
|
|
|
focuses on acquiring producing properties; and |
|
|
|
|
expands the scope of operations by diversifying our exploratory and development
efforts, both in and outside of our current areas of operation. |
Although the direction of our exploration and development activities has shifted from high
risk exploratory activities to lower risk development opportunities, we will continue our efforts,
as we have in the past, to maintain low general and administrative expenses relative to the size of
our overall operations, utilize advanced technologies, serve as operator in appropriate
circumstances, and reduce operating costs.
The extent to which we are able to implement and follow through with our business plan will be influenced by:
|
|
|
the prices we receive for the oil and natural gas we produce; |
|
|
|
|
the results of reprocessing and reinterpreting our 3-D seismic data; |
|
|
|
|
the results of our drilling activities; |
|
|
|
|
the costs of obtaining high quality field services; |
|
|
|
|
our ability to find and consummate acquisition opportunities; and |
|
|
|
|
our ability to negotiate and enter into work to earn arrangements, joint venture or
other similar agreements on terms acceptable to us. |
Significant changes in the prices we receive for the oil and natural gas, or the occurrence of
unanticipated events beyond our control may cause us to defer or deviate from our business plan,
including the amounts we have budgeted for our activities.
Operating Performance
Our operating performance is influenced by several factors, the most significant of which are
the prices we receive for our oil and natural gas and our production volumes. The world price for
oil has overall influence on the prices that we receive for our oil production. The prices
received for different grades of oil are based upon the world price for oil, which is then adjusted
based upon the particular grade. Typically, light oil is sold at a premium, while heavy grades of
crude are discounted. Natural gas prices we receive are influenced by:
|
|
|
seasonal demand; |
|
|
|
|
weather; |
|
|
|
|
hurricane conditions in the Gulf of Mexico; |
|
|
|
|
availability of pipeline transportation to end users; |
|
|
|
|
proximity of our wells to major transportation pipeline infrastructures; and |
|
|
|
|
to a lesser extent, world oil prices. |
(16)
|
|
Additional factors influencing our overall operating performance include: |
|
|
|
production expenses; |
|
|
|
|
overhead requirements; and |
|
|
|
|
costs of capital. |
Our oil and natural gas exploration, development and acquisition activities require
substantial and continuing capital expenditures. Historically, the sources of financing to fund
our capital expenditures have included:
|
|
|
cash flow from operations; |
|
|
|
|
sales of our equity securities; |
|
|
|
|
bank borrowings; and |
|
|
|
|
industry joint ventures. |
For the three months ended September 30, 2006 the sale price we received for our crude oil
production (excluding hedges) averaged $64.53 per barrel compared with $58.95 per barrel for the
three months ended September 30, 2005. The average sales price we received for natural gas for the
three months ended September 30, 2006 (excluding hedges), was $5.64 per Mcf compared with $9.88 per
Mcf for the three months ended September 30, 2005. For information regarding prices received
including our hedges, refer to the selected operating data table in the Results of Operations on
page 18. Hedge costs for oil were $3.3 million and $3.7 million for the three months ended
September 30, 2006 and September 30, 2005, respectively. The hedge gain associated with the
ineffective portion of our hedges decreased $0.1 million to a gain of approximately $0.3 million in
the three months ended September 30, 2006 compared to a gain of $0.4 million for the three months
ended September, 2005. The gain on ineffectiveness is caused by a narrowing of the differential
price of West Texas Intermediate Light and current designated sales of West Texas Sour barrels.
The majority of our oil is West Texas Sour. Actual gains or losses may increase or decrease until
settlement of these contracts.
For the nine months ended September 30, 2006, the sale price we received for our crude oil
production (excluding hedges) averaged $61.88 per barrel compared with $50.86 per barrel for the
nine months ended September 30, 2005. The average sales price we received for natural gas for the
nine months ended September 30, 2006 (excluding hedges), was $6.11 per Mcf compared with $8.01 per
Mcf for the nine months ended September 30, 2005. For information regarding prices received
including our hedges, refer to the selected operating data table in the Results of Operations on
page 18. Hedge costs for oil and natural gas were $9.3 million and $9.0 million for the nine
months ended September 30, 2006 and September 30, 2005, respectively. The hedge gain (loss)
associated with the ineffective portion of our hedges increased approximately $1.0 million to a
gain of approximately $0.5 million in the nine months ended September 30, 2006 compared to a loss
of approximately ($0.5 million) for the nine months ended September 30, 2005. The reduction in
ineffectiveness is caused by a reduction of the differential price of West Texas Intermediate Light
and current designated sales of West Texas Sour barrels. The majority of our oil is West Texas
Sour. Actual gains or losses may increase or decrease until settlement of these contracts.
Our oil and natural gas producing activities are accounted for using the full cost method of
accounting. Under this accounting method, we capitalize all costs incurred in connection with the
acquisition of oil and natural gas properties and the exploration for and development of oil and
natural gas reserves. These costs include lease acquisition costs, geological and geophysical
expenditures, costs of drilling productive and non-productive wells, and overhead expenses directly
related to land and property acquisition and exploration and development activities. Proceeds from
the disposition of oil and natural gas properties are accounted for as a reduction in capitalized
costs, with no gain or loss recognized unless a disposition involves a material change in reserves,
in which case the gain or loss is recognized.
Depletion of the capitalized costs of oil and natural gas properties, including estimated
future development costs, is provided using the equivalent unit-of-production method based upon
estimates of proved oil and natural gas reserves and production, which are converted to a common
unit of measure based upon their relative energy content. Unproved oil and natural gas properties
are not amortized, but are individually assessed for impairment. The cost of any impaired property
is transferred to the balance of oil and natural gas properties being depleted. Depletion per BOE
at September 30, 2006 and
(17)
2005 was $10.53 and $7.27 respectively.
Results of Operations
Our business activities are characterized by frequent, and sometimes significant, changes in
our:
|
|
|
reserve base; |
|
|
|
|
sources of production; |
|
|
|
|
product mix (gas versus oil volumes); and |
|
|
|
|
the prices we receive for our oil and natural gas production. |
Year-to-year or other periodic comparisons of the results of our operations can be difficult
and may not fully and accurately describe our condition. The following table shows selected
operating data for each of the three and nine months ended September 30, 2006 and September 30,
2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
9/30/2006 |
|
|
9/30/2005 |
|
|
9/30/2006 |
|
|
9/30/2005 |
|
|
|
(in thousands, except per unit data) |
|
Production Volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
282 |
|
|
|
247 |
|
|
|
848 |
|
|
|
672 |
|
Natural gas (Mcf) |
|
|
2,001 |
|
|
|
1,109 |
|
|
|
4,894 |
|
|
|
2,411 |
|
BOE (1) |
|
|
616 |
|
|
|
432 |
|
|
|
1,664 |
|
|
|
1,074 |
|
BOE per day |
|
|
6.7 |
|
|
|
4.7 |
|
|
|
6.1 |
|
|
|
3.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per
Bbl) (2) |
|
$ |
64.53 |
|
|
$ |
58.95 |
|
|
$ |
61.88 |
|
|
$ |
50.86 |
|
Natural gas
(per Mcf) (2) |
|
$ |
5.64 |
|
|
$ |
9.88 |
|
|
$ |
6.11 |
|
|
$ |
8.01 |
|
BOE price (2) |
|
$ |
47.91 |
|
|
$ |
59.09 |
|
|
$ |
49.50 |
|
|
$ |
49.81 |
|
BOE price (3) |
|
$ |
42.58 |
|
|
$ |
50.60 |
|
|
$ |
43.93 |
|
|
$ |
41.46 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
18,194 |
|
|
$ |
14,550 |
|
|
$ |
52,478 |
|
|
$ |
34,168 |
|
Oil hedge |
|
|
(3,279 |
) |
|
|
(3,664 |
) |
|
|
(9,264 |
) |
|
|
(8,759 |
) |
Natural gas |
|
|
11,296 |
|
|
|
10,951 |
|
|
|
29,882 |
|
|
|
19,306 |
|
Natural gas hedge |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(201 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
26,211 |
|
|
$ |
21,837 |
|
|
$ |
73,096 |
|
|
$ |
44,514 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
|
$ |
5,323 |
|
|
$ |
2,663 |
|
|
$ |
12,639 |
|
|
$ |
7,399 |
|
Production taxes |
|
|
1,538 |
|
|
|
1,334 |
|
|
|
4,116 |
|
|
|
2,615 |
|
General and administrative: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative |
|
|
1,579 |
|
|
|
1,113 |
|
|
|
4,236 |
|
|
|
2,941 |
|
Public reporting |
|
|
826 |
|
|
|
622 |
|
|
|
2,911 |
|
|
|
1,830 |
|
Depreciation, depletion and amortization |
|
|
7,420 |
|
|
|
3,104 |
|
|
|
17,848 |
|
|
|
8,159 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
16,686 |
|
|
$ |
8,836 |
|
|
$ |
41,750 |
|
|
$ |
22,944 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
9,525 |
|
|
$ |
13,001 |
|
|
$ |
31,346 |
|
|
$ |
21,570 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 and natural gas.
|
|
(3) |
|
Hedged price is the actual price received at the wellhead for our oil and natural gas plus or
minus the settlements on our derivatives. |
(18)
RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2006 AND 2005:
Our oil and natural gas revenues and production product mix are displayed in the following
table for the three months ended September 30, 2006 and September 30, 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues (1) |
|
Production |
|
|
2006 |
|
2005 |
|
2006 |
|
2005 |
Oil and Gas Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
57 |
% |
|
|
50 |
% |
|
|
46 |
% |
|
|
57 |
% |
Natural gas (Mcf) |
|
|
43 |
% |
|
|
50 |
% |
|
|
54 |
% |
|
|
43 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes hedge transactions |
The following table outlines the detail of our operating revenues for the following
periods.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Increase |
|
|
% Increase |
|
|
|
2006 |
|
|
2005 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
(in thousands except per unit data) |
|
Production Volumes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
282 |
|
|
|
247 |
|
|
|
35 |
|
|
|
14 |
% |
Natural gas (Mcf) |
|
|
2,001 |
|
|
|
1,109 |
|
|
|
892 |
|
|
|
80 |
% |
BOE |
|
|
616 |
|
|
|
432 |
|
|
|
184 |
|
|
|
43 |
% |
BOE/Day |
|
|
6.7 |
|
|
|
4.7 |
|
|
|
2.0 |
|
|
|
43 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)(1) |
|
$ |
64.53 |
|
|
$ |
58.95 |
|
|
$ |
5.58 |
|
|
|
9 |
% |
Natural gas
(per Mcf) (1) |
|
$ |
5.64 |
|
|
$ |
9.88 |
|
|
$ |
(4.24 |
) |
|
|
(43 |
)% |
BOE price (1) |
|
$ |
47.91 |
|
|
$ |
59.09 |
|
|
$ |
(11.18 |
) |
|
|
(19 |
)% |
BOE price (2) |
|
$ |
42.58 |
|
|
$ |
50.60 |
|
|
$ |
(8.02 |
) |
|
|
(16 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
18,194 |
|
|
$ |
14,550 |
|
|
$ |
3,644 |
|
|
|
25 |
% |
Oil hedges |
|
$ |
(3,279 |
) |
|
$ |
(3,664 |
) |
|
$ |
(385 |
) |
|
|
(11 |
)% |
Natural gas |
|
$ |
11,296 |
|
|
$ |
10,951 |
|
|
$ |
345 |
|
|
|
3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
26,211 |
|
|
$ |
21,837 |
|
|
$ |
4,374 |
|
|
|
20 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Excludes hedge transactions. |
|
(2) |
|
Includes hedge transactions. |
Oil revenues, excluding hedges, increased $3.6 million or 25% for the three months ended
September 30, 2006 compared to the same period of 2005. Oil production volumes increased 14% which
was primarily due to the Harris Field acquisition and drilling programs in the Carm-Ann San Andres
Field/N. Means Queen Unit and the Diamond M Property. The increase in oil production increased
revenue approximately $2.1 million for 2006 (based on 2005 comparable period average prices).
Wellhead average realized crude oil prices increased $5.58 per Bbl or 9% to $64.53 per Bbl for 2006
compared to 2005. The increase in oil price increased revenue approximately $1.5 million for 2006
(based on current period production) for the three months ending September 30, 2006.
Natural gas revenues, excluding hedges, increased $0.3 million or 3% for the three months
ended September 30, 2006 compared to the same period of 2005. Natural gas production volumes
increased 80% primarily due to the drilling program in the Barnett Shale in north Texas, New Mexico
area and the Wilcox natural gas discovery in south Texas. The increase in natural gas volumes
increased revenue approximately $8.8 million (based on 2005 comparable period average prices) for
2006. Average realized wellhead natural gas prices decreased 43% or $4.24 per Mcf to $5.64 per
Mcf. The
(19)
decrease in natural gas prices had a negative effect on revenues of approximately $8.5
million (based on current period production) for the three months ending September 30, 2006.
Losses on oil hedges decreased $0.39 million or 11% for 2006 compared to 2005 due to the
decrease in oil prices. On a BOE basis, hedges accounted for a realized loss of $5.33 per BOE in
2006 compared to $8.49 per BOE in 2005. We
have hedged certain oil volumes in an attempt to mitigate price volatility and to meet the
requirements under our loan facility. BOE production increased 2,000 BOE/day or 43% for 2006
compared to the same period in 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, |
|
|
Increase |
|
|
% Increase |
|
|
|
2006 |
|
|
2005 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
|
|
|
|
(dollars in thousands) |
|
|
|
|
|
Cost and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
|
$ |
5,323 |
|
|
$ |
2,663 |
|
|
$ |
2,660 |
|
|
|
100 |
% |
Production taxes |
|
|
1,538 |
|
|
|
1,334 |
|
|
|
204 |
|
|
|
15 |
% |
General and administrative: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative |
|
|
1,579 |
|
|
|
1,113 |
|
|
|
466 |
|
|
|
42 |
% |
Public reporting |
|
|
826 |
|
|
|
622 |
|
|
|
204 |
|
|
|
33 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative |
|
|
2,405 |
|
|
|
1,735 |
|
|
|
670 |
|
|
|
39 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
7,420 |
|
|
|
3,104 |
|
|
|
4,316 |
|
|
|
139 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
16,686 |
|
|
$ |
8,836 |
|
|
$ |
7,850 |
|
|
|
89 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating costs increased approximately $2.7 million, or 100%, to $5.3 million
during the three months ended September 30, 2006 compared with $2.7 million for the same period of
2005. The increase in lease operating expense is primarily due to increased well count due to our
drilling program in the Diamond M Deep, Cam-Ann San Andres Field/ N. Means Queen Unit and Barnett
Shale Fields as well as the acquisition of the Harris Field, and increased ad valorem taxes.
Lifting costs were $8.64 per BOE in 2006 compared to $6.17 per BOE in 2005. The increase in
lifting costs is primarily due to general overall increases in operating costs including ad valorem
tax, service costs, electricity and chemicals.
Production taxes increased 15% or $0.2 million in 2006, associated with an increase in
revenues of $4.3 million. Production taxes in future periods will be a function of product mix,
production volumes and product prices.
General and administrative expenses in total increased 39% or $0.67 million in 2006 compared
to 2005. Included in our total general and administrative expenses is public reporting cost which
increased 33% or $0.2 million. Public reporting increased due to increases in investor
presentations and the annual stockholder meeting. In addition public reporting also experienced
increases in director stock option expenses as well as employee compensation related expenditures.
The remainder of the increase in general and administrative costs is due to employee compensation
and related benefit costs. General and administrative expenses capitalized to the full cost pool
were approximately $0.5 million for 2006 compared to $0.3 million in 2005. On a BOE basis, general
and administrative costs were $2.56 per BOE in 2006 compared to $2.58 per BOE in 2005, while public
reporting costs were $1.34 per BOE and $1.44 per BOE for the same period.
Depreciation, depletion and amortization expense increased 139% or $4.3 million for 2006
compared to 2005. Depreciation, depletion and amortization per BOE was $12.05 for 2006 and $7.19
for 2005. This increase is attributable to increased drilling costs, producing property purchases
and reserve revisions as a result of decreased product prices. Depletion costs are highly
correlated with production volumes, capital expenditures and product prices. Fiscal year 2006
depletion will increase with increased production volumes and capital expenditures.
(20)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, |
|
|
Increase |
|
|
% Increase |
|
|
|
2006 |
|
|
2005 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
(dollars in thousands) |
|
Other income (expense) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair market value of derivatives |
|
$ |
10,323 |
|
|
$ |
(9,388 |
) |
|
$ |
19,711 |
|
|
|
210 |
% |
Gain on ineffective portion of hedges |
|
|
305 |
|
|
|
404 |
|
|
|
(99 |
) |
|
|
(25 |
)% |
Interest and other income |
|
|
29 |
|
|
|
83 |
|
|
|
(54 |
) |
|
|
(65 |
)% |
Interest expense, net |
|
|
(3,345 |
) |
|
|
(1,060 |
) |
|
|
2,285 |
|
|
|
216 |
% |
Other expense |
|
|
(96 |
) |
|
|
(75 |
) |
|
|
21 |
|
|
|
28 |
% |
Equity in gain (loss) of pipelines
and gathering system ventures |
|
|
(39 |
) |
|
|
22 |
|
|
|
(61 |
) |
|
|
(277 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
7,177 |
|
|
$ |
(10,014 |
) |
|
$ |
17,191 |
|
|
|
172 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We recorded a change in fair market value of derivatives of $10.3 million in 2006
compared to a loss of $9.4 million in 2005. This is an increase to earnings of $19.7 million. The
gain associated with the ineffective portion of our hedges decreased $0.1 million for 2006 compared
to 2005. Crude oil prices continued to increase into the third quarter of 2006. Meanwhile natural
gas prices continued to decline in the third quarter of 2006. Our total volumes designated as cash
flow hedges decreased in 2006 compared to 2005 and as a result the ineffectiveness associated with
the hedged volumes decreased accordingly. The actual gain or loss may increase or decrease until
settlement of these contracts.
Interest expense increased with the increase of debt from approximately $68.0 million at
September 30, 2005 to $147.0 million at September 30, 2006 along with an increase of our loan
interest rate for 2006. Capitalized interest on work in progress decreased interest expense by
$0.25 million in 2006, an increase of $0.20 million compared to 2005.
Income tax expense was $5.7 million in 2006 compared to $1.0 million in 2005. Income tax
expense for 2006 will be dependent on our earnings and is expected to be approximately 35% of
income before income taxes.
We had basic net earnings per share of $0.30 and $0.06 and diluted net earnings per share of
$0.30 and $0.06 for 2006 and 2005, respectively. Basic weighted average common shares outstanding
increased from 34.0 million shares in 2005 to 36.2 million shares in 2006. The increase in common
shares is due to the sale of 2.5 million shares of common stock in August of 2006.
RESULTS OF OPERATIONS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2006 AND 2005:
Our oil and natural gas revenues and production product mix are displayed in the following
table for the nine months ended September 30, 2006 and September 30, 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues (1) |
|
Production |
|
|
2006 |
|
2005 |
|
2006 |
|
2005 |
Oil and Gas Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
59 |
% |
|
|
57 |
% |
|
|
51 |
% |
|
|
63 |
% |
Natural gas (Mcf) |
|
|
41 |
% |
|
|
43 |
% |
|
|
49 |
% |
|
|
37 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes hedge transactions |
(21)
The following table outlines the detail of our operating revenues for the following periods.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
Increase |
|
|
% Increase |
|
|
|
2006 |
|
|
2005 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
(in thousands except per unit data) |
|
Production Volumes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
848 |
|
|
|
672 |
|
|
|
176 |
|
|
|
26 |
% |
Natural gas (Mcf) |
|
|
4,894 |
|
|
|
2,411 |
|
|
|
2,483 |
|
|
|
103 |
% |
BOE |
|
|
1,664 |
|
|
|
1,074 |
|
|
|
590 |
|
|
|
55 |
% |
BOE/Day |
|
|
6.1 |
|
|
|
3.9 |
|
|
|
2.2 |
|
|
|
56 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per
Bbl) (1) |
|
$ |
61.88 |
|
|
$ |
50.86 |
|
|
$ |
11.02 |
|
|
|
22 |
% |
Natural gas
(per Mcf) (1) |
|
$ |
6.11 |
|
|
$ |
8.01 |
|
|
$ |
(1.90 |
) |
|
|
(24 |
)% |
BOE price (1) |
|
$ |
49.50 |
|
|
$ |
49.81 |
|
|
$ |
(0.31 |
) |
|
|
(1 |
)% |
BOE price (2) |
|
$ |
43.93 |
|
|
$ |
41.46 |
|
|
$ |
2.47 |
|
|
|
6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
52,478 |
|
|
$ |
34,168 |
|
|
|
18,310 |
|
|
|
54 |
% |
Oil hedges |
|
$ |
(9,264 |
) |
|
$ |
(8,759 |
) |
|
|
505 |
|
|
|
6 |
% |
Natural gas |
|
$ |
29,882 |
|
|
$ |
19,306 |
|
|
|
10,576 |
|
|
|
55 |
% |
Natural gas hedges |
|
$ |
|
|
|
$ |
(201 |
) |
|
|
(201 |
) |
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
73,096 |
|
|
$ |
44,514 |
|
|
|
28,582 |
|
|
|
64 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Excludes hedge transactions. |
|
(2) |
|
Includes hedge transactions. |
Oil revenues, excluding hedges, increased $18.3 million or 54% for the nine months ended
September 30, 2006 compared to the same period of 2005. Oil production volumes increased 26%
primarily due to the acquisition of the Harris Field and the drilling programs in the Cam-Ann San
Andres Field/N. Means Queen Unit and the Diamond M properties. The increase in oil production
increased revenue approximately $9.0 million (based on 2005 comparable period average prices) for
2006. Wellhead average realized crude oil prices increased $11.02 per Bbl or 22% to $61.88 per Bbl
for 2006 compared to 2005. The increase in oil price increased revenue approximately $9.3 million
for 2006 (based on current period production) for the nine months ending September 30, 2006.
Natural gas revenues, excluding hedges, increased $10.6 million or 55% for the nine months
ended September 30, 2006 compared to the same period of 2005. Natural gas production volumes
increased 103% primarily due to added production from new wells in New Mexico, Barnett Shale of
north Texas and the Wilcox discovery in south Texas. The increase in natural gas volumes increased
revenue approximately $19.9 million (based on 2005 comparable period average prices) for 2006.
Average realized wellhead natural gas prices decreased 24% or $1.90 per Mcf to $6.11 per Mcf. The
decrease in natural gas prices had a negative effect on revenues of approximately $9.3 million
(based on current period production) for the nine months ending September 30, 2006.
Losses on oil hedges increased $0.5 million or 6% for 2006 compared to 2005 due to the
increase in oil prices. Natural gas hedge losses were $0.2 million in 2005. On a BOE basis,
hedges accounted for a realized loss of $5.57 per BOE in 2006 compared to $8.35 per BOE in 2005.
We have hedged certain oil and natural gas volumes in an attempt to mitigate price volatility and
to meet the requirements under our loan facility. BOE production increased 2,200 BOE/day or 56%
for 2006 compared to the same period in 2005.
(22)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, |
|
|
Increase |
|
|
% Increase |
|
|
|
2006 |
|
|
2005 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
(dollars in thousands) |
|
Cost and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
|
$ |
12,639 |
|
|
$ |
7,399 |
|
|
$ |
5,240 |
|
|
|
71 |
% |
Production taxes |
|
|
4,116 |
|
|
|
2,615 |
|
|
|
1,501 |
|
|
|
57 |
% |
General and administrative: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative |
|
|
4,236 |
|
|
|
2,941 |
|
|
|
1,295 |
|
|
|
44 |
% |
Public reporting |
|
|
2,911 |
|
|
|
1,830 |
|
|
|
1,081 |
|
|
|
59 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative |
|
|
7,147 |
|
|
|
4,771 |
|
|
|
2,376 |
|
|
|
50 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
17,848 |
|
|
|
8,159 |
|
|
|
9,689 |
|
|
|
119 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
41,750 |
|
|
$ |
22,944 |
|
|
$ |
18,806 |
|
|
|
82 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating costs increased approximately $5.2 million, or 71%, to $12.6 million
during the nine months ended September 30, 2006 compared with $7.4 million for the same period of
2005. The increase in lease operating expense is primarily due to increased well count due to our
drilling program in the Diamond M, Carm-Ann San Andres Field/N. Means Queen Unit and Barnett Shale
Field as well as the acquisition of the Harris Field, and increased ad valorem taxes. Lifting
costs were $7.60 per BOE in 2006 compared to $6.89 per BOE in 2005. The increase in lifting costs
is primarily due to general overall increases in operating costs including ad valorem tax, service
costs, electricity and chemicals.
Production taxes increased 57% or $1.5 million in 2006, associated with an increase in
revenues of $28.9 million. Production taxes in future periods will be a function of product mix,
production volumes and product prices.
General and administrative expenses in total increased 50% or $2.4 million in 2006 compared to
2005. Included in our total general and administrative expenses is public reporting cost which
increased 59% or $1.1 million. Public reporting increased due to increases in investor relation
presentations including road shows and the stockholder meeting. In addition public reporting also
experienced increases in director stock option expenses as well as employee compensation related
expenditures. The remainder of the increase in general and administrative costs is due to
employee compensation and related benefit costs. During the second quarter of 2006, we determined
that during 2003 approximately 30,000 options were awarded which were not available for issue under
existing stock option plans. In June 2006, the Board of Directors approved a plan whereby these
excess options would be repurchased for cash totaling approximately $0.5 million. This amount was
charged to expense during the second quarter of 2006. General and administrative expenses
capitalized to the full cost pool were $1.3 million for 2006 compared to $0.9 million in 2005. On
a BOE basis, general and administrative costs were $2.55 per BOE in 2006 compared to $2.74 per BOE
in 2005, while public reporting costs were $1.75 per BOE and $1.70 per BOE for the same period.
Depreciation, depletion and amortization expense increased 119% or $9.7 million for 2006
compared to 2005. Depreciation, depletion and amortization per BOE was $10.73 for 2006 and $7.60
for 2005. This increase is attributable to increased drilling costs, producing property purchases
and reserve revisions as a result of decreased product prices. Depletion costs are highly
correlated with production volumes, capital expenditures and product prices. Fiscal year 2006
depletion will increase with increased production volumes and capital expenditures.
(23)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, |
|
|
Increase |
|
|
% Increase |
|
|
|
2006 |
|
|
2005 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
(dollars in thousands) |
|
Other income (expense) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair market value of derivatives |
|
$ |
116 |
|
|
$ |
(33,086 |
) |
|
$ |
33,202 |
|
|
|
100 |
% |
Gain (loss) on ineffective portion of hedges |
|
|
500 |
|
|
|
(456 |
) |
|
|
956 |
|
|
|
210 |
% |
Interest and other income |
|
|
122 |
|
|
|
124 |
|
|
|
(2 |
) |
|
|
(2 |
)% |
Interest expense, net |
|
|
(8,944 |
) |
|
|
(3,101 |
) |
|
|
5,843 |
|
|
|
188 |
% |
Other expense |
|
|
(164 |
) |
|
|
(77 |
) |
|
|
87 |
|
|
|
113 |
% |
Equity in loss of pipelines and gathering system ventures |
|
|
(68 |
) |
|
|
(72 |
) |
|
|
(4 |
) |
|
|
(6 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(8,438 |
) |
|
$ |
(36,668 |
) |
|
$ |
(28,230 |
) |
|
|
77 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We recorded a change in fair market value of derivatives of approximately $0.12 million
in 2006 compared to a loss of $33.1 million in 2005. The gain associated with the ineffective
portion of our hedges increased $1.0 million for 2006 compared to 2005. Crude oil prices increased
in 2006 over 2005. Meanwhile natural gas prices continued to decline in 2006. Our total volumes
designated as cash flow hedges decreased in 2006 compared to 2005 and as a result the
ineffectiveness associated with the hedged volumes decreased accordingly. The actual gain or loss
may increase or decrease until settlement of these contracts.
Interest expense increased with the increase of debt from approximately $68.0 million at
September 30, 2005 to $147.0 million at September 30, 2006 along with an increase of our loan
interest rate for 2006. Capitalized interest on work in progress decreased interest expense by
$0.55 million in 2006, an increase of $0.45 million compared to 2005.
Income tax expense was $7.8 million in 2006 compared to an income tax benefit of $5.1 million
in 2005. Income tax expense for 2006 will be dependent on our earnings and is expected to be
approximately 35% of income before income taxes.
We had basic net earnings per share of $0.43 and net loss of $0.32 and diluted net earnings
per share of $0.42 and net loss of $0.32 for 2006 and 2005, respectively. Basic weighted average
common shares outstanding increased from approximately 31.6 million shares in 2005 to approximately
35.3 million shares in 2006. The increase in common shares is due to our sale of 5.75 million
shares of common stock in February 2005, the conversion of preferred shares into common shares in
June, 2005 and our sale of 2.5 million shares of common stock in August 2006.
LIQUIDITY AND CAPITAL RESOURCES
Working capital decreased approximately $7.8 million as of September 30, 2006
compared with December 31, 2005. Current liabilities exceeded current assets by $7.4
million at September 30, 2006. The working capital decrease was due to increased obligations
associated with our accelerated drilling program for 2006.
We incurred net property costs of $155.1 million for the nine months ended September 30, 2006
compared to $34.7 million for the same period in 2005. The increase is primarily related to our
accelerated drilling activity and the Harris and Barnett Shale acquisitions. Our property
expenditures were $144.7 million for the first nine months of 2006 partially offset by restricted
cash utilized for property purchases. Investment in our pipelines and gathering systems was $9.7
million for the nine months ended September 30, 2006. Included in our increased property basis for
the nine months of 2006 and 2005 were net asset retirement costs of approximately $2.0 million and
$0.07 million, respectively (see Note 9 to Consolidated Financial Statements). Our property
leasehold acquisition, development and enhancement activities were financed by our bank borrowings,
the utilization of cash flows provided by operations and cash on hand.
On August 16, 2006, we had gross cash proceeds of approximately $63.1 million and net proceeds
of approximately $60.3 million from the sale of common stock (see Note 2 to Consolidated Financial
Statements). These proceeds and cash available were used for general corporate purposes, including
debt repayment and the acceleration of our drilling and completion operations in certain core areas
such as the Barnett Shale gas, New Mexico Wolfcamp gas and Permian Basin west Texas oil properties.
Stockholders equity is $171.1 million for September 30, 2006 compared to $89.5 million at
December 31, 2005, an increase of 91%. The increase is primarily attributable to the net proceeds
of approximately $60.3 million from the sale
(24)
of equity securities of 2,500,000 shares of our common
stock, a reduction in accumulated comprehensive loss of $4.9 million related to our derivative
instruments (see Note 7 to Consolidated Financial Statements) and net income of
approximately $15.1 million.
Historically, we have funded our operations, capital requirements and interest expense
requirements with cash flows from our oil and natural gas properties, bank borrowings and proceeds
from sales of our equity securities. Although we expect these same capital resources to support our
future activities, we continually review and consider alternative methods of financing.
Bank Borrowings
We have two separate credit facilities. Our Third Amended and Restated Credit Agreement (or
the Revolving Credit Agreement), dated as of December 23, 2005, with a group of bank lenders
provides a revolving line of credit having a borrowing base limitation of $156.0 million at
October 1, 2006. The total amount that we can borrow and have outstanding at any one time is
limited to the lesser of $350.0 million or the borrowing base established by the lenders. At
September 30, 2006, the principal amount outstanding under our revolving credit facility was $97.0
million, excluding $0.49 million reserved for our letters of credit. The second credit facility is
a five year term loan facility provided to us under a Second Lien Term Loan Agreement (the Second
Lien Agreement), dated as of November 15, 2005, with a group of banks and other lenders. At
September 30, 2006, our term loan under this facility was fully funded in the principal amount of
$50.0 million, which was outstanding on that same date.
Revolving Credit Facility
The Revolving Credit Agreement provides for a credit facility that allows us to borrow, repay
and reborrow amounts available under the revolving credit facility. The amount of the borrowing
base is based primarily upon the estimated value of our oil and natural gas reserves. The borrowing
base amount is redetermined by the lenders semi-annually on or about April 1 and October 1 of each
year or at other times required by the lenders or at our request. If, as a result of the lenders
redetermination of the borrowing base, the outstanding principal amount of our loans exceeds the
borrowing base, we must either provide additional collateral to the lenders or repay the
outstanding principal of our loans in an amount equal to the excess. Except for the principal
payments that may be required because of our outstanding loans being in excess of the borrowing
base, interest only is payable monthly.
Loans made to us under this revolving credit facility bear interest at the base rate of
Citibank, N.A. or the LIBOR rate, at our election. Generally, Citibanks base rate is equal to its
prime rate as announced from time to time by Citibank.
The LIBOR rate is generally equal to the sum of (a) the rate designated as British Bankers
Association Interest Settlement Rates and offered on one, two, three, six or twelve month interest
periods for deposits of $1.0 million, and (b) a margin ranging from 2.00% to 2.50%, depending upon
the outstanding principal amount of the loans. If the principal amount outstanding is equal to or
greater than 75% of the borrowing base, the margin is 2.50%. If the principal amount outstanding is
equal to or greater than 50%, but less than 75% of the borrowing base, the margin is 2.25%. If the
principal amount outstanding is less than 50% of the borrowing base, the margin is 2.00%.
The interest rate we are required to pay on our borrowings, including the applicable margin,
may never be less than 5.00%. At September 30, 2006, our weighted average base and LIBOR rates,
plus margin, were 7.64% on $97.0 million.
In the case of base rate loans, interest is payable on the last day of each month. In the case
of LIBOR loans, interest is payable on the last day of each applicable interest period.
If the total outstanding borrowings under the revolving credit facility are less than the
borrowing base, an unused commitment fee is required to be paid to the lenders. The amount of the
fee is .25% of the daily average of the unadvanced amount of the borrowing base. The fee is payable
quarterly.
If the borrowing base is increased, we are required to pay a fee of .375% on the amount of any
increase in the borrowing base.
All outstanding principal under the revolving credit facility is due and payable on October
31, 2010. The maturity date of our outstanding loans may be accelerated by the lenders upon the
occurrence of an event of default under the Revolving Credit Agreement.
(25)
As of September 30, 2006, we were in compliance with our debt covenants.
Second Lien Term Loan Facility
The Second Lien Agreement provides a $50.0 million term loan. Loans made to us under this
credit facility bear interest at an alternate base rate or the LIBOR rate, at our election. The
alternate base rate is the greater of (a) the prime rate in effect on such day and (b) the Federal
Funds Effective Rate in effect on such day plus 1/2 of 1%, plus a margin of 3.50% per annum.
The LIBOR rate is generally equal to the sum of a (a) the rate designated as British Bankers
Association Interest Settlement Rates and offered on one, two, three or six month interest periods
for deposits of $1.0 million and (b) an applicable margin rate per annum equal to 4.50%.
At September 30, 2006, our Libor interest rate, plus the applicable margin, was 9.9375% on
$50.0 million.
In the case of alternate base rate loans, interest is payable the last day of each March,
June, September and December. In the case of LIBOR loans, interest is payable the last day of the
tranche period not to exceed a three month period.
All outstanding principal under the Second Lien Agreement is due and payable on November 15,
2010. The maturity date may be accelerated by the lenders upon the occurrence of an event of
default under the Second Lien Agreement.
Prepayments in whole or in part if made prior to the first anniversary date will bear a
premium of 1% of the amount prepaid. There is no premium after the first anniversary date.
As of September 30, 2006 we were in compliance with our debt covenants.
Interest expense for the nine months ending September 30, 2006, for both facilities, was
approximately $9.2 million not including approximately $0.55 million for interest capitalized
associated with drilling projects.
Preferred Stock
On June 6, 2005, outstanding shares of Parallels 6% Convertible Preferred Stock, $0.10 par
value per share, were converted to common stock. Under terms of the preferred stock, all of the
holders of the preferred stock elected to convert their shares into shares of Parallel common stock
based on a conversion rate of $10.00 divided by $3.50. The holders of the preferred stock received
approximately 2.8571 shares of common stock of Parallel for each share of preferred stock.
Dividends on the preferred stock ceased to accrue, and as of June 6, 2005 the preferred stock was
no longer outstanding.
Sale of Equity Securities
On February 9, 2005, we sold 5,750,000 shares of our common stock, $.01 par value per share,
pursuant to a public offering at a price of $5.27 per share. Gross cash proceeds were $30.3
million, and net proceeds were approximately $28.0 million. The common shares were issued under
Parallels $100.0 million Universal Shelf Registration Statement on Form S-3 which became effective
in November 2004. The proceeds were used to reduce the revolving credit facility.
On August 16, 2006, we sold 2,500,000 shares of our common stock, $.01 par value per share,
pursuant to a public offering at a price of $25.25 per share. Gross cash proceeds were
approximately $63.1 million, and net proceeds were approximately $60.3 million. The common shares
were issued under Parallels $100.0 million Universal Shelf Registration Statement on Form S-3
which became effective in November 2004. The proceeds were used for general corporate purposes,
including debt repayment and the acceleration of our drilling and completion operations in certain
core areas such as the Barnett Shale gas, New Mexico Wolfcamp gas and Permian Basin west Texas oil
properties
Commodity Price Risk Management Transactions and Effects of Derivative Instruments
The purpose of all of our derivative trades is to provide a measure of stability in cash flow
as a result of our daily activities associated with the selling of oil and natural gas production
and expenditures associated with the borrowings that we have secured through our bank borrowings.
The derivative trade arrangements we have employed include collars, costless collars, floors or
purchased puts, oil and natural gas swaps and interest rate swaps. In 2003, we designated our
(26)
derivative trades as cash flow hedges under the provisions of SFAS 133, as amended. Although our
purpose for entering into derivative trades has remained the same, contracts entered into after
June 30, 2004 were not designated as cash flow hedges.
Under cash flow hedge accounting for oil and natural gas production, the quarterly effective
portion of the change in fair value of the commodity derivatives is recorded in stockholders
equity as other comprehensive income (loss) and
then transferred to revenue in the period the related oil and natural gas production is sold.
Ineffective portions of cash flow hedges (changes in the fair value of derivative instruments due
to changes in realized prices that do not match the changes in the hedge price) are recognized in
gain (loss) on ineffective portion of hedges as they occur. While the cash flow hedge contract is
open, the ineffective gain or loss may increase or decrease until settlement of the contract. As
of September 30, 2006, we had designated as cash flow hedges of 750 Bbls per day of production from
October 1, 2006 through December 20, 2006. All other commodity derivative trades are accounted for
by mark-to-market accounting whereby changes in fair value are charged to earnings. Changes in
the fair value of derivatives are recorded in our Consolidated Statements of Operations as these
changes occur in the Other income (expense), net section of this statement. To the extent these
trades relate to production in 2006 and beyond and oil prices increase, we report a loss currently,
but if there is no further change in prices, our net earnings will be correspondingly higher (than
if there had been no price increase) when the production is sold.
Under cash flow hedge accounting for interest rates, the quarterly change in the fair value of
the derivative is recorded in stockholders equity as other comprehensive income (loss). The gain
or loss is transferred, on a contract by contract basis, to interest expense as the interest
accrues. Ineffective portions of cash flow hedges are recognized in other expense as they occur.
As of September 30, 2006, the floating interest rate on $10.0 million of the bank borrowings in
2006 was hedged. All other interest rate swaps that have been entered into are accounted for by
mark-to-market accounting as prescribed by SFAS 133.
We are exposed to credit risk in the event of nonperformance by the counterparty in our
derivative trade instruments. However, we periodically assess the creditworthiness of the
counterparty to mitigate this credit risk.
Certain of our commodity price risk management arrangements have required us to deliver cash
collateral or other assurances of performance to the counterparties in the event that our payment
obligations with respect to our commodity price risk management transactions exceed certain levels.
Contractual Obligations, Commitments and Off-Balance Sheet Arrangements
We have contractual obligations and commitments that may affect our financial position.
However, based on our assessment of the provisions and circumstances of our contractual obligation
and commitments, we do not feel there would be an adverse effect on our consolidated results of
operations, financial condition or liquidity.
(27)
The following table is a summary of significant contractual obligations as of September 30, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Obligation Due in Period |
|
|
|
Three |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
months |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ending |
|
|
Periods ended December 31, |
|
|
After |
|
|
|
|
Contractual Cash Obligations |
|
2006 |
|
|
2007 |
|
|
2008 |
|
|
2009 |
|
|
2010 |
|
|
5 years |
|
|
Total |
|
|
|
(in thousands) |
|
Revolving
Credit Facility (secured) (1) |
|
$ |
1,868 |
|
|
$ |
7,411 |
|
|
$ |
7,431 |
|
|
$ |
7,411 |
|
|
$ |
103,172 |
|
|
$ |
|
|
|
$ |
127,293 |
|
Second Lien
Term Loan Agreement (2) |
|
|
1,252 |
|
|
|
4,969 |
|
|
|
4,982 |
|
|
|
4,969 |
|
|
|
54,342 |
|
|
|
|
|
|
|
70,514 |
|
Office Lease (Dinero Plaza) |
|
|
50 |
|
|
|
204 |
|
|
|
210 |
|
|
|
216 |
|
|
|
36 |
|
|
|
|
|
|
|
716 |
|
Andrews and Snyder Field Offices (3) |
|
|
6 |
|
|
|
23 |
|
|
|
14 |
|
|
|
14 |
|
|
|
14 |
|
|
|
|
|
|
|
71 |
|
Asset
retirement obligations (4) |
|
|
305 |
|
|
|
83 |
|
|
|
59 |
|
|
|
258 |
|
|
|
576 |
|
|
|
3,344 |
|
|
|
4,625 |
|
Derivative Obligations |
|
|
4,075 |
|
|
|
15,317 |
|
|
|
14,289 |
|
|
|
82 |
|
|
|
(1,547 |
) |
|
|
|
|
|
|
32,216 |
|
Drilling Contract |
|
|
272 |
|
|
|
808 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,080 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
7,828 |
|
|
$ |
28,815 |
|
|
$ |
26,985 |
|
|
$ |
12,950 |
|
|
$ |
156,593 |
|
|
$ |
3,344 |
|
|
$ |
236,515 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Outstanding principal of $97.0 million due October 31, 2010 and estimated interest
obligation calculated using the
weighted average rate at September 30, 2006 of 7.64% |
|
(2) |
|
Outstanding principal of $50.0 million due November 15, 2010 and estimated interest
obligation calculated using the LIBOR
rate at September 30, 2006 of 9.9375% |
|
(3) |
|
The Snyder field office lease remains in effect until the termination of our trade agreement
with a third party working interest
owner in the Diamond M project. The Andrews field office lease expires in December 2007.
The lease cost for these two
office facilities are billed to nonaffiliated third party working interest owners under our
joint operating agreements
with these third parties. |
|
(4) |
|
Assets retirement obligations of oil and natural gas assets, excluding salvage value and
accretion. |
Outlook
The oil and natural gas industry is capital intensive. We make, and anticipate that we will
continue to make, substantial capital expenditures in the exploration for, development and
acquisition of oil and natural gas reserves. Historically, our capital expenditures have been
financed primarily with:
|
|
|
internally generated cash from operations; |
|
|
|
|
proceeds from bank borrowings; and |
|
|
|
|
proceeds from sales of equity securities. |
The continued availability of these capital sources depends upon a number of variables, including:
|
|
|
our proved reserves; |
|
|
|
|
the volumes of oil and natural gas we produce from existing wells; |
|
|
|
|
the prices at which we sell oil and natural gas; and |
|
|
|
|
our ability to acquire, locate and produce new reserves. |
Each of these variables materially affects our borrowing capacity. We may from time to time
seek additional financing in the form of:
|
|
|
increased bank borrowings; |
|
|
|
|
sales of Parallels securities; |
(28)
|
|
|
sales of non-core properties; or |
|
|
|
|
other forms of financing. |
Except for the revolving credit facility we have with our bank lenders, we do not have
agreements for any future financing and there can be no assurance as to the availability or terms
of any such financing.
Inflation
Our drilling costs have escalated and we would expect this trend to continue.
Recent Accounting Pronouncements
In July 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income
Taxesan Interpretation of FASB Statement No. 109 (FIN 48). FIN 48 clarifies the accounting for
uncertainty in income taxes recognized in an entitys financial statements in accordance with SFAS
No. 109, Accounting for Income Taxes, and prescribes a recognition threshold and measurement
attribute for the financial statement recognition and measurement of a tax position taken or
expected to be taken in a tax return. Additionally, FIN 48 provides guidance on subsequent
derecognition of tax positions, financial statement classification, recognition of interest and
penalties, accounting in interim periods, and disclosure and transition requirements. FIN 48 is
effective for the Companys fiscal year beginning February 25, 2007, with early adoption permitted.
The Company is in the process of evaluating FIN 48.
In September 2006, the Securities and Exchange Commission (SEC) issued Staff Accounting
Bulletin No. 108 (SAB 108). Due to diversity in practice among registrants, SAB 108 expresses
SEC staff views regarding the process by which misstatements in financial statements are evaluated
for purposes of determining whether financial statement restatement is necessary, SAB 108 is
effective for fiscal years ending after November 15, 2006, and early application is encouraged.
Parallel does not believe SAB 108 will have a material impact on our financial position or results
from operations.
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair
Value Measurements (FAS 157). This Statement defines fair value as used in numerous accounting
pronouncements, establishes a framework for measuring fair value in generally accepted account
principles and expands disclosure related to the use of fair value measures in financial
statements. The Statement is to be effective for Parallels financial statements issued in 2008;
however, earlier application is encouraged. Parallel is currently evaluating the timing of
adoption and the impact that adoption might have on our financial position or results of
operations.
Critical Accounting Policies
This discussion should be read in conjunction with the financial statements and the
accompanying notes and Managements Discussion and Analysis of Financial Condition and Results of
Operations included in our Annual Report or Form 10-K for the year ended December 31, 2005, filed
with the Securities and Exchange Commission on March 16, 2006.
TRENDS AND PRICES
Changes in oil and natural gas prices significantly affect our revenues, cash flows and
borrowing capacity. Markets for oil and natural gas have historically been, and will continue to
be, volatile. Prices for oil and natural gas typically fluctuate in response to relatively minor
changes in supply and demand, market uncertainty, seasonal, political and other factors beyond our
control. We are unable to accurately predict domestic or worldwide political events or the effects
of other such factors on the prices we receive for our oil and natural gas.
Our capital expenditure budgets are highly dependent on future oil and natural gas prices and
will be consistent with internally generated cash flows.
During fiscal year 2005 the average realized sales price for our oil and natural gas was
$51.57 (unhedged) per BOE. For the nine months ended September 30, 2006, our average realized
price was $49.50 (unhedged) per BOE.
(29)
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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|
the drilling plans and ability to secure drilling rigs to effectuate plans; |
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|
production volumes; |
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|
our business strategy; |
|
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|
market prices; |
|
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|
|
sources of funds necessary to conduct operations and complete acquisitions; |
|
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|
|
development costs; |
|
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|
|
number and location of planned wells; |
|
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|
|
our future commodity price risk management activities; and |
|
|
|
|
our plans and forecasts. |
We have based these forward-looking statements on our current assumptions, expectations and
projections about future events.
We use the words may, will, expect, anticipate, estimate, believe, continue,
intend, plan, budget, present value, future or reserves or other similar words to
identify forward-looking statements. These statements also involve risks and uncertainties that
could cause our actual results or financial condition to materially differ for our expectations.
We believe the assumptions and expectations reflected in these forward-looking statements are
reasonable. However, we cannot give any assurance that our expectations will prove to be correct
or that we will be able to take any actions that are presently planned. All of these statements
involve assumptions of future events and risks and uncertainties. Risks and uncertainties
associated with forward-looking statements include, but are not limited to:
|
|
|
fluctuations in prices of oil and natural gas; |
|
|
|
|
dependent on key personnel; |
|
|
|
|
reliance on technological development and technology development programs; |
|
|
|
|
demand for oil and natural gas; |
|
|
|
|
losses due to potential or future litigation; |
|
|
|
|
future capital requirements and availability of financing; |
|
|
|
|
geological concentration of our reserves; |
|
|
|
|
risks associated with drilling and operating wells; |
|
|
|
|
competition; |
|
|
|
|
general economic conditions; |
|
|
|
|
governmental regulations and liability for environmental matters; |
|
|
|
|
receipt of amounts owed to us by purchasers of our production and counterparties to our hedging contracts; |
(30)
|
|
|
hedging decisions, including whether or not to hedge; |
|
|
|
|
events similar to 911; |
|
|
|
|
actions of third party co-owners of interests in properties in which we also own an interest; and |
|
|
|
|
fluctuations in interest rates and availability of capital. |
For these and other reasons, actual results may differ materially from those projected or
implied. We believe it is important to communicate our expectations of future performance to our
investors. However, events may occur in the future that we are unable to accurately predict, or
over which we have no control. We caution you against putting undue reliance on forward-looking
statements or projecting any future results based on such statements.
Before you invest in our common stock, you should be aware that there are various risks
associated with an investment. We have described some of these risks under Risks Related to Our
Business beginning on page 19 of our Form 10-K for the year ended December 31, 2005.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The following quantitative and qualitative information is provided about market risks and
derivative instruments to which Parallel was a party at September 30, 2006, and from which Parallel
may incur future earnings, gains or losses from changes in market interest rates and oil and
natural gas prices.
Interest Rate Sensitivity as of September 30, 2006
Our only financial instruments sensitive to changes in interest rates are our bank debt and
interest rate swaps. As the interest rate is variable and reflects current market conditions, the
carrying value of our bank debt approximates the fair value. The table below shows principal cash
flows and related weighted average interest rates by expected maturity dates. Weighted average
interest rates were determined using weighted average interest paid and accrued in September, 2006.
You should read Note 3 to the Consolidated Financial Statements for further discussion of our debt
that is sensitive to interest rates.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2007 |
|
2008 |
|
2009 |
|
2010 |
|
Total |
|
|
(in thousands, except interest rates) |
Revolving Facility (secured) |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
97,000 |
|
|
$ |
97,000 |
|
Average interest rate |
|
|
7.64 |
% |
|
|
7.64 |
% |
|
|
7.64 |
% |
|
|
7.64 |
% |
|
|
7.64 |
% |
|
|
|
|
Term Loan (Second Lien) |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
50,000 |
|
|
$ |
50,000 |
|
Average interest rate |
|
|
9.94 |
% |
|
|
9.94 |
% |
|
|
9.94 |
% |
|
|
9.94 |
% |
|
|
9.94 |
% |
|
|
|
|
At September 30, 2006, we had bank loans in the amount of approximately $97.0 million
outstanding on our revolving credit facility at a weighted average interest rate of 7.64% and
approximately $50.0 million outstanding on our term loan at an interest rate of 9.9375%. Under
our revolving credit facility, we may elect an interest rate based upon the agent banks base
lending rate or the LIBOR rate, plus a margin ranging from 2.00% to 2.50% per annum, depending upon
the outstanding principal amount of the loans. The interest rate we are required to pay, including
the applicable margin, may never be less than 5.00%.
As of September 30, 2006, we employed fixed interest rate swap contracts with BNP Paribas,
based on the 90-day LIBOR rates at the time of the contract. These interest rate swaps are treated
as a cash flow hedge as defined in SFAS 133, and are on $10.0 million of our variable rate debt for
all of 2006. We will continue to pay the variable interest rates for this portion of our Bank
Borrowings, but due to the interest rate swaps, we have fixed the rate at 4.05%. Under the terms
of these contracts, in periods during which the fixed interest rate stated in the agreement exceeds
the variable rate (which is based on the 90-day LIBOR rate), we pay to the counterparty an amount
determined by applying this excess fixed rate to the notional amount of the contract. In periods
when the variable rate exceeds the fixed rate stated in the respective swap contract, the
counterparty pays an amount to us determined by applying the excess of the variable rate over the
stated fixed rate. As of September 30, 2006, the fair market value of these interest rate swaps was
a gain of $0.03 million.
(31)
As of September 30, 2006, we had also employed additional fixed interest rate swap contracts
with BNP Paribas and Citibank, N.A. based on the 90-day LIBOR rates at the time of the contracts.
However, these contracts are accounted for by mark-to-market accounting as prescribed in SFAS
133. Nonetheless, we view these contracts as additional protection against future interest rate
volatility.
A recap for the period of time, notional amounts, fixed interest rates, and fair market value
of these contracts at September 30, 2006 follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional |
|
|
|
|
|
|
Fair |
|
Period of Time |
|
Amounts |
|
|
Fixed Interest Rates |
|
|
Market Value |
|
|
|
($ in millions) |
|
|
|
|
|
|
($ in thousands) |
|
October 1, 2006 thru December 31, 2006 (1) |
|
$ |
10 |
|
|
|
4.05 |
% |
|
$ |
30 |
|
October 1, 2006 thru December 31, 2006 |
|
$ |
50 |
|
|
|
4.41 |
% |
|
|
307 |
|
January 1, 2007 thru December 31, 2007 |
|
$ |
100 |
|
|
|
4.62 |
% |
|
|
469 |
|
January 1, 2008 thru December 31, 2008 |
|
$ |
100 |
|
|
|
4.86 |
% |
|
|
(119 |
) |
January 1, 2009 thru December 31, 2009 |
|
$ |
50 |
|
|
|
5.06 |
% |
|
|
(82 |
) |
January 1, 2010 thru October 31, 2010 |
|
$ |
50 |
|
|
|
5.15 |
% |
|
|
(59 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
$ |
546 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Designated as cash flow hedge. |
Commodity Price Sensitivity as of September 30, 2006
Our major market risk exposure is in the pricing applicable to our oil and natural gas
production. Market risk refers to the risk of loss from adverse changes in oil and natural gas
prices. Realized pricing is primarily driven by the prevailing domestic price for crude oil and
spot prices applicable to the region in which we produce natural gas. Historically, prices
received for oil and natural gas production have been volatile and unpredictable. We expect
pricing volatility to continue. Oil prices ranged from a low of $36.43 per barrel to a high of
$65.63 per barrel during 2005. Natural gas prices we received during 2005 ranged from a low of
$2.22 per Mcf to a high of $15.43 per Mcf. During 2006 oil prices ranged from a low of $51.65 to a
high of $73.03. Natural gas prices we received during 2006 ranged from a low of $1.00 per Mcf to a
high of $15.11 per Mcf. A significant decline in the prices of oil or natural gas could have a
material adverse effect on our financial condition and results of operations.
We employ various derivative instruments in order to minimize our exposure to the
aforementioned commodity price volatility. As of September 30, 2006, we had employed costless
collars, collars, and swaps in order to protect against this price volatility. Although all of the
contracts that we have entered into are viewed as protection against this price volatility, all but
two of these contracts are accounted for by the mark-to-market accounting method as prescribed in
SFAS 133.
As of September 30, 2006, we had commodity swap contracts designated as cash flow hedges
totaling 750 Bbls per day from October 1, 2006 through December 20, 2006 at a NYMEX swap price of
$23.04 per Bbl.
A description of our active commodity derivative contracts as of September 30, 2006 follows:
Put Options. In 2005 we purchased put options or floors on volumes of 3,000 MMBtu
per day for a total of 642,000 MMBtu during the seven month period from April 1, 2006 through
October 31, 2006 at an average floor price of $7.17 per MMBtu for a total consideration of
approximately $0.23 million. The remaining put options volumes of 93,000 MMBtu have a fair market
value of $0.3 million as of September 30, 2006.
Collars. Collars are contracts which combine both a put option or floor and a call
option or ceiling. These contracts may or may not involve payment or receipt of cash at
inception, depending on the ceiling and floor pricing.
(32)
A summary of our collar positions at September 30, 2006 is as follows:
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|
M M Btu |
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|
Houston Ship |
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|
|
|
|
|
|
Fair |
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|
|
Barrels of |
|
|
NyMex Oil Prices |
|
|
of Natural |
|
|
Channel Gas Prices |
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|
WAHA Gas Prices |
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|
Market |
|
Period of Time |
|
Oil |
|
|
Floor |
|
|
Cap |
|
|
Gas |
|
|
Floor |
|
|
Cap |
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|
Floor |
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|
Cap |
|
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Value |
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($ in |
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|
thousands) |
|
October 1, 2006 thru
December 31, 2006 |
|
|
99,000 |
|
|
$ |
53.12 |
|
|
$ |
80.87 |
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(246 |
) |
October 1, 2006 thru
October 31, 2006 |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
|
62,000 |
|
|
$ |
7.50 |
|
|
$ |
13.90 |
|
|
$ |
|
|
|
$ |
|
|
|
|
217 |
|
October 1, 2006 thru
October 31, 2006 |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
|
31,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
9.00 |
|
|
$ |
14.55 |
|
|
|
164 |
|
January 1, 2007 thru
December 31, 2007 |
|
|
292,000 |
|
|
$ |
55.63 |
|
|
$ |
84.88 |
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
146 |
|
April 1, 2007 thru
October 31, 2007 |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
|
214,000 |
|
|
$ |
6.00 |
|
|
$ |
11.05 |
|
|
$ |
|
|
|
$ |
|
|
|
|
51 |
|
January 1, 2008 thru
December 31, 2008 |
|
|
237,900 |
|
|
$ |
60.38 |
|
|
$ |
81.08 |
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
236 |
|
January 1, 2009 thru
December 31, 2009 |
|
|
620,500 |
|
|
$ |
63.53 |
|
|
$ |
80.21 |
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
1,583 |
|
January 1, 2010 thru
October 31, 2010 |
|
|
486,400 |
|
|
$ |
63.44 |
|
|
$ |
78.26 |
|
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
1,492 |
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
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|
|
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|
Total Fair Market Value |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
3,643 |
|
|
|
|
|
|
|
|
|
|
|
|
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|
Commodity Swaps. Generally, swaps are an agreement to buy or sell a specified
commodity for delivery in the future, at an agreed fixed price. Swap transactions convert a
floating or market price into a fixed price. For any particular swap transaction, the counterparty
is required to make a payment to the Company if the reference price for any settlement period is
less than the swap or fixed price for such contract, and the Company is required to make a payment
to the counterparty if the reference price for any settlement period is greater than the swap or
fixed price for such contract.
We have entered into oil swap contracts with BNP Paribas. A recap for the period of time, number
of Nymex Oil Fair Market barrels, swap prices and fair market values as of September 30, 2006 for these swaps
follows:
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|
|
|
|
|
|
|
|
|
Period of Time |
|
Barrels of Oil |
|
|
Nymex Oil Swap Price |
|
|
Fair
Market Value |
|
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
|
October 1, 2006 thru December 20, 2006 (1) |
|
|
60,750 |
|
|
$ |
23.04 |
|
|
$ |
(2,476 |
) |
October 1, 2006 thru December 31, 2006 |
|
|
46,000 |
|
|
$ |
36.35 |
|
|
|
(1,275 |
) |
January 1, 2007 thru December 31, 2007 |
|
|
474,500 |
|
|
$ |
34.36 |
|
|
|
(15,315 |
) |
January 1, 2008 thru December 31, 2008 |
|
|
439,200 |
|
|
$ |
33.37 |
|
|
|
(14,195 |
) |
|
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|
|
|
|
|
|
|
|
|
|
Total fair market value |
|
|
|
|
|
|
|
|
|
$ |
(33,261 |
) |
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|
(1) |
|
Designated as a cash flow hedge. |
(33)
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 was evaluated by our management, with the participation
of our Chief Executive Officer, Larry C. Oldham (principal executive officer), and our Chief
Financial Officer, Steven D. Foster (principal financial officer), in accordance with Rules of the
Securities Exchange Act of 1934. Based on that evaluation, Mr. Oldham and Mr. Foster have
concluded that our disclosure controls and procedures were effective as of September 30, 2006 to
provide reasonable assurance that information required to be disclosed in our reports filed or
submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported
within the time periods specified in the SECs rules and forms.
PART II OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
On December 30, 2005, we were named as a defendant in a lawsuit filed in the 352nd Judicial
District Court of Tarrant County, Texas, Cause No. 352-215616-05, AFE Oil and Gas, L.L.C. (aka AFE
Oil and Gas, LLC) v. Premium Resources II, L.P., Premium Resources, Inc., Danay Covert, Nick
Morris, William D. Middleton, Dale Resources, L.L.C., and Parallel Petroleum, Inc.
In this suit, the plaintiff alleges breach of fiduciary duty, fraud and conspiracy to defraud,
breach of contract, constructive trust, suit to remove cloud from title, declaratory judgment,
alter ego, and statutory fraud and seeks recovery of an unspecified amount of actual damages,
special damages, consequential damages, exemplary damages, attorneys fees, pre-judgment and
post-judgment interest and costs. Generally, the plaintiff alleges that it owns a 5.5% overriding
royalty interest in certain oil and gas properties known as the Square Top LP and the West Fork
LP leases located in Tarrant County, Texas. The plaintiff alleges that the defendants (other than
Dale Resources and Parallel) wrongfully and intentionally allowed these original oil and gas leases
to terminate; causing the termination of plaintiffs overriding royalty interest in each lease. The
plaintiff further alleges that the defendants (other than Dale Resources and Parallel) failed to
drill wells necessary to maintain the original leases in force and that after the original leases
were allowed to terminate, the defendants (other than Dale Resources and Parallel) then acquired
new oil and gas leases covering these same oil and gas properties, which were subsequently assigned
to Dale Resources. Thereafter, Dale Resources allegedly assigned a portion of these new leases to
Parallel.
In addition to seeking unspecified monetary damages, the plaintiff also seeks to impose a
constructive trust for its benefit on the new oil and natural gas leases and seeks a judicial
declaration that either (1) the plaintiff is the owner of an overriding royalty interest in the new
leases or that (2) the original leases and plaintiffs interest in the original leases are still in
effect. The plaintiff also claims that the new leases constitute a cloud on plaintiffs title and
seeks to have that cloud removed. Based on our present understanding of this case, we believe that
we have substantial defenses to the plaintiffs claims and intend to vigorously assert these
defenses. However, if the plaintiff is awarded an interest in the new leases, we could potentially
become liable for the payment to plaintiff of the portion of production proceeds attributable to
plaintiffs interest received by us. On the other hand, if the plaintiff prevails on its claim that
the original leases are still in effect, our interest in the new leases could become subject to
forfeiture. Based on the information known to date, we have not established a reserve for this
matter.
We are not aware of any other threatened litigation and we have not been a party to any
bankruptcy, receivership, reorganization, adjustment or similar proceeding.
ITEM 1A. RISK FACTORS
There have been no material changes from the risk factors as previously disclosed in our Form
10-K Report for the fiscal year ended December 31, 2005.
(34)
ITEM
6. EXHIBITS
The following exhibits are filed herewith or incorporated by reference, as indicated:
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No. |
|
Description of Exhibit |
|
|
|
3.1
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|
Certificate of Incorporation of Registrant (Incorporated by reference to Exhibit 3.1 to Form
10-Q of the Registrant for the fiscal quarter ended June 30, 2004) |
|
|
|
3.2
|
|
Bylaws of Registrant (Incorporated by reference to Exhibit 3 of the Registrants Form 8-K,
dated October 9, 2000, as filed with the Securities and Exchange Commission on October 10,
2000) |
|
|
|
3.3
|
|
Certificate of Formation of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.3 of
the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004) |
|
|
|
3.4
|
|
Limited Liability Company Agreement of Parallel, L.L.C. (Incorporated by reference to Exhibit
No. 3.4 of the Registrants Statement on Form S-3, No. 333-119725 filed on October 13, 2004) |
|
|
|
3.5
|
|
Certificate of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit
No. 3.5 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on
October 13, 2004) |
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|
3.6
|
|
Agreement of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No.
3.6 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October
13, 2004) |
|
|
|
4.1
|
|
Certificate of Designations, Preferences and Rights of Serial Preferred Stock 6%
Convertible Preferred Stock (Incorporated by reference to Exhibit 4.1 of Form 10-Q of the
Registrant for the fiscal quarter ended June 30, 2004) |
|
|
|
4.2
|
|
Certificate of Designation, Preferences and Rights of Series A Preferred Stock (Incorporated
by reference to Exhibit 4.2 of Form 10-K of the Registrant for the fiscal year ended December
31, 2000) |
|
|
|
4.3
|
|
Rights Agreement, dated as of October 5, 2000, between the Registrant and Computershare Trust
Company, Inc., as Rights Agent (Incorporated by reference to Exhibit 4.3 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2000) |
|
|
|
4.4
|
|
Form of Indenture relating to senior debt securities of the Registrant (Incorporated by
reference to Exhibit No. 4.4 of the Registrants Statement on Form S-3, No. 333-119725 filed
on October 13, 2004) |
|
|
|
4.5
|
|
Form of Indenture relating to subordinated debt securities of the Registrant (Incorporated by
reference to Exhibit No. 4.5 of the Registrants Registration Statement on Form S-3, No.
333-119725 filed on October 13, 2004) |
|
|
|
4.6
|
|
Form of common stock certificate of the Registrant (Incorporated by reference to Exhibit No.
4.6 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October
13, 2004) |
|
|
|
4.7
|
|
Warrant Purchase Agreement, dated November 20, 2001, between the Registrant and Stonington
Corporation (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant for the
fiscal year ended December 31, 2004) |
|
|
|
4.8
|
|
Warrant Purchase Agreement, dated December 23, 2003, between the Registrant and Stonington
Corporation (Incorporated by reference to Exhibit 4.8 of Form 10-K of the Registrant for the
fiscal year ended December 31, 2004) |
|
|
|
|
|
Executive Compensation Plans and Arrangements (Exhibit No.s 10.1 through 10.8): |
|
|
|
10.1
|
|
1992 Stock Option Plan (Incorporated by reference to Exhibit 10.1 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2004) |
|
|
|
10.2
|
|
Merrill Lynch, Pierce, Fenner & Smith Incorporated Prototype Simplified Employee Pension Plan
(Incorporated by reference to Exhibit 10.6 of the Registrants Form 10-K for the fiscal year
ended December 31, 1995) |
(35)
|
|
|
No. |
|
Description of Exhibit |
|
|
|
10.3
|
|
Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.3 of the
Registrants Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2005) |
|
|
|
10.4
|
|
1998 Stock Option Plan (Incorporated by reference to Exhibit 10.7 of Form 10-K of the
Registrant for the fiscal year ended December 31, 1998) |
|
|
|
10.5
|
|
Form of Incentive Award Agreements, dated December 12, 2001, between the Registrant and
Thomas R. Cambridge, Larry C. Oldham, Eric A. Bayley and John S. Rutherford granting 2,394
Unit Equivalent Rights to Mr. Cambridge; 9,564 Unit Equivalent Rights to Mr. Oldham; 2,869
Unit Equivalent Rights to Mr. Bayley; and 7,173 Unit Equivalent Rights to Mr. Rutherford
(Incorporated by reference to Exhibit 10.8 of Form 10-K of the Registrant for the fiscal year
ended December 31, 2001) |
|
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|
10.6
|
|
2001 Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.7 of
the Registrants Form 10-Q Report for the fiscal quarter ended March 31, 2004) |
|
|
|
10.7
|
|
2004 Non-Employee Director Stock Grant Plan (Incorporated by reference to Exhibit 10.1 of the
Registrants Form 8-K Report dated September 22, 2004) |
|
|
|
10.8
|
|
Incentive and Retention Plan (Incorporated by reference to Exhibit 10.1 of the Registrants
Form 8-K Report dated September 23, 2004 and filed with the Securities and Exchange Commission
on September 29, 2004) |
|
|
|
10.9
|
|
Certificate of Formation of First Permian, L.L.C. (Incorporated by reference to Exhibit 10.1
of the Registrants Form 8-K Report dated June 30, 1999) |
|
|
|
10.10
|
|
Limited Liability Company Agreement of First Permian, L.L.C. (Incorporated by reference to
Exhibit 10.2 of the Registrants Form 8-K Report dated June 30, 1999) |
|
|
|
10.11
|
|
Amended and Restated Limited Liability Company Agreement of First Permian, L.L.C. dated as
of May 31, 2000 (Incorporated by reference to Exhibit 10.16 of Form 10-K of the Registrant for
the fiscal year ended December 31, 2000) |
|
|
|
10.12
|
|
Credit Agreement, dated June 30, 1999, by and among First Permian, L.L.C., Parallel
Petroleum Corporation, Baytech, Inc., and Bank One, Texas, N.A. (Incorporated by reference to
Exhibit 10.6 of the Registrants Form 8-K Report dated June 30, 1999) |
|
|
|
10.13
|
|
Limited Guaranty, dated June 30, 1999, by and among First Permian, L.L.C., parallel
Petroleum Corporation and Bank One, Texas, N.A. (Incorporated by reference to Exhibit 10.7 of
the Registrants Form 8-K Report dated June 30, 1999) |
|
|
|
10.14
|
|
Second Restated Credit Agreement, dated October 25, 2000, among First Permian, L.L.C., Bank
One, Texas, N.A., and Bank One Capital Markets, Inc. (Incorporated by reference to Exhibit
10.22 of Form 10-K of the Registrant for the fiscal year ended December 31, 2000) |
|
|
|
10.15
|
|
Loan Agreement, dated as of January 25, 2002, between the Registrant and First American
Bank, SSB (Incorporated by reference to Exhibit 10.25 of Form 10-K of the Registrant for the
fiscal year ended December 31, 2001) |
|
|
|
10.16
|
|
Purchase and Sale Agreement, dated as of November 27, 2002, among JMC Exploration, Inc.,
Arkoma Star L.L.C., Parallel, L.P. and Texland Petroleum, Inc. (Incorporated by reference to
Exhibit 10.1 of Form 8-K of the Registrant, dated December 20, 2002) |
|
|
|
10.17
|
|
First Amended and Restated Credit Agreement, dated December 20, 2002, by and among Parallel
Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, Western
National Bank and BNP Paribas (Incorporated by reference to Exhibit 10.2 of Form 8-K of the
Registrant, dated December 20, 2002) |
|
|
|
10.18
|
|
Guaranty dated December 20, 2002, between Parallel, L.L.C. and First American Bank, SSB, as
Agent (Incorporated by reference to Exhibit 10.3 of Form 8-K of the Registrant, dated December
20, 2002) |
|
|
|
10.19
|
|
First Amendment to First Amended and Restated Credit Agreement, dated as of September 12,
2003, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First
American Bank, SSB, Western National Bank, and BNP Paribas (Incorporated by reference to
Exhibit 10.29 of Form 10-Q of the Registrant for the quarter ended September 30, 2003) |
(36)
|
|
|
No. |
|
Description of Exhibit |
|
|
|
10.20
|
|
Second Amendment and Restated Credit Agreement, dated September 27, 2004, by and among
Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB,
BNP Paribas, Citibank, F.S.B. and
Western National Bank (Incorporated by reference to Exhibit 10.1 of the Registrants Form
8-K Report dated September 27, 2004 and filed with the Securities and Exchange Commission on
October 1, 2004) |
|
|
|
10.21
|
|
Agreement of Limited Partnership of West Fork Pipeline Company LP (Incorporated by reference
to Exhibit 10.21 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004) |
|
|
|
10.22
|
|
First Amendment to Second Amended and Restated Credit Agreement, dated as of December 27,
2004, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First
American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by
reference to Exhibit 10.1 of the Registrants Form 8-K Report dated December 30, 2004 and
filed with the Securities and Exchange Commission on December 30, 2004) |
|
|
|
10.23
|
|
Second Amendment to Second Amended and Restated Credit Agreement, dated as of April 1, 2005,
by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American
Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference
to Exhibit 10.1 of the Registrants Form 8-K Report dated April 4, 2005 and filed with the
Securities and Exchange Commission on April 8, 2005) |
|
|
|
10.24
|
|
Third Amendment to Second Amended and Restated Credit Agreement (Incorporated by reference
to Exhibit 10.1 of the Registrants Form 8-K Report dated October 4, 2005 and filed with the
Securities and Exchange Commission on October 20, 2005) |
|
|
|
10.25
|
|
Purchase and Sale Agreement, dated as of October 14, 1005, among Parallel, L.P., Lynx
Production Company, Inc., Elton Resources, Inc., Cascade Energy Corporation, Chelsea Energy,
Inc., William P. Sutter, Trustee, William P. Sutter Trust, J. Leroy Bell, E. L. Brahaney,
Brent Beck, Cavic Interests, LLC and Stanley Talbott (Incorporated by reference to Exhibit
10.2 of the Registrants Form 8-K Report dated October 14, 2005 and filed with the Securities
and Exchange Commission on October 20, 2005) |
|
|
|
10.26
|
|
Ancillary Agreement to Purchase and Sale Agreement, dated October 14, 2005, between
Parallel, L.P. and Lynx Production Company, Inc. (Incorporated by reference to Exhibit 10.3 of
the Registrants Form 8-K Report dated October 14, 2005 and filed with the Securities and
Exchange Commission on October 20, 2005) |
|
|
|
10.27
|
|
Guarantee of Parallel, L.P., dated October 13, 2004 (Incorporated by reference to Exhibit
10.4 of the Registrants Form 8-K Report dated October 14, 2005 and filed with the Securities
and Exchange Commission on October 20, 2005) |
|
|
|
10.28
|
|
ISDA Master Agreement, dated as of October 13, 2005, between Parallel, L.P. and Citibank,
N.A. (Incorporated by reference to Exhibit 10.5 of the Registrants Form 8-K Report dated
October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005) |
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10.29
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Third Amended and Restated Credit Agreement, dated as of December 23, 2005, among Parallel
Petroleum Corporation, Parallel, L.P., Parallel, L.L.C. and Citibank Texas, N.A., BNP Paribas,
CitiBank F.S.B., Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland and
Fortis Capital Corp. (Incorporated by reference to Exhibit No. 10.1 of the Registrants Form
8-K Report, dated December 23, 2005, as filed with the Securities and Exchange Commission on
December 30, 2005) |
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10.30
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Second Lien Term Loan Agreement, dated November 15, 2005, among Parallel Petroleum
Corporation, Parallel, L.P., BNP Paribas and Citibank Texas, N.A. (Incorporated by reference
to Exhibit No. 10.4 of the Registrants Form 8-K Report, dated November 15, 2005, as filed
with the Securities and Exchange Commission on November 21, 2005) |
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10.31
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Intercreditor and Subordination Agreement, dated November 15, 2005, among Citibank Texas,
N.A., BNP Paribas, Parallel Petroleum Corporation, Parallel, L.P. and Parallel, L.L.C.
(Incorporated by reference to Exhibit No. 10.5 of the Registrants Form 8-K Report, dated
November 15, 2005, as filed with the Securities and Exchange Commission on November 21, 2005) |
(37)
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No. |
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Description of Exhibit |
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14
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Code of Ethics (Incorporated by reference to Exhibit No. 14 of the Registrants Form 10-K
Report for the fiscal year ended December 31, 2003 and filed with the Securities and Exchange
Commission on March 22, 2004) |
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21
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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) |
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*31.1
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Certification of Principal Executive Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 302 of the Sarbanes -
Oxley Act of 2002. |
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*31.2
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Certification of Principal Financial Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 302 of the Sarbanes -
Oxley Act of 2002. |
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*32.1
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Certification of Chief Executive Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the Sarbanes -
Oxley Act of 2002. |
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*32.2
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Certification of Chief Financial Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the Sarbanes -
Oxley Act of 2002. |
(38)
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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PARALLEL PETROLEUM CORPORATION |
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BY:
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/s/ Larry C. Oldham
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Date: November 8, 2006 |
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Larry C. Oldham |
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President and Chief Executive Officer |
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Date: November 8, 2006
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BY:
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/s/ Steven D. Foster
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Steven D. Foster, |
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Chief Financial Officer |
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INDEX TO EXHIBITS
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No. |
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Description of Exhibit |
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3.1
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Certificate of Incorporation of Registrant (Incorporated by reference to Exhibit 3.1 to Form
10-Q of the Registrant for the fiscal quarter ended June 30, 2004) |
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3.2
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Bylaws of Registrant (Incorporated by reference to Exhibit 3 of the Registrants Form 8-K,
dated October 9, 2000, as filed with the Securities and Exchange Commission on October 10,
2000) |
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3.3
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Certificate of Formation of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.3 of
the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004) |
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3.4
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Limited Liability Company Agreement of Parallel, L.L.C. (Incorporated by reference to Exhibit
No. 3.4 of the Registrants Statement on Form S-3, No. 333-119725 filed on October 13, 2004) |
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3.5
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Certificate of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit
No. 3.5 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on
October 13, 2004) |
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3.6
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Agreement of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No.
3.6 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October
13, 2004) |
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4.1
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Certificate of Designations, Preferences and Rights of Serial Preferred Stock 6%
Convertible Preferred Stock (Incorporated by reference to Exhibit 4.1 of Form 10-Q of the
Registrant for the fiscal quarter ended June 30, 2004) |
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4.2
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Certificate of 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) |
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4.3
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Rights Agreement, dated as of October 5, 2000, between the Registrant and Computershare Trust
Company, Inc., as Rights Agent (Incorporated by reference to Exhibit 4.3 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2000) |
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4.4
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Form of Indenture relating to senior debt securities of the Registrant (Incorporated by
reference to Exhibit No. 4.4 of the Registrants Statement on Form S-3, No. 333-119725 filed
on October 13, 2004) |
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4.5
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Form of Indenture relating to subordinated debt securities of the Registrant (Incorporated by
reference to Exhibit No. 4.5 of the Registrants Registration Statement on Form S-3, No.
333-119725 filed on October 13, 2004) |
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4.6
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Form of common stock certificate of the Registrant (Incorporated by reference to Exhibit No.
4.6 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October
13, 2004) |
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4.7
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Warrant Purchase Agreement, dated November 20, 2001, between the Registrant and Stonington
Corporation (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant for the
fiscal year ended December 31, 2004) |
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4.8
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Warrant Purchase Agreement, dated December 23, 2003, between the Registrant and Stonington
Corporation (Incorporated by reference to Exhibit 4.8 of Form 10-K of the Registrant for the
fiscal year ended December 31, 2004) |
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Executive Compensation Plans and Arrangements (Exhibit No.s 10.1 through 10.8): |
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10.1
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1992 Stock Option Plan (Incorporated by reference to Exhibit 10.1 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2004) |
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10.2
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Merrill Lynch, Pierce, Fenner & Smith Incorporated Prototype Simplified Employee Pension Plan
(Incorporated by reference to Exhibit 10.6 of the Registrants Form 10-K for the fiscal year
ended December 31, 1995) |
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No. |
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Description of Exhibit |
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10.3
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Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.3 of the
Registrants Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2005) |
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10.4
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1998 Stock Option Plan (Incorporated by reference to Exhibit 10.7 of Form 10-K of the
Registrant for the fiscal year ended December 31, 1998) |
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10.5
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Form of Incentive Award Agreements, dated December 12, 2001, between the Registrant and
Thomas R. Cambridge, Larry C. Oldham, Eric A. Bayley and John S. Rutherford granting 2,394
Unit Equivalent Rights to Mr. Cambridge; 9,564 Unit Equivalent Rights to Mr. Oldham; 2,869
Unit Equivalent Rights to Mr. Bayley; and 7,173 Unit Equivalent Rights to Mr. Rutherford
(Incorporated by reference to Exhibit 10.8 of Form 10-K of the Registrant for the fiscal year
ended December 31, 2001) |
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10.6
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2001 Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.7 of
the Registrants Form 10-Q Report for the fiscal quarter ended March 31, 2004) |
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10.7
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2004 Non-Employee Director Stock Grant Plan (Incorporated by reference to Exhibit 10.1 of the
Registrants Form 8-K Report dated September 22, 2004) |
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10.8
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Incentive and Retention Plan (Incorporated by reference to Exhibit 10.1 of the Registrants
Form 8-K Report dated September 23, 2004 and filed with the Securities and Exchange Commission
on September 29, 2004) |
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10.9
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Certificate of Formation of First Permian, L.L.C. (Incorporated by reference to Exhibit 10.1
of the Registrants Form 8-K Report dated June 30, 1999) |
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10.10
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Limited Liability Company Agreement of First Permian, L.L.C. (Incorporated by reference to
Exhibit 10.2 of the Registrants Form 8-K Report dated June 30, 1999) |
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10.11
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Amended and Restated Limited Liability Company Agreement of First Permian, L.L.C. dated as
of May 31, 2000 (Incorporated by reference to Exhibit 10.16 of Form 10-K of the Registrant for
the fiscal year ended December 31, 2000) |
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10.12
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Credit Agreement, dated June 30, 1999, by and among First Permian, L.L.C., Parallel
Petroleum Corporation, Baytech, Inc., and Bank One, Texas, N.A. (Incorporated by reference to
Exhibit 10.6 of the Registrants Form 8-K Report dated June 30, 1999) |
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10.13
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Limited Guaranty, dated June 30, 1999, by and among First Permian, L.L.C., parallel
Petroleum Corporation and Bank One, Texas, N.A. (Incorporated by reference to Exhibit 10.7 of
the Registrants Form 8-K Report dated June 30, 1999) |
10.14
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Second Restated Credit Agreement, dated October 25, 2000, among First Permian, L.L.C., Bank |
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One, Texas, N.A., and Bank One Capital Markets, Inc. (Incorporated by reference to Exhibit
10.22 of Form 10-K of the Registrant for the fiscal year ended December 31, 2000) |
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10.15
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Loan Agreement, dated as of January 25, 2002, between the Registrant and First American
Bank, SSB (Incorporated by reference to Exhibit 10.25 of Form 10-K of the Registrant for the
fiscal year ended December 31, 2001) |
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10.16
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Purchase and Sale Agreement, dated as of November 27, 2002, among JMC Exploration, Inc.,
Arkoma Star L.L.C., Parallel, L.P. and Texland Petroleum, Inc. (Incorporated by reference to
Exhibit 10.1 of Form 8-K of the Registrant, dated December 20, 2002) |
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10.17
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First Amended and Restated Credit Agreement, dated December 20, 2002, by and among Parallel
Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB, Western
National Bank and BNP Paribas (Incorporated by reference to Exhibit 10.2 of Form 8-K of the
Registrant, dated December 20, 2002) |
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10.18
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Guaranty dated December 20, 2002, between Parallel, L.L.C. and First American Bank, SSB, as
Agent (Incorporated by reference to Exhibit 10.3 of Form 8-K of the Registrant, dated December
20, 2002) |
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No. |
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Description of Exhibit |
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10.19
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First Amendment to First Amended and Restated Credit Agreement, dated as of September 12,
2003, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First
American Bank, SSB, Western National Bank, and BNP Paribas (Incorporated by reference to
Exhibit 10.29 of Form 10-Q of the Registrant for the quarter ended September 30, 2003) |
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10.20
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Second Amendment and Restated Credit Agreement, dated September 27, 2004, by and among
Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American Bank, SSB,
BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference to Exhibit
10.1 of the Registrants Form 8-K Report dated September 27, 2004 and filed with the
Securities and Exchange Commission on October 1, 2004) |
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10.21
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Agreement of Limited Partnership of West Fork Pipeline Company LP (Incorporated by reference
to Exhibit 10.21 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004) |
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10.22
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First Amendment to Second Amended and Restated Credit Agreement, dated as of December 27,
2004, by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First
American Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by
reference to Exhibit 10.1 of the Registrants Form 8-K Report dated December 30, 2004 and
filed with the Securities and Exchange Commission on December 30, 2004) |
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10.23
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Second Amendment to Second Amended and Restated Credit Agreement, dated as of April 1, 2005,
by and among Parallel Petroleum Corporation, Parallel, L.P., Parallel, L.L.C., First American
Bank, SSB, BNP Paribas, Citibank, F.S.B. and Western National Bank (Incorporated by reference
to Exhibit 10.1 of the Registrants Form 8-K Report dated April 4, 2005 and filed with the
Securities and Exchange Commission on April 8, 2005) |
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10.24
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Third Amendment to Second Amended and Restated Credit Agreement (Incorporated by reference
to Exhibit 10.1 of the Registrants Form 8-K Report dated October 4, 2005 and filed with the
Securities and Exchange Commission on October 20, 2005) |
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10.25
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Purchase and Sale Agreement, dated as of October 14, 1005, among Parallel, L.P., Lynx
Production Company, Inc., Elton Resources, Inc., Cascade Energy Corporation, Chelsea Energy,
Inc., William P. Sutter, Trustee, William P. Sutter Trust, J. Leroy Bell, E. L. Brahaney,
Brent Beck, Cavic Interests, LLC and Stanley Talbott (Incorporated by reference to Exhibit
10.2 of the Registrants Form 8-K Report dated October 14, 2005 and filed with the Securities
and Exchange Commission on October 20, 2005) |
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10.26
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Ancillary Agreement to Purchase and Sale Agreement, dated October 14, 2005, between
Parallel, L.P. and Lynx Production Company, Inc. (Incorporated by reference to Exhibit 10.3 of
the Registrants Form 8-K Report dated October 14, 2005 and filed with the Securities and
Exchange Commission on October 20, 2005) |
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10.27
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Guarantee of Parallel, L.P., dated October 13, 2004 (Incorporated by reference to Exhibit
10.4 of the Registrants Form 8-K Report dated October 14, 2005 and filed with the Securities
and Exchange Commission on October 20, 2005) |
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10.28
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ISDA Master Agreement, dated as of October 13, 2005, between Parallel, L.P. and Citibank,
N.A. (Incorporated by reference to Exhibit 10.5 of the Registrants Form 8-K Report dated
October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005) |
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10.29
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Third Amended and Restated Credit Agreement, dated as of December 23, 2005, among Parallel
Petroleum Corporation, Parallel, L.P., Parallel, L.L.C. and Citibank Texas, N.A., BNP Paribas,
CitiBank F.S.B., Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland and
Fortis Capital Corp. (Incorporated by reference to Exhibit No. 10.1 of the Registrants Form
8-K Report, dated December 23, 2005, as filed with the Securities and Exchange Commission on
December 30, 2005) |
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10.30
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Second Lien Term Loan Agreement, dated November 15, 2005, among Parallel Petroleum
Corporation, Parallel, L.P., BNP Paribas and Citibank Texas, N.A. (Incorporated by reference
to Exhibit No. 10.4 of the
Registrants Form 8-K Report, dated November 15, 2005, as filed with the Securities and
Exchange Commission on November 21, 2005) |
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No. |
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Description of Exhibit |
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10.31
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Intercreditor and Subordination Agreement, dated November 15, 2005, among Citibank Texas,
N.A., BNP Paribas, Parallel Petroleum Corporation, Parallel, L.P. and Parallel, L.L.C.
(Incorporated by reference to Exhibit No. 10.5 of the Registrants Form 8-K Report, dated
November 15, 2005, as filed with the Securities and Exchange Commission on November 21, 2005) |
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14
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Code of Ethics (Incorporated by reference to Exhibit No. 14 of the Registrants Form 10-K
Report for the fiscal year ended December 31, 2003 and filed with the Securities and Exchange
Commission on March 22, 2004) |
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21
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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) |
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*31.1
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Certification of Principal Executive Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 302 of the Sarbanes -
Oxley Act of 2002. |
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*31.2
|
|
Certification of Principal Financial Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 302 of the Sarbanes -
Oxley Act of 2002. |
|
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*32.1
|
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Certification of Chief Executive Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the Sarbanes -
Oxley Act of 2002. |
|
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*32.2
|
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Certification of Chief Financial Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the Sarbanes -
Oxley Act of 2002. |