e10vq
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark
One)
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2010
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: 001-33801
APPROACH RESOURCES INC.
(Exact name of registrant as specified in its charter)
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Delaware
(State or other jurisdiction of incorporation or organization)
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51-0424817
(I.R.S. Employer Identification No.) |
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One Ridgmar Centre
6500 West Freeway, Suite 800
Fort Worth, Texas
(Address of principal executive offices)
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76116
(Zip Code) |
(817) 989-9000
(Registrants telephone number, including area code)
N/A
(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. þ Yes o No
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). o Yes o No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act.
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Large accelerated filer o
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Accelerated filer þ
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Non-accelerated filer o
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Smaller reporting company o |
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(Do not check if smaller reporting company) |
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). o Yes þ No
The number of shares of the registrants common stock, $0.01 par value, outstanding as of July
31, 2010 was 21,094,629.
PART IFINANCIAL INFORMATION
Item 1. Financial Statements.
APPROACH RESOURCES INC. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED BALANCE SHEETS
(In thousands, except shares and per-share amounts)
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June 30, |
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December 31, |
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2010 |
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2009 |
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ASSETS |
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CURRENT ASSETS: |
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Cash and cash equivalents |
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$ |
293 |
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$ |
2,685 |
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Accounts receivable: |
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Joint interest owners |
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7,180 |
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3,088 |
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Oil and gas sales |
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4,499 |
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4,607 |
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Unrealized gain on commodity derivatives |
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1,839 |
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786 |
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Prepaid expenses and other current assets |
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468 |
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582 |
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Deferred
income taxes current |
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1,605 |
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255 |
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Total current assets |
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15,884 |
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12,003 |
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PROPERTIES AND EQUIPMENT: |
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Oil and gas properties, at cost, using the successful efforts method of accounting |
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416,118 |
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387,792 |
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Furniture, fixtures and equipment |
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1,940 |
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1,540 |
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418,058 |
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389,332 |
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Less accumulated depletion, depreciation and amortization |
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(95,516 |
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(84,849 |
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Net properties and equipment |
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322,542 |
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304,483 |
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OTHER ASSETS |
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2,518 |
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2,440 |
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Total assets |
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$ |
340,944 |
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$ |
318,926 |
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LIABILITIES AND STOCKHOLDERS EQUITY |
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CURRENT LIABILITIES: |
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Advances from nonoperators |
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$ |
315 |
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$ |
2,689 |
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Accounts payable |
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7,939 |
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3,074 |
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Oil and gas sales payable |
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5,142 |
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3,774 |
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Accrued liabilities |
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10,773 |
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10,935 |
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Unrealized loss on commodity derivatives |
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1,524 |
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Total current liabilities |
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24,169 |
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21,996 |
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NONCURRENT LIABILITIES: |
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Long-term debt |
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42,169 |
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32,319 |
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Unrealized loss on commodity derivatives |
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528 |
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1,144 |
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Deferred income taxes |
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42,602 |
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38,374 |
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Asset retirement obligations |
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4,940 |
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4,597 |
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Total liabilities |
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114,408 |
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98,430 |
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COMMITMENTS AND CONTINGENCIES |
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STOCKHOLDERS EQUITY: |
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Preferred
stock, $0.01 par value, 10,000,000 shares authorized, none outstanding |
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Common stock, $0.01 par value, 90,000,000 shares authorized, 21,090,007 and
20,959,285 issued and outstanding, respectively |
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210 |
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209 |
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Additional paid-in capital |
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169,918 |
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168,993 |
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Retained earnings |
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56,638 |
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51,524 |
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Accumulated other comprehensive loss |
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(230 |
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(230 |
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Total stockholders equity |
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226,536 |
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220,496 |
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Total liabilities and stockholders equity |
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$ |
340,944 |
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$ |
318,926 |
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See
accompanying notes to these consolidated financial statements.
1
APPROACH RESOURCES INC. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except shares and per-share amounts)
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Three Months Ended |
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Six Months Ended |
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June 30, |
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June 30, |
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2010 |
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2009 |
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2010 |
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2009 |
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REVENUES: |
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Oil and gas sales |
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$ |
13,155 |
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$ |
9,915 |
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$ |
26,375 |
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$ |
19,980 |
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EXPENSES: |
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Lease operating |
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2,203 |
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1,753 |
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4,043 |
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4,122 |
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Severance and production taxes |
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610 |
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507 |
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1,304 |
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937 |
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Exploration |
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187 |
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1,677 |
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General and administrative |
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2,181 |
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2,230 |
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4,690 |
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5,040 |
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Depletion, depreciation and amortization |
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5,010 |
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6,223 |
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10,845 |
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13,171 |
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Total expenses |
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10,191 |
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10,713 |
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22,559 |
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23,270 |
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OPERATING INCOME (LOSS) |
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2,964 |
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(798 |
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3,816 |
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(3,290 |
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OTHER: |
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Interest expense, net |
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(550 |
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(457 |
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(1,016 |
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(902 |
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Realized gain on commodity derivatives |
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1,768 |
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4,444 |
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1,998 |
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7,625 |
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Unrealized (loss) gain on commodity
derivatives |
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(1,901 |
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(4,320 |
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3,194 |
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(2,175 |
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INCOME
(LOSS) BEFORE INCOME TAX PROVISION (BENEFIT) |
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2,281 |
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(1,131 |
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7,992 |
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1,258 |
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INCOME TAX PROVISION (BENEFIT) |
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730 |
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(460 |
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2,878 |
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1,061 |
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NET INCOME (LOSS) |
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$ |
1,551 |
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$ |
(671 |
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$ |
5,114 |
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$ |
197 |
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EARNINGS (LOSS) PER SHARE: |
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Basic |
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$ |
0.07 |
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$ |
(0.03 |
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$ |
0.24 |
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$ |
0.01 |
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Diluted |
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$ |
0.07 |
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$ |
(0.03 |
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$ |
0.24 |
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$ |
0.01 |
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WEIGHTED AVERAGE SHARES OUTSTANDING: |
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Basic |
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21,059,413 |
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20,827,745 |
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21,027,982 |
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20,794,121 |
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Diluted |
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21,184,331 |
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20,827,745 |
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21,154,647 |
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20,847,284 |
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See
accompanying notes to these consolidated financial statements.
2
APPROACH RESOURCES INC. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
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Six Months Ended |
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June 30, |
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2010 |
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2009 |
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OPERATING ACTIVITIES: |
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Net income |
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$ |
5,114 |
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$ |
197 |
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Adjustments to reconcile net income to cash provided by
operating activities: |
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Depletion, depreciation and amortization |
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10,845 |
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13,171 |
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Unrealized (gain) loss on commodity derivatives |
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(3,194 |
) |
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2,175 |
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Exploration expense |
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1,677 |
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Share-based compensation expense |
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996 |
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1,020 |
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Deferred income taxes |
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2,807 |
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1,419 |
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Changes in operating assets and liabilities: |
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Accounts receivable |
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(3,846 |
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13,713 |
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Prepaid expenses and other assets |
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235 |
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(88 |
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Accounts payable |
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2,492 |
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(10,572 |
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Oil and gas sales payable |
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1,368 |
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(1,617 |
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Accrued liabilities |
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(162 |
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(8,232 |
) |
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Cash provided by operating activities |
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18,332 |
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11,186 |
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INVESTING ACTIVITIES: |
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Additions to oil and gas properties |
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(29,757 |
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(16,324 |
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Additions to other property and equipment, net |
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(477 |
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(221 |
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Cash used in investing activities |
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(30,234 |
) |
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(16,545 |
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FINANCING ACTIVITIES: |
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Borrowings under credit facility, net of debt issuance costs |
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51,162 |
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45,415 |
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Repayment of amounts outstanding under credit facility |
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(41,650 |
) |
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(42,715 |
) |
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Cash provided by financing activities |
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9,512 |
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2,700 |
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CHANGE IN CASH AND CASH EQUIVALENTS |
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(2,390 |
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(2,659 |
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EFFECT OF FOREIGN CURRENCY TRANSLATION ON CASH AND CASH
EQUIVALENTS |
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(2 |
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(1 |
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CASH AND CASH EQUIVALENTS, beginning of period |
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2,685 |
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4,077 |
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CASH AND CASH EQUIVALENTS, end of period |
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$ |
293 |
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$ |
1,417 |
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SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: |
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Cash paid for interest |
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$ |
1,017 |
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$ |
998 |
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See
accompanying notes to these consolidated financial statements.
3
APPROACH RESOURCES INC. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
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Three Months Ended |
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Six Months Ended |
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June 30, |
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June 30, |
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2010 |
|
2009 |
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|
2010 |
|
2009 |
|
Net income (loss) |
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$ |
1,551 |
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$ |
(671 |
) |
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$ |
5,114 |
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$ |
197 |
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Other comprehensive income: |
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Foreign currency translation, net of related income tax |
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5 |
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128 |
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91 |
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Total comprehensive income (loss) |
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$ |
1,556 |
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|
$ |
(543 |
) |
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$ |
5,114 |
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$ |
288 |
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|
See
accompanying notes to these consolidated financial statements.
4
APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2010
(Unaudited)
1. Summary of Significant Accounting Policies
Organization and Nature of Operations
Approach Resources Inc. (the Company, we, us or our) is an independent energy company
engaged in the exploration, development, production and acquisition of natural gas and oil
properties in the United States. We focus on finding and developing natural gas and oil reserves
in tight sands and shale gas. We currently operate or have oil and gas properties or interests in
Texas, Kentucky and New Mexico.
Consolidation, Basis of Presentation and Significant Estimates
The interim consolidated financial statements of the Company are unaudited and contain all
adjustments (consisting primarily of normal recurring accruals) necessary for a fair statement of
the results for the interim periods presented. Results for interim periods are not necessarily
indicative of results to be expected for a full year due in part to the volatility in prices for
crude oil and natural gas, future commodity prices for commodity derivative contracts, global
economic and financial market conditions, interest rates, access to sources of liquidity, estimates
of reserves, drilling risks, geological risks, transportation restrictions, the timing of
acquisitions, product supply and demand, market competition and interruptions of production. You
should read these consolidated interim financial statements in conjunction with the audited
consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for
the year ended December 31, 2009, filed with the Securities and Exchange Commission on March 12,
2010.
The accompanying interim consolidated financial statements have been prepared in accordance
with accounting principles generally accepted in the United States of America and include the
accounts of the Company and its wholly-owned subsidiaries. Intercompany accounts and transactions
are eliminated. In preparing the accompanying financial statements, we have made certain estimates
and assumptions that affect reported amounts in the financial statements and disclosures of
contingencies. Actual results may differ from those estimates. Significant assumptions are required
in the valuation of proved oil and natural gas reserves, which affect the amount at which oil and
natural gas properties are recorded. Significant assumptions are also required in estimating our
accrual of capital expenditures, asset retirement obligations and share-based compensation. It is
at least reasonably possible these estimates could be revised in the near term, and these revisions
could be material. Certain prior year amounts have been reclassified to conform to current year
presentation. These classifications have no impact on the net income reported.
2. Earnings Per Common Share
We report basic earnings per common share, which excludes the effect of potentially dilutive
securities, and diluted earnings per common share, which includes the effect of all potentially
dilutive securities unless their impact is antidilutive. The following are reconciliations of the
numerators and denominators of our basic and diluted earnings per share (dollars in thousands,
except per-share amounts):
5
APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2010
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2010 |
|
2009 |
|
|
2010 |
|
2009 |
|
Income (numerator): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) basic |
|
$ |
1,551 |
|
|
$ |
(671 |
) |
|
$ |
5,114 |
|
|
$ |
197 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares (denominator): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average shares basic |
|
|
21,059,413 |
|
|
|
20,827,745 |
|
|
|
21,027,982 |
|
|
|
20,794,121 |
|
Dilution effect of share-based
compensation, treasury method |
|
|
124,918 |
|
|
|
|
|
|
|
126,665 |
|
|
|
53,163 |
|
|
|
|
|
|
|
|
Weighted
average shares diluted |
|
|
21,184,331 |
|
|
|
20,827,745 |
|
|
|
21,154,647 |
|
|
|
20,847,284 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.07 |
|
|
$ |
(0.03 |
) |
|
$ |
0.24 |
|
|
$ |
0.01 |
|
|
|
|
|
|
|
|
Diluted |
|
$ |
0.07 |
|
|
$ |
(0.03 |
) |
|
$ |
0.24 |
|
|
$ |
0.01 |
|
|
|
|
|
|
|
|
3. Revolving Credit Facility
We have a $200 million revolving credit facility with a borrowing base set at $115 million.
The borrowing base is redetermined semi-annually on or before each April 1 and October 1 based on
our oil and gas reserves. We or the lenders can each request one additional borrowing base
redetermination each calendar year.
The maturity date under our revolving credit facility is July 31, 2012. Borrowings bear
interest based on the agent banks prime rate plus an applicable margin ranging from 1.25% to
2.25%, or the sum of the Eurodollar rate plus an applicable margin ranging from 2.25% to 3.25%.
Margins vary based on the borrowings outstanding compared to the borrowing base. In addition, we
pay an annual commitment of 0.50% of unused borrowings available under our revolving credit
facility.
Effective February 1, 2010, we entered into a seventh amendment to our credit agreement, which
replaced The Frost National Bank as the administrative agent under the Credit Agreement with
JPMorgan Chase Bank, N.A., as successor agent.
Effective May 3, 2010, we entered into an eighth amendment to our credit agreement, which (i)
extended the maturity date of the Credit Agreement by one year to July 31, 2012, (ii) increased the
Companys commodity derivatives limit from 75% to 85% of annual projected production from proved
developed producing oil and gas properties, (iii) reaffirmed the borrowing base and lenders
aggregate commitment of $115 million and (iv) transferred Fortis Capital Corp.s interest in the
Credit Agreement to BNP Paribas.
We had outstanding borrowings of $42.2 million and $32.3 million under our revolving credit
facility at June 30, 2010 and December 31, 2009, respectively. The weighted average interest rate
applicable to our outstanding borrowings was 3.68% and 3.20% as of June 30, 2010, and December 31,
2009, respectively. We also had outstanding unused letters of credit under our revolving credit
facility totaling $350,000 at June 30, 2010, which reduce amounts available for borrowing under our
revolving credit facility.
Loans under our revolving credit facility are secured by first priority liens on substantially
all of our West Texas assets and are guaranteed by our subsidiaries.
6
APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2010
(Unaudited)
Covenants
Our credit agreement contains two principal financial covenants:
|
|
a consolidated modified current ratio covenant that requires us to maintain a ratio
of not less than 1.0 to 1.0 at all times. The consolidated modified current ratio is
calculated by dividing Consolidated Current Assets (as defined in the credit agreement)
by Consolidated Current Liabilities (as defined in the credit agreement). As defined
more specifically in the credit agreement, the consolidated modified current ratio is
calculated as current assets less current unrealized gains on commodity derivatives
plus the available borrowing base at the respective balance sheet date, divided by
current liabilities less current unrealized losses on commodity derivatives at the
respective balance sheet date. |
|
|
a consolidated funded debt to consolidated EBITDAX ratio covenant that requires us
to maintain a ratio of not more than 3.5 to 1.0 at the end of each fiscal quarter. The
consolidated funded debt to consolidated EBITDAX ratio is calculated by dividing
Consolidated Funded Debt (as defined in the credit agreement) by Consolidated EBITDAX
(as defined in the credit agreement). As defined more specifically in the credit
agreement, consolidated EBITDAX is calculated as net income (loss), plus (1)
exploration expense, (2) depletion, depreciation and amortization expense, (3)
share-based compensation expense, (4) unrealized loss on commodity derivatives, (5)
interest expense, (6) income and franchise taxes, and (7) certain other noncash
expenses, less (1) gains or losses from sales or dispositions of assets, (2) unrealized
gain on commodity derivatives and (3) extraordinary or nonrecurring gains. For
purposes of calculating this ratio, consolidated EBITDAX for a fiscal quarter is
annualized pursuant to the credit agreement. |
Our credit agreement also restricts cash dividends and other restricted payments, transactions
with affiliates, incurrence of other debt, consolidations and mergers, the level of operating
leases, assets sales, investments in other entities and liens on properties.
In addition, our credit agreement contains customary events of default that would permit our
lenders to accelerate the debt under our credit agreement if not cured within applicable grace
periods, including, among others, failure to make payments of principal or interest when due,
materially incorrect representations and warranties, failure to make mandatory prepayments in the
event of borrowing base deficiencies, breach of covenants, defaults upon other obligations in
excess of $500,000, events of bankruptcy, the occurrence of one or more unstayed judgments in
excess of $500,000 not covered by an acceptable policy of insurance, failure to pay any obligation
in excess of $500,000 owed under any derivatives transaction or in any amount if the obligation
under the derivatives transaction is secured by collateral under the credit agreement, any event of
default by the Company occurs under any agreement entered into in connection with a derivatives
transaction, liens securing the loans under the credit agreement cease to be in place, a Change in
Control (as defined in the credit agreement) of the Company occurs, and dissolution of the Company.
At June 30, 2010, we were in compliance with all of our covenants and had not committed any
acts of default under the credit agreement.
4. Commitments and Contingencies
Approach Operating, LLC v. EnCana Oil & Gas (USA) Inc., Cause No. 29.070A, District Court of
Limestone County, Texas. On July 2, 2009, our operating subsidiary filed a lawsuit against EnCana
Oil & Gas (USA) Inc. (EnCana) for breach of the joint operating agreement (JOA) covering our
7
APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2010
(Unaudited)
North Bald Prairie project in East Texas and seeking damages for nonpayment of amounts owed
under the JOA as well as declaratory relief. We contend that such
amounts owed by EnCana were at
least $2 million and $2.1 million at June 30, 2010, and December 31, 2009, respectively, plus
attorneys fees, costs and other amounts to which we might be entitled under law or in equity. The
amount owed to us is included in other noncurrent assets on our balance sheet at June 30, 2010, and
December 31, 2009. As we previously have disclosed, in December 2008, EnCana notified us that it
was exercising its right to become operator of record for joint interest wells in North Bald
Prairie under an operator election agreement between the parties. EnCana contends that it does not
owe us for part or all of joint interest billings incurred after EnCana provided us with notice of
EnCanas election to assume operatorship in December 2008. EnCana also alleges that certain of the
disputed operations were unnecessary, and that other charges are improper because we allegedly
failed to obtain EnCanas consent under the JOA prior to undertaking the operations. We have
informed the court that we will transfer operatorship to EnCana when EnCana has made all payments
it owes under the JOA.
We also are involved in various other legal and regulatory proceedings arising in the
normal course of business. While we cannot predict the outcome of these proceedings with
certainty, we do not believe that an adverse result in any pending legal or regulatory proceeding,
individually or in the aggregate, would be material to our consolidated financial condition or cash
flows; however, an unfavorable outcome could have a material adverse effect on our results of
operations for a specific interim period or year.
5. Income Taxes
The effective income tax rate for the three and six months ended June 30, 2010, was 32% and
36%, respectively. Total income tax expense for the three and six months end June 30, 2010,
differed from amounts computed by applying the U.S. federal statutory tax rates to pretax income
due to the impact of permanent differences between book and taxable income.
Total income tax expense for the three and six months ended June 30, 2009, was 40.7% and
84.3%, respectively. Total income tax expense for the three and six months ended June 30, 2009,
differed from the amounts computed by applying the U.S. federal statutory tax rates to pretax
income due to the impact of permanent differences between book and taxable income. The total
income tax expense for the six months ended June 30, 2009, also was impacted by a change in our
estimated income tax expense for the year ended December 31, 2008, and increased state income tax
rates.
6. Derivatives
At June 30, 2010, we had the following commodity derivatives positions outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
$/MMBtu |
|
Period |
|
Monthly |
|
|
Total |
|
|
Fixed |
|
NYMEX Henry Hub |
|
|
|
|
|
|
|
|
|
|
|
|
Price swaps 2010 |
|
|
150,000 |
|
|
|
900,000 |
|
|
$ |
5.85 |
|
Price swaps 2010 |
|
|
150,000 |
|
|
|
900,000 |
|
|
$ |
6.40 |
|
Price swaps 2010 |
|
|
100,000 |
|
|
|
600,000 |
|
|
$ |
6.36 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average price ($/MMBtu) |
|
|
|
|
|
|
|
|
|
$ |
6.18 |
|
|
|
|
|
|
|
|
|
|
|
|
|
WAHA basis differential |
|
|
|
|
|
|
|
|
|
|
|
|
Basis swaps 2010 |
|
|
415,000 |
|
|
|
2,490,000 |
|
|
$ |
(0.71 |
) |
Basis swaps 2011 |
|
|
300,000 |
|
|
|
3,600,000 |
|
|
$ |
(0.53 |
) |
8
APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2010
(Unaudited)
The following summarizes the fair value of our open commodity derivatives as of June 30,
2010, and December 31, 2009 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Derivatives |
|
|
Liability Derivatives |
|
|
|
Balance Sheet |
|
|
|
|
|
|
|
|
|
|
Balance Sheet |
|
|
|
|
|
|
Location |
|
|
Fair Value |
|
|
Location |
|
|
Fair Value |
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
2010 |
|
|
2009 |
|
Derivatives
not
designated as
hedging instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized |
|
|
|
|
|
|
|
|
|
Unrealized |
|
|
|
|
|
|
|
|
Commodity |
|
gain on |
|
|
|
|
|
|
|
|
|
loss on |
|
|
|
|
|
|
|
|
derivatives |
|
commodity |
|
|
|
|
|
|
|
|
|
commodity |
|
|
|
|
|
|
|
|
|
|
derivatives |
|
$ |
1,839 |
|
|
$ |
786 |
|
|
derivatives |
|
$ |
528 |
|
|
$ |
2,668 |
|
The following summarizes the impact of our commodity derivatives on our consolidated
statement of operations (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Derivatives |
|
|
|
Income Statement |
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
Location |
|
|
June 30, |
|
|
June 30, |
|
|
|
|
|
|
|
2010 |
|
2009 |
|
|
2010 |
|
2009 |
|
Derivatives not
designated as
hedging instruments
under SFAS 133 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized gain on |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
commodity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
derivatives |
|
derivatives |
|
$ |
1,768 |
|
|
$ |
4,444 |
|
|
$ |
1,998 |
|
|
$ |
7,625 |
|
|
|
Unrealized (loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
gain on commodity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
derivatives |
|
|
(1,901 |
) |
|
|
(4,320 |
) |
|
|
3,194 |
|
|
|
(2,175 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(133 |
) |
|
$ |
124 |
|
|
$ |
5,192 |
|
|
$ |
5,450 |
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gains and losses, at fair value, are included on our consolidated balance
sheets as current or noncurrent assets or liabilities based on the anticipated timing of cash
settlements under the related contracts. Changes in the fair value of our commodity derivative
contracts are recorded in net income as they occur and included in other income (expense) on our
consolidated statements of operations. We estimate the fair values of swap contracts based on the
present value of the difference in exchange-quoted forward price curves and contractual settlement
prices multiplied by notional quantities. We use our internal valuations to determine the fair
values of the contracts that are reflected on our consolidated balance sheets. Realized gains and
losses are also included in other income (expense) on our consolidated statements of operations.
We are exposed to credit losses in the event of nonperformance by the counterparties on our
commodity derivatives positions and have considered the exposure in our internal valuations.
However, we do not anticipate nonperformance by the counterparties over the term of the commodity
derivatives positions.
9
APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2010
(Unaudited)
To estimate the fair value of our commodity derivatives positions, we use market data or
assumptions that market participants would use in pricing the asset or liability, including
assumptions about risk and the risks inherent in the inputs to the valuation technique. These
inputs can be readily observable, market corroborated or generally unobservable. We primarily apply
the market approach for recurring fair value measurements and attempt to use the best available
information. We determine the fair value based upon the hierarchy that prioritizes the inputs used
to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in
active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to
unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows:
|
|
|
Level 1 Quoted prices are available in active markets for identical assets or
liabilities as of the reporting date. At June 30, 2010, we had no Level 1 measurements. |
|
|
|
Level 2 Pricing inputs are other than quoted prices in active markets included in
Level 1, which are either directly or indirectly observable as of the reporting date.
Level 2 includes those financial instruments that are valued using models or other
valuation methodologies. These models are primarily industry-standard models that
consider various assumptions, including quoted forward prices for commodities, time
value, volatility factors and current market and contractual prices for the underlying
instruments, as well as other relevant economic measures. Our derivatives, which
consist primarily of commodity swaps, are valued using commodity market data which is
derived by combining raw inputs and quantitative models and processes to generate
forward curves. Where observable inputs are available, directly or indirectly, for
substantially the full term of the asset or liability, the instrument is categorized in
Level 2. At June 30, 2010, all of our commodity derivatives were valued using Level 2
measurements. |
|
|
|
Level 3 Pricing inputs include significant inputs that are generally less
observable from objective sources. These inputs may be used with internally developed
methodologies that result in managements best estimate of fair value. At June 30,
2010, we had no Level 3 measurements. |
7. Share-Based Compensation
During the six months ended June 30, 2010, we granted 107,777 nonvested shares of common stock
to employees. The total fair market value of these nonvested shares on the grant date was
$812,000, which will be expensed over a service period of three years. A summary of the status of
nonvested shares for the six months ended June 30, 2010, is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
|
|
Grant-Date |
|
|
|
Shares |
|
|
Fair Value |
|
Nonvested at January 1, 2010 |
|
|
225,880 |
|
|
$ |
9.73 |
|
|
|
|
|
|
|
|
|
|
Granted |
|
|
107,777 |
|
|
|
7.53 |
|
Vested |
|
|
(63,527 |
) |
|
|
10.63 |
|
Cancelled |
|
|
(1,680 |
) |
|
|
15.48 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonvested at June 30, 2010 |
|
|
268,450 |
|
|
$ |
8.60 |
|
|
|
|
|
|
|
|
10
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion is intended to assist in understanding our results of operations and
our financial condition. This section should be read in conjunction with managements discussion
and analysis contained in our Annual Report on Form 10-K for the year ended December 31, 2009,
filed with the Securities and Exchange Commission (SEC) on March 12, 2010. Our consolidated
financial statements and the accompanying notes included elsewhere in this Quarterly Report on Form
10-Q contain additional information that should be referred to when reviewing this material.
Certain statements in this discussion may be forward-looking. These forward-looking statements
involve risks and uncertainties, which could cause actual results to differ from those expressed in
this report. A glossary containing the meaning of the oil and gas industry terms used in this
managements discussion and analysis follows the Results of Operations table in this Item 2.
Forward-Looking Statements and Cautionary Statements
Various statements in this report, including those that express a belief, expectation or
intention, as well as those that are not statements of historical fact, are forward-looking
statements within the meaning of Section 27A of the Securities Act of 1933, as amended and Section
21E of the Securities Exchange Act of 1934, as amended (the Exchange Act). The forward-looking
statements may include projections and estimates concerning the timing and success of specific
projects, typical well economics and our future reserves, production, revenues, costs, income,
capital spending, 3-D seismic operations, interpretation and results and obtaining permits and
regulatory approvals. When used in this report, the words will, believe, intend, expect,
may, should, anticipate, could, estimate, plan, predict, project or their
negatives, other similar expressions or the statements that include those words, are intended to
identify forward-looking statements, although not all forward-looking statements contain such
identifying words.
These forward-looking statements are largely based on our expectations, which reflect
estimates and assumptions made by our management. These estimates and assumptions reflect our best
judgment based on currently known market conditions and other factors. Although we believe such
estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of
risks and uncertainties that are beyond our control. In addition, managements assumptions about
future events may prove to be inaccurate. We caution all readers that the forward-looking
statements contained in this report are not guarantees of future performance, and we cannot assure
any reader that such statements will be realized or the forward-looking events and circumstances
will occur. Actual results may differ materially from those anticipated or implied in the
forward-looking statements due to the factors listed in the Risk Factors section and elsewhere in
this report. All forward-looking statements speak only as of the date of this report. We expressly
disclaim all responsibility to publicly update or revise any forward-looking statements as a result
of new information, future events or otherwise. These cautionary statements qualify all
forward-looking statements attributable to us, or persons acting on our behalf. The risks,
contingencies and uncertainties relate to, among other matters, the following:
|
|
estimated quantities of oil and gas reserves; |
|
|
overall United States and global economic and financial market conditions; |
|
|
domestic and foreign demand and supply for oil, gas, NGLs and LNG; |
|
|
uncertainty of commodity prices in oil, gas and NGLs; |
|
|
disruption of credit and capital markets; |
|
|
our financial position; |
|
|
our cash flow and liquidity; |
|
|
replacing our oil and gas reserves; |
|
|
our inability to retain and attract key personnel; |
|
|
uncertainty regarding our future operating results; |
11
|
|
uncertainties in exploring for and producing oil and gas; |
|
|
high costs, shortages, delivery delays or unavailability of drilling rigs,
equipment, labor or other services; |
|
|
disruptions to, capacity constraints in or other limitations on the pipeline systems
that deliver our gas and NGLs and other processing and transportation considerations; |
|
|
our inability to obtain additional financing necessary to fund our operations and
capital expenditures and to meet our other obligations; |
|
|
competition in the oil and gas industry; |
|
|
marketing of oil, gas and NGLs; |
|
|
interpretation of 3-D seismic data; |
|
|
exploitation of our current asset base or property acquisitions; |
|
|
the effects of government regulation and permitting and other legal requirements; |
|
|
plans, objectives, expectations and intentions contained in this report that are not
historical; and |
|
|
other factors discussed in our Annual Report on Form 10-K for the year ended
December 31, 2009, filed with the SEC on March 12, 2010. |
Our financial results depend upon many factors, particularly the price of oil and gas.
Commodity prices are affected by changes in market supply and demand, which are impacted by overall
economic activity, weather, pipeline capacity constraints, estimates of inventory storage levels,
commodity price differentials and other factors. Factors potentially impacting the future natural
gas supply balance include increased drilling and production from domestic, shale gas reservoirs
and the recent increase in the United States LNG import capacity. As a result, we cannot accurately
predict future oil and gas prices, and therefore, we cannot determine what effect increases or
decreases will have on our capital program, production volumes and future revenues. A substantial
or extended decline in oil and gas prices could have a material adverse effect on our business,
financial condition, results of operations, quantities of oil and gas reserves that may be
economically produced and liquidity that may be accessed through our borrowing base under our
revolving credit facility and through the capital markets. We enter into financial swaps and
collars to partially mitigate the risk of market price fluctuations related to future oil and gas
production.
In addition to production volumes and commodity prices, finding and developing sufficient
amounts of oil and gas reserves at economical costs are critical to our long-term success. Future
finding and development costs are subject to changes in the industry, including the costs of
acquiring, drilling and completing our projects. We focus our efforts on increasing oil and gas
reserves and production while controlling costs at a level that is appropriate for long-term
operations. Our future cash flow from operations will depend on our ability to manage our overall
cost structure.
Like all oil and gas production companies, we face the challenge of natural production
declines. Oil and gas production from a given well naturally decreases over time. Additionally, our
reserves have a rapid initial decline. We generally will attempt to overcome this natural decline
by drilling to develop and identify additional reserves, acquisitions, and farm-ins or other joint
drilling ventures. However, during times of severe price declines, we may from time to time reduce
capital expenditures and curtail drilling operations in order to preserve net asset value of our
existing proved reserves. A material reduction in capital expenditures and drilling activities
could materially reduce our production volumes and revenues and increase future expected costs
necessary to develop existing reserves. Notwithstanding these periods of reduced capital
expenditures or curtailed production, our future growth will depend upon our ability over the long
term to continue to add oil and gas reserves in excess of production at a reasonable cost. We
intend to maintain our focus on the costs of adding reserves through drilling and acquisitions as
well as the costs necessary to produce such reserves.
We also face the challenge of financing future acquisitions. We believe we have adequate
unused borrowing capacity under our revolving credit facility for possible acquisitions, temporary
working
12
capital needs and expansion of our drilling program. Funding for future acquisitions also may
require additional sources of financing, which may not be available.
Overview
We are an independent energy company engaged in the exploration, development, production and
acquisition of oil and gas properties. We focus on natural gas and oil reserves in tight sands and
shale and have leasehold interests totaling approximately 275,069 gross (199,110 net) acres as of
June 30, 2010. Our management and technical team has a proven track record of finding and
exploiting reservoirs through advanced completion, fracturing and drilling techniques. As the
operator of all of our production and estimated proved reserves, we have a high degree of control
over capital expenditures and other operating matters.
We currently operate or have interests in the following areas:
West Texas Permian Basin
|
|
Ozona Northeast (Wolfcamp, Canyon Sands, Strawn and Ellenburger) |
|
|
Cinco Terry (Wolfcamp, Canyon Sands and Ellenburger) |
East Texas East Texas Basin
|
|
North Bald Prairie (Cotton Valley Sand and Cotton Valley Lime) |
Northern New Mexico Chama Basin
|
|
El Vado East (Mancos Shale/Niobrara) |
Southwest Kentucky Illinois Basin
|
|
Boomerang (New Albany Shale) |
We had estimated proved oil and gas reserves of 278.3 Bcfe at June 30, 2010. Total proved
reserves at June 30, 2010, were 50% oil and NGLs, 50% natural gas and 48% proved developed. All of
the Companys proved reserves and production are located in Ozona Northeast and Cinco Terry in West
Texas and in North Bald Prairie in East Texas. See Managements Discussion and Analysis of
Financial Condition and Results of Operations Mid-Year 2010 Proved Oil and Gas Reserves.
Estimated proved reserves increased 27% to 278.3 Bcfe at June 30, 2010, compared to 218.9 Bcfe
of estimated proved reserves at December 31, 2009. The increase in proved reserves at June 30,
2010, is primarily due to planned processing upgrades in our largest field in the Permian Basin,
Ozona Northeast, after the first quarter of 2011. At that time, our current, wellhead gas purchase
contract will have expired and we will begin processing NGLs from the liquids-rich gas stream in
Ozona Northeast. Higher prices for natural gas, oil and NGLs, and well performance, planned
processing upgrades and development drilling in Cinco Terry wells also contributed to the increase
in proved reserves.
At June 30, 2010, we owned working interests in approximately 500 producing oil and gas wells.
Production for the second quarter of 2010 was 24.5 MMcfe/d. Our estimated production for the month
of July 2010 was 26.5 MMcfe/d.
As previously disclosed, earlier this year we received conditional permits from Rio Arriba
County, New Mexico for eight drilling locations. Under the Countys oil and gas ordinance,
additional approvals are required after satisfaction of the permit conditions and before drilling.
A County decision on a ninth permit application has been delayed. In addition, we have received
notice from the State of New Mexico that public hearings on requested proration units will be
required for at least two potential drilling locations in the County. As a result of ongoing
regulatory and permitting delays in New Mexico,
13
we expect to focus on our core development drilling in West Texas for the remainder of 2010,
and do not expect to begin drilling in New Mexico before the second half of 2011.
Mid-Year 2010 Proved Oil and Gas Reserves
Proved Reserves Table
The following table sets forth summary information regarding our estimated proved reserves as
of June 30, 2010. We determined the natural gas equivalent of oil and NGLs by using a conversion
ratio of six Mcf of natural gas to one Bbl of oil or NGLs. The standardized measure of discounted
future net cash flows for our proved reserves at June 30, 2010, was $180.3 million. The PV-10 of
our estimated proved reserves at June 30, 2010, was $277.8 million.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves |
|
Reserves Category |
|
Natural Gas (MMcf) |
|
|
Oil (MBbls) |
|
|
NGLs (MBbls) |
|
|
Total (MMcfe) |
|
PROVED |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ozona Northeast |
|
|
49,184 |
|
|
|
616 |
|
|
|
6,628 |
|
|
|
92,653 |
|
Cinco Terry |
|
|
16,204 |
|
|
|
1,161 |
|
|
|
2,872 |
|
|
|
40,402 |
|
North Bald Prairie |
|
|
1,493 |
|
|
|
|
|
|
|
|
|
|
|
1,493 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
66,881 |
|
|
|
1,777 |
|
|
|
9,500 |
|
|
|
134,548 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Undeveloped: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ozona Northeast |
|
|
47,454 |
|
|
|
981 |
|
|
|
6,822 |
|
|
|
94,268 |
|
Cinco Terry |
|
|
12,046 |
|
|
|
1,834 |
|
|
|
2,145 |
|
|
|
35,919 |
|
North Bald Prairie |
|
|
13,516 |
|
|
|
|
|
|
|
|
|
|
|
13,516 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
73,016 |
|
|
|
2,815 |
|
|
|
8,967 |
|
|
|
143,703 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL PROVED at June 30, 2010 |
|
|
139,897 |
|
|
|
4,592 |
|
|
|
18,467 |
|
|
|
278,251 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the six months ended June 30, 2010, we engaged DeGolyer and MacNaughton, independent
petroleum engineers, to prepare independent estimates of the proved reserves associated with our
oil and gas properties. Estimates of the PV-10 of our proved reserves were prepared by the
Companys reservoir engineers.
Proved reserve volumes and PV-10 were estimated based on the unweighted, arithmetic average of
the closing price on the first day of each month for the 12-month period prior to June 30, 2010,
for natural gas, oil and NGLs. Natural gas volumes were calculated based on the average Henry Hub
spot price of $4.09 per MMBtu. Oil volumes were calculated based on the average West Texas
Intermediate, or WTI, posted price of $75.99 per Bbl. NGL volumes were calculated based on the
average price received on the first day of each month for the 12-month period prior to June 30,
2010, of $36.12 per Bbl. All prices were adjusted for energy content, quality and basis
differentials by field and were held constant through the lives of the properties.
PV-10 is our estimate of the present value of future net revenues from proved oil and gas
reserves after deducting estimated production and ad valorem taxes, future capital costs and
operating expenses, but before deducting any estimates of future income taxes. PV-10 is a
non-GAAP, financial measure and generally differs from the standardized measure of discounted
future net cash flows, the most directly comparable GAAP financial measure, because it does not
include the effects of income taxes on future cash flows. PV-10 should not be considered as an
alternative to the standardized measure of discounted future net cash flows as computed under GAAP.
14
The following table shows our reconciliation of our PV-10 to the standardized measure of
discounted future net cash flows (the most directly comparable measure calculated and presented in
accordance with GAAP). The estimated future net revenues are discounted at an annual rate of 10% to
determine their present value.
|
|
|
|
|
|
|
As of June 30, |
|
|
|
2010 |
|
|
|
(in thousands) |
|
PV-10 |
|
$ |
277,793 |
|
Less income taxes: |
|
|
|
|
Undiscounted future income taxes |
|
|
(235,984 |
) |
10% discount factor |
|
|
138,459 |
|
|
|
|
|
Future discounted income taxes |
|
|
(97,525 |
) |
|
|
|
|
|
Standardized measure of discounted future net cash flows |
|
$ |
180,268 |
|
|
|
|
|
We believe PV-10 to be an important measure for evaluating the relative significance of
our oil and gas properties and that the presentation of the non-GAAP financial measure of PV-10
provides useful information to investors because it is widely used by professional analysts and
investors in evaluating oil and gas companies. Because there are many unique factors that can
impact an individual company when estimating the amount of future income taxes to be paid, we
believe the use of a pretax measure is valuable for evaluating the Company. We believe that PV-10
is a financial measure routinely used and calculated similarly by other companies in the oil and
gas industry.
15
Results of Operations
The following table sets forth summary information regarding natural gas, oil and NGL
revenues, production, average product prices and average production costs and expenses for the
three and six months ended June 30, 2010 and 2009. Oil and NGLs are converted at the rate of one
Bbl per six Mcf.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2010 |
|
2009 |
|
|
2010 |
|
2009 |
|
Revenues (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas |
|
$ |
6,864 |
|
|
$ |
5,326 |
|
|
$ |
14,546 |
|
|
$ |
11,936 |
|
Oil |
|
|
3,940 |
|
|
|
3,182 |
|
|
|
7,495 |
|
|
|
5,210 |
|
NGLs |
|
|
2,351 |
|
|
|
1,407 |
|
|
|
4,334 |
|
|
|
2,834 |
|
|
|
|
|
|
|
|
Total oil and gas sales |
|
|
13,155 |
|
|
|
9,915 |
|
|
|
26,375 |
|
|
|
19,980 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized gain on commodity derivatives |
|
|
1,768 |
|
|
|
4,444 |
|
|
|
1,998 |
|
|
|
7,625 |
|
|
|
|
|
|
|
|
Total oil and gas sales including
derivative impact |
|
$ |
14,923 |
|
|
$ |
14,359 |
|
|
$ |
28,373 |
|
|
$ |
27,605 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (MMcf) |
|
|
1,558 |
|
|
|
1,624 |
|
|
|
2,982 |
|
|
|
3,395 |
|
Oil (MBbls) |
|
|
54 |
|
|
|
57 |
|
|
|
101 |
|
|
|
116 |
|
NGLs (MBbls) |
|
|
58 |
|
|
|
52 |
|
|
|
104 |
|
|
|
120 |
|
|
|
|
|
|
|
|
Total (MMcfe) |
|
|
2,231 |
|
|
|
2,282 |
|
|
|
4,212 |
|
|
|
4,815 |
|
Total (MMcfe/d) |
|
|
24.5 |
|
|
|
25.1 |
|
|
|
23.3 |
|
|
|
26.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (per Mcf) |
|
$ |
4.41 |
|
|
$ |
3.28 |
|
|
$ |
4.88 |
|
|
$ |
3.52 |
|
Oil (per Bbl) |
|
|
73.26 |
|
|
|
55.60 |
|
|
|
74.27 |
|
|
|
44.83 |
|
NGLs (per Bbl) |
|
|
40.33 |
|
|
|
26.84 |
|
|
|
41.65 |
|
|
|
23.54 |
|
|
|
|
|
|
|
|
Total (per Mcfe) |
|
$ |
5.90 |
|
|
$ |
4.35 |
|
|
$ |
6.26 |
|
|
$ |
4.15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized gain on commodity derivatives
(per Mcfe) |
|
|
0.79 |
|
|
|
1.95 |
|
|
|
0.47 |
|
|
|
1.58 |
|
|
|
|
|
|
|
|
Total including derivative impact
(per Mcfe) |
|
$ |
6.69 |
|
|
$ |
6.30 |
|
|
$ |
6.73 |
|
|
$ |
5.73 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses (per Mcfe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating (1) |
|
$ |
0.99 |
|
|
$ |
0.77 |
|
|
$ |
0.96 |
|
|
$ |
0.86 |
|
Severance and production taxes |
|
|
0.27 |
|
|
|
0.22 |
|
|
|
0.31 |
|
|
|
0.19 |
|
Exploration |
|
|
0.08 |
|
|
|
|
|
|
|
0.40 |
|
|
|
|
|
General and administrative |
|
|
0.98 |
|
|
|
0.98 |
|
|
|
1.11 |
|
|
|
1.05 |
|
Depletion, depreciation and amortization |
|
|
2.25 |
|
|
|
2.73 |
|
|
|
2.57 |
|
|
|
2.74 |
|
(1) Lease operating expenses per Mcfe include ad valorem taxes.
Bbl. One stock tank barrel, of 42 U.S. gallons liquid volume, used herein to reference oil,
condensate or NGLs.
MBbl. Thousand barrels of oil, condensate or NGLs.
Mcf. Thousand cubic feet of natural gas.
MMcf. Million cubic feet of natural gas.
MMcfe. Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one
Bbl of oil, condensate or NGLs.
NGLs. Natural gas liquids.
/d. Per day when used with volumetric units or dollars.
16
Three Months Ended June 30, 2010, Compared to Three Months Ended June 30, 2009
Oil and gas production. Production for the three months ended June 30, 2010, totaled 2.2 Bcfe
(24.5 MMcfe/d), compared to 2.3 Bcfe (25.1 MMcfe/d) produced in the prior year period, a decrease
of 2.2%. Production for the three months ended June 30, 2010, was 70% natural gas and 30% oil and
NGLs, compared to 71% natural gas and 29% oil and NGLs in the prior year period. Production from
tight gas reservoirs has a high initial rate of decline in the early life of the well. The natural
decline of our tight gas fields and reduced drilling activity in 2009 caused a decline in our
average daily production from the three months ended June 30, 2009, to the three months ended June
30, 2010. Production declined at a faster rate in our Cinco Terry field than Ozona Northeast,
which we believe is typical given its earlier stage of development. Production declined at a
slower rate in Ozona Northeast due to the later stage of development of the field.
Oil and gas sales. Oil and gas sales increased $3.2 million, or 32.7%, for the three months
ended June 30, 2010, to $13.2 million from $9.9 million for the three months ended June 30, 2009.
The increase in oil and gas sales principally resulted from an increase in realized oil and gas
prices.
Commodity derivative activities. Our commodity derivative activity resulted in a realized gain
of $1.8 million and $4.4 million for the three months ended June 30, 2010, and 2009, respectively.
Our average realized price, including the effect of commodity derivatives, was $6.69 per Mcfe for
the three months ended June 30, 2010, compared to $6.30 per Mcfe for the three months ended June
30, 2009. Realized gains and losses on commodity derivatives are derived from the relative
movement of gas prices in relation to the fixed notional pricing in our price swaps for the
applicable periods. The unrealized loss on commodity derivatives was $1.9 million and $4.3 million
for the three months ended June 30, 2010, and 2009, respectively. As natural gas commodity prices
increase, the fair value of the open portion of those positions decreases. As natural gas
commodity prices decrease, the fair value of the open portion of those positions increases.
Historically, we have not designated our derivative instruments as cash-flow hedges. We record our
open derivative instruments at fair value on our consolidated balance sheets as either unrealized
gains or losses on commodity derivatives. We record changes in such fair value in net income on our
consolidated statements of operations under the caption entitled unrealized (loss) gain on
commodity derivatives.
Lease operating expenses. Our lease operating expenses (LOE) increased $450,000, or 25.7%,
for the three months ended June 30, 2010, to $2.2 million ($0.99 per Mcfe) from $1.8 million ($0.77
per Mcfe) for the three months ended June 30, 2009. The increase in LOE per Mcfe over the prior
year period was primarily due to higher ad valorem taxes and well repairs and maintenance. The
higher ad valorem taxes for the three months ended June 30, 2010, included a change in our
estimated ad valorem taxes for 2010 attributable to higher commodity price assumptions used by
taxing authorities to calculate final taxes for 2010. As average daily production is expected to
continue to increase from the three and six months ended June 30, 2010, we expect LOE per Mcfe to
decrease slightly from current levels during the remainder of 2010. The following is a summary of
LOE (per Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
|
|
|
|
|
|
June 30, |
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
Change |
|
|
% Change |
|
Compression and gas treating |
|
$ |
0.26 |
|
|
$ |
0.27 |
|
|
$ |
(0.01 |
) |
|
|
(3.7 |
)% |
Ad valorem taxes |
|
|
0.23 |
|
|
|
0.06 |
|
|
|
0.17 |
|
|
|
283.3 |
|
Water hauling, insurance and other |
|
|
0.21 |
|
|
|
0.21 |
|
|
|
|
|
|
|
|
|
Pumping and supervision |
|
|
0.14 |
|
|
|
0.13 |
|
|
|
0.01 |
|
|
|
7.7 |
|
Well repairs and maintenance |
|
|
0.12 |
|
|
|
0.08 |
|
|
|
0.04 |
|
|
|
50.0 |
|
Workovers |
|
|
0.03 |
|
|
|
0.02 |
|
|
|
0.01 |
|
|
|
50.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
0.99 |
|
|
$ |
0.77 |
|
|
$ |
0.22 |
|
|
|
28.6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
17
Severance and production taxes. Our severance and production taxes increased $103,000, or
20.3%, for the three months ended June 30, 2010, to $610,000 from $507,000 for the three months
ended June 30, 2009. The increase in severance and production taxes was primarily a function of the
increase in oil and gas sales between the two periods. Severance and production taxes amounted to
approximately 4.6% and 5.1% of oil and gas sales for the respective periods.
Exploration. We recorded $187,000 of exploration expense for the three months ended June 30,
2010. Exploration expense for the three months ended June 30, 2010, resulted primarily from lease
extensions in Cinco Terry. We recorded no exploration expense for the three months ended June 30,
2009.
General and administrative. Our general and administrative expenses (G&A) decreased $49,000,
or 2.2%, to $2.2 million ($0.98 per Mcfe) for the three months ended June 30, 2010, from $2.2
million ($0.98 per Mcfe) for the three months ended June 30, 2009. Following is a summary of G&A
(in millions and per Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
|
|
|
|
|
|
June 30, |
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
Change |
|
|
% Change |
|
|
|
$MM |
|
|
Mcfe |
|
|
$MM |
|
|
Mcfe |
|
|
$MM |
|
|
Mcfe |
|
|
Mcfe |
|
Salaries and benefits |
|
$ |
1.0 |
|
|
$ |
0.46 |
|
|
$ |
1.0 |
|
|
$ |
0.43 |
|
|
$ |
|
|
|
$ |
0.03 |
|
|
|
7.0 |
% |
Share-based compensation |
|
|
0.4 |
|
|
|
0.17 |
|
|
|
0.3 |
|
|
|
0.15 |
|
|
|
0.1 |
|
|
|
0.02 |
|
|
|
13.3 |
|
Professional fees |
|
|
0.2 |
|
|
|
0.10 |
|
|
|
0.2 |
|
|
|
0.07 |
|
|
|
|
|
|
|
0.03 |
|
|
|
42.9 |
|
Rent expense |
|
|
0.1 |
|
|
|
0.05 |
|
|
|
0.1 |
|
|
|
0.05 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Data processing |
|
|
0.1 |
|
|
|
0.04 |
|
|
|
0.1 |
|
|
|
0.07 |
|
|
|
|
|
|
|
(0.03 |
) |
|
|
(42.9 |
) |
Other |
|
|
0.4 |
|
|
|
0.16 |
|
|
|
0.5 |
|
|
|
0.21 |
|
|
|
(0.1 |
) |
|
|
(0.05 |
) |
|
|
(23.8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
2.2 |
|
|
$ |
0.98 |
|
|
$ |
2.2 |
|
|
$ |
0.98 |
|
|
$ |
|
|
|
$ |
|
|
|
|
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization. Our depletion, depreciation and amortization
expense (DD&A) decreased $1.2 million, or 19.5%, to $5 million for the three months ended June
30, 2010, from $6.2 million for the three months ended June 30, 2009. Our DD&A per Mcfe decreased
by $0.48, or 17.6%, to $2.25 per Mcfe for the three months ended June 30, 2010, compared to $2.73
per Mcfe for the three months ended June 30, 2009. The decrease in DD&A was primarily attributable
to an increase in estimated proved developed reserves at June 30, 2010, and a slight decrease in
production over the prior year period. Our estimated proved developed reserves at June 30, 2010,
increased primarily due to the expected NGL recoveries in Ozona Northeast after the first quarter
of 2011, higher commodity prices and well performance, planned processing upgrades and development
drilling in Cinco Terry.
Interest expense, net. Our interest expense, net, increased $93,000, or 20.4%, to $550,000
for the three months ended June 30, 2010, from $457,000 for the three months ended June 30, 2009.
This increase was substantially the result of higher interest rates in the 2010 period, partially
offset by a higher average debt level in the 2009 period. Additionally, interest expense during
the three months ended June 30, 2010, was higher due to amortization of $63,000 for deferred loan
costs. The weighted average interest rate applicable to our outstanding borrowings during the
three months ended June 30, 2010 and 2009, was 3.62% and 3.28%, respectively.
Income taxes. Our income taxes increased $1.2 million to $730,000 for the three months ended
June 30, 2010, from a benefit of $460,000 for the three months ended June 30, 2009. The increase in
income taxes was due to higher pretax income in the 2010 period. Our effective income tax rate for
the three months ended June 30, 2010, was 32%, compared with 40.7% for the three months ended June
30, 2009. Total income tax expense for the three months end June 30, 2010, differed from amounts
computed by applying the U.S. federal statutory tax rates to pretax income due to the impact of
permanent difference between book and taxable income.
18
Six Months Ended June 30, 2010, Compared to Six Months Ended June 30, 2009
Oil and gas production. Production for the six months ended June 30, 2010, totaled 4.2 Bcfe
(23.3 MMcfe/d), compared to 4.8 Bcfe (26.6 MMcfe/d) produced in the prior year period, a decrease
of 12.5%. Production for the six months ended June 30, 2010 and 2009, was 71% natural gas and 29%
oil and NGLs. Production from tight gas reservoirs has a high initial rate of decline in the early
life of the well. The natural decline of our tight gas fields and reduced drilling activity in
2009 caused a decline in our average daily production from the six months ended June 30, 2009, to
the six months ended June 30, 2010. Production declined at a faster rate in our Cinco Terry field
than Ozona Northeast, which we believe is typical given its earlier stage of development.
Production declined at a slower rate in Ozona Northeast due to the later stage of development of
the field.
Oil and gas sales. Oil and gas sales increased $6.4 million, or 32%, for the six months ended
June 30, 2010, to $26.4 million from $20 million for the six months ended June 30, 2009. The
increase in oil and gas sales principally resulted from an increase in realized oil and gas prices,
partially offset by a decrease in production. Of the $6.4 million increase in revenues,
approximately $10.2 million was attributable to an increase in oil and gas prices, partially offset
by approximately $3.8 million attributable to a reduction in production.
Commodity derivative activities. Our commodity derivative activity resulted in a realized gain
of $2 million and $7.6 million for the six months ended June 30, 2010, and 2009, respectively. Our
average realized price, including the effect of commodity derivatives, was $6.73 per Mcfe for the
six months ended June 30, 2010, compared to $5.73 per Mcfe for the six months ended June 30, 2009.
Realized gains and losses on commodity derivatives are derived from the relative movement of gas
prices in relation to the fixed notional pricing in our price swaps for the applicable periods.
The unrealized gain on commodity derivatives was $3.2 million for the six months ended June 30,
2010, compared to an unrealized loss of $2.2 million for the six months ended June 30, 2009. As
natural gas commodity prices increase, the fair value of the open portion of those positions
decreases. As natural gas commodity prices decrease, the fair value of the open portion of those
positions increases. Historically, we have not designated our derivative instruments as cash-flow
hedges. We record our open derivative instruments at fair value on our consolidated balance sheets
as either unrealized gains or losses on commodity derivatives. We record changes in such fair value
in net income on our consolidated statements of operations under the caption entitled unrealized
(loss) gain on commodity derivatives.
Lease operating expenses. Our LOE decreased $79,000, or 1.9%, for the six months ended June
30, 2010, to $4 million ($0.96 per Mcfe) from $4.1 million ($0.86 per Mcfe) for the six months
ended June 30, 2009. The increase in LOE per Mcfe over the prior year period was primarily due to
an increase in ad valorem taxes, pumping and supervision and well repairs and maintenance, in
addition to a decrease in production and compression and gas treating over the prior year period.
The higher ad valorem taxes for the six months ended June 30, 2010, included a change in our
estimated ad valorem taxes for 2010 attributable to higher commodity price assumptions used by
taxing authorities to calculate final taxes for 2010. In addition, pumping and supervision costs
increased due to our continued development of our fields, and compression and treating declined due
to lower compressor rentals. The following is a summary of LOE (per Mcfe):
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
|
|
|
|
|
|
|
June 30, |
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
Change |
|
|
% Change |
|
Compression and gas treating |
|
$ |
0.27 |
|
|
$ |
0.31 |
|
|
$ |
(0.04 |
) |
|
|
(12.9 |
)% |
Ad valorem taxes |
|
|
0.21 |
|
|
|
0.15 |
|
|
|
0.06 |
|
|
|
40.0 |
|
Pumping and supervision |
|
|
0.18 |
|
|
|
0.14 |
|
|
|
0.04 |
|
|
|
28.6 |
|
Water hauling, insurance and other |
|
|
0.18 |
|
|
|
0.17 |
|
|
|
0.01 |
|
|
|
5.9 |
|
Well repairs and maintenance |
|
|
0.11 |
|
|
|
0.08 |
|
|
|
0.03 |
|
|
|
37.5 |
|
Workovers |
|
|
0.01 |
|
|
|
0.01 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
0.96 |
|
|
$ |
0.86 |
|
|
$ |
0.10 |
|
|
|
11.6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Severance and production taxes. Our severance and production taxes increased $367,000, or
39.2%, for the six months ended June 30, 2010, to $1.3 million from $937,000 for the six months
ended June 30, 2009. The increase in severance and production taxes was primarily a function of the
increase in oil and gas sales between the two periods. Severance and production taxes amounted to
approximately 4.9% and 4.7% of oil and gas sales for the respective periods.
Exploration. We recorded $1.7 million of exploration expense for the six months ended June 30,
2010. Exploration expense for the six months ended June 30, 2010, resulted primarily from our
acquisition of 3-D seismic data across Cinco Terry. We recorded no exploration expense for the six
months ended June 30, 2009.
General and administrative. Our G&A decreased $350,000, or 6.9%, to $4.7 million ($1.11 per
Mcfe) for the six months ended June 30, 2010, from $5 million ($1.05 per Mcfe) for the six months
ended June 30, 2009. The decrease in G&A was principally due to data processing and lower
professional fees, partially offset by an increase in rent expense. Following is a summary of G&A
(in millions and per Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
|
|
|
|
|
|
|
June 30, |
|
|
|
|
|
|
|
|
|
2010 |
|
|
2009 |
|
|
Change |
|
|
% Change |
|
|
|
$MM |
|
|
Mcfe |
|
|
$MM |
|
|
Mcfe |
|
|
$MM |
|
|
Mcfe |
|
|
Mcfe |
|
Salaries and benefits |
|
$ |
2.0 |
|
|
$ |
0.48 |
|
|
$ |
2.0 |
|
|
$ |
0.40 |
|
|
$ |
|
|
|
$ |
0.08 |
|
|
|
20.0 |
% |
Share-based compensation |
|
|
1.0 |
|
|
|
0.24 |
|
|
|
1.0 |
|
|
|
0.21 |
|
|
|
|
|
|
|
0.03 |
|
|
|
14.3 |
|
Rent expense |
|
|
0.7 |
|
|
|
0.16 |
|
|
|
0.6 |
|
|
|
0.12 |
|
|
|
0.1 |
|
|
|
0.04 |
|
|
|
33.3 |
|
Professional fees |
|
|
0.5 |
|
|
|
0.13 |
|
|
|
0.6 |
|
|
|
0.13 |
|
|
|
(0.1 |
) |
|
|
|
|
|
|
|
|
Data processing |
|
|
0.2 |
|
|
|
0.05 |
|
|
|
0.4 |
|
|
|
0.08 |
|
|
|
(0.2 |
) |
|
|
(0.03 |
) |
|
|
(37.5 |
) |
Other |
|
|
0.3 |
|
|
|
0.05 |
|
|
|
0.4 |
|
|
|
0.11 |
|
|
|
(0.1 |
) |
|
|
(0.06 |
) |
|
|
(54.5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
4.7 |
|
|
$ |
1.11 |
|
|
$ |
5.0 |
|
|
$ |
1.05 |
|
|
$ |
(0.3 |
) |
|
$ |
0.06 |
|
|
|
5.7 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization. Our DD&A decreased $2.3 million, or 17.7%, to
$10.8 million for the six months ended June 30, 2010, from $13.2 million for the six months ended
June 30, 2009. Our DD&A per Mcfe decreased by $0.17, or 6%, to $2.57 per Mcfe for the six months
ended June 30, 2010, compared to $2.74 per Mcfe for the six months ended June 30, 2009. The
decrease in DD&A was primarily attributable to an increase in estimated proved developed reserves
at June 30, 2010, and a decrease in production over the prior year period. Our estimated proved
developed reserves at June 30, 2010, increased primarily due to the expected NGL recoveries in
Ozona Northeast after the first quarter of 2011, higher commodity prices and well performance,
planned processing upgrades and development drilling in Cinco Terry.
Interest
expense, net. Our interest expense, net, increased $114,000, or 12.6%, to $1 million
for the six months ended June 30, 2010, from $902,000 for the six months ended June 30, 2009. This
increase was substantially the result of the amortization of $120,000 for deferred loan costs
during the six
20
months ended June 30, 2010. The weighted average interest rate applicable to our outstanding
borrowings during the six months ended June 30, 2010 and 2009, was 3.51% and 3.24%, respectively.
Income taxes. Our income taxes increased $1.8 million to $2.9 million for the six months ended
June 30, 2010, from $1.1 million for the six months ended June 30, 2009. The increase in income
taxes was due to higher pretax income in the 2010 period, partially offset by higher taxes in the
2009 period from a change in our estimated income tax provision for the year ended December 31,
2008. Our effective income tax rate for the six months ended June 30, 2010, was 36%, compared with
84.3% for the six months ended June 30, 2009. The higher effective tax rate in the 2009 period
resulted primarily from a change in our estimated income tax provision for the year ended December
31, 2008.
21
Liquidity and Capital Resources
We generally will rely on cash generated from operations, borrowings under our revolving
credit facility and, to the extent that credit and capital market conditions will allow, future
public equity and debt offerings to satisfy our liquidity needs. Our ability to fund planned
capital expenditures and to make acquisitions depends upon our future operating performance,
borrowing availability under our revolving credit facility, and more broadly, on the availability
of equity and debt financing, which is affected by prevailing economic conditions in our industry
and financial, business and other factors, some of which are beyond our control. We cannot predict
whether additional liquidity from equity or debt financings beyond our revolving credit facility
will be available on acceptable terms, or at all, in the foreseeable future.
Our cash flows from operating activities are affected by commodity prices, production, the
effect of commodity derivatives, changes in working capital and the timing of cash receipts and
payments. Prices for oil and gas are affected by national and international economic and political
environments, national and global supply and demand for hydrocarbons, seasonal influences of
weather and other factors beyond our control. Our working capital is significantly influenced by
changes in commodity prices, and significant declines in commodity prices will cause a decrease in
our production volumes and exploration and development expenditures. Our working capital also is
influenced by our efforts to manage our long-term debt levels and related interest costs and,
therefore, we maintain minimal cash balances. Our positive operating cash flow and available
borrowing capabilities allow us to maintain a low or negative working capital position. Cash flows
from operations are primarily used to fund exploration and development of our oil and gas
properties.
The following table summarizes our sources and uses of funds for the periods noted (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
|
2010 |
|
|
2009 |
|
Cash flows provided by operating activities |
|
$ |
18,332 |
|
|
$ |
11,186 |
|
Cash flows used in investing activities |
|
|
(30,234 |
) |
|
|
(16,545 |
) |
Cash flows provided by financing activities |
|
|
9,512 |
|
|
|
2,700 |
|
Effect of Canadian exchange rate |
|
|
(2 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents |
|
$ |
(2,392 |
) |
|
$ |
(2,660 |
) |
|
|
|
|
|
|
|
Operating Activities
During the six months ended June 30, 2010, our cash flows from operations, borrowings under
our revolving credit facility and available cash were used primarily for drilling activities in
Ozona Northeast and Cinco Terry and our 3-D seismic program in Cinco Terry.
Cash provided by operating activities for the six months ended June 30, 2010, was $18.3
million, compared to $11.2 million in the six months ended June 30, 2009. Cash flows from
operating activities increased $7.1 million from the same period in 2009 due primarily to a $6.4
million, or 32% increase, in oil and gas sales in the 2010 period. Cash flows provided by
operating activities also were affected by an increase in cash flows provided by working capital
during the six months ended June 30, 2010.
22
Investing Activities
The $30.2 million of cash flows used in investing activities during the six months ended June
30, 2010, were primarily for the continued development of our Cinco Terry and Ozona Northeast
fields, as well as acquiring 3-D seismic data across Cinco Terry. For the comparable 2009 period,
the cash flows used in investing activities were primarily for drilling operations in Cinco Terry.
Capital Expenditures for 2010
The following table summarizes our current capital expenditure budget for 2010. We intend to
fund 2010 capital expenditures, excluding any acquisitions, out of internally-generated cash flows
and, as necessary, borrowings under our revolving credit facility. At June 30, 2010, we had
available borrowing capacity of $72.5 million under our revolving credit facility.
|
|
|
|
|
|
|
Year Ending |
|
|
|
December 31, 2010 |
|
|
|
(in thousands) |
|
West Texas |
|
|
|
|
Ozona Northeast |
|
$ |
25,600 |
|
Cinco Terry |
|
|
19,950 |
|
Exploratory |
|
|
3,075 |
|
Lease acquisition, geological and geophysical |
|
|
4,375 |
|
|
|
|
|
Total capital expenditures |
|
$ |
53,000 |
|
|
|
|
|
Our capital expenditure budget for 2010 is subject to change depending upon a number of
factors, including economic and industry conditions at the time of drilling, prevailing and
anticipated prices for gas, oil and NGLs, the results of our development and exploration efforts,
the availability of sufficient capital resources for drilling prospects, our financial results, the
availability of leases on reasonable terms and our ability to obtain permits for the drilling
locations. We expect drilling rigs, drilling crews, steel tubulars and oilfield services to be in
high demand in the Permian Basin during 2010, and that the costs related to these services will
increase from 2009 levels. We expect that these higher service costs, as well as additional
exploration and acreage acquisition opportunities, will result in an increase in our 2010 capital
expenditure budget before year end 2010.
Financing Activities
We borrowed $51.2 million and $45.4 million under our revolving credit facility during the six
months ended June 30, 2010, and 2009, respectively. We repaid $41.7 million and $42.7 million of
the amounts borrowed under our revolving credit facility during the six months ended June 30, 2010,
and 2009, respectively.
Our current goal is to manage our borrowings to help us maintain financial flexibility and
liquidity, and to avoid the problems associated with highly-leveraged companies with large interest
costs and possible debt reductions restricting ongoing operations.
We believe that cash flows from operations and borrowings under our revolving credit facility
will finance substantially all of our capital needs through 2010. We may also use our revolving
credit facility for possible acquisitions and temporary working capital needs. Further, we may
determine to access the public equity or debt markets for potential acquisitions, working capital
or other liquidity needs, if such financing is available on acceptable terms.
23
Revolving Credit Facility
We have a $200 million revolving credit facility with a borrowing base set at $115 million.
The borrowing base is redetermined semi-annually on or before each April 1 and October 1 based on
our oil and gas reserves. We or the lenders can each request one additional borrowing base
redetermination each calendar year.
The maturity date under our revolving credit facility is July 31, 2012. Borrowings bear
interest based on the agent banks prime rate plus an applicable margin ranging from 1.25% to
2.25%, or the sum of the Eurodollar rate plus an applicable margin ranging from 2.25% to 3.25%.
Margins vary based on the borrowings outstanding compared to the borrowing base. In addition, we
pay an annual commitment of 0.50% of unused borrowings available under our revolving credit
facility.
Effective May 3, 2010, we entered into an eighth amendment to our credit agreement, which (i)
extended the maturity date of the Credit Agreement by one year to July 31, 2012, (ii) increased the
Companys commodity derivatives limit from 75% to 85% of annual projected production from proved
developed producing oil and gas properties, (iii) reaffirmed the borrowing base and lenders
aggregate commitment of $115 million and (iv) transferred Fortis Capital Corp.s interest in the
Credit Agreement to BNP Paribas.
We had outstanding borrowings of $42.2 million and $32.3 million under our revolving credit
facility at June 30, 2010 and December 31, 2009, respectively. The weighted average interest rate
applicable to our outstanding borrowings was 3.68% and 3.20% as of June 30, 2010, and December 31,
2009, respectively. We also had outstanding unused letters of credit under our revolving credit
facility totaling $350,000 at June 30, 2010, which reduce amounts available for borrowing under our
revolving credit facility.
Loans under our revolving credit facility are secured by first priority liens on substantially
all of our West Texas assets and are guaranteed by our subsidiaries.
Covenants
Our credit agreement contains two principal financial covenants:
|
|
a consolidated modified current ratio covenant that requires us to maintain a ratio
of not less than 1.0 to 1.0 at all times. The consolidated modified current ratio is
calculated by dividing Consolidated Current Assets (as defined in the credit agreement)
by Consolidated Current Liabilities (as defined in the credit agreement). As defined
more specifically in the credit agreement, the consolidated modified current ratio is
calculated as current assets less current unrealized gains on commodity derivatives
plus the available borrowing base at the respective balance sheet date, divided by
current liabilities less current unrealized losses on commodity derivatives at the
respective balance sheet date. |
|
|
a consolidated funded debt to consolidated EBITDAX ratio covenant that requires us
to maintain a ratio of not more than 3.5 to 1.0 at the end of each fiscal quarter. The
consolidated funded debt to consolidated EBITDAX ratio is calculated by dividing
Consolidated Funded Debt (as defined in the credit agreement) by Consolidated EBITDAX
(as defined in the credit agreement). As defined more specifically in the credit
agreement, consolidated EBITDAX is calculated as net income (loss), plus (1)
exploration expense, (2) depletion, depreciation and amortization expense, (3)
share-based compensation expense, (4) unrealized loss on commodity derivatives, (5)
interest expense, (6) income and franchise taxes, and (7) certain other noncash
expenses, less (1) gains or losses from sales or dispositions of assets, (2) unrealized
gain on commodity derivatives and (3) extraordinary or nonrecurring gains. For
|
24
|
|
purposes of calculating this ratio, consolidated EBITDAX for a fiscal quarter is
annualized pursuant to the credit agreement. |
Our credit agreement also restricts cash dividends and other restricted payments, transactions
with affiliates, incurrence of other debt, consolidations and mergers, the level of operating
leases, assets sales, investments in other entities and liens on properties.
In addition, our credit agreement contains customary events of default that would permit our
lenders to accelerate the debt under our credit agreement if not cured within applicable grace
periods, including, among others, failure to make payments of principal or interest when due,
materially incorrect representations and warranties, failure to make mandatory prepayments in the
event of borrowing base deficiencies, breach of covenants, defaults upon other obligations in
excess of $500,000, events of bankruptcy, the occurrence of one or more unstayed judgments in
excess of $500,000 not covered by an acceptable policy of insurance, failure to pay any obligation
in excess of $500,000 owed under any derivatives transaction or in any amount if the obligation
under the derivatives transaction is secured by collateral under the credit agreement, any event of
default by the Company occurs under any agreement entered into in connection with a derivatives
transaction, liens securing the loans under the credit agreement cease to be in place, a Change in
Control (as defined in the credit agreement) of the Company occurs, and dissolution of the Company.
At June 30, 2010, we were in compliance with all of our covenants and had not committed any
acts of default under the credit agreement.
To date we have experienced no disruptions in our ability to access our revolving credit
facility. However, our lenders have substantial ability to reduce our borrowing base on the basis
of subjective factors, including the loan collateral value that each lender, in its discretion and
using the methodology, assumptions and discount rates as such lender customarily uses in evaluating
oil and gas properties, assigns to our properties.
We cannot predict with certainty the impact to us of any further disruption in the credit
environment or guarantee that the lenders under our revolving credit facility will not decrease our
borrowing base in the future. If our borrowing base was decreased below our total outstanding
borrowings, resulting in a borrowing base deficiency, then we would be required under the credit
agreement, within 15 days after notice from the agent bank, to (i) pledge additional collateral to
cure the borrowing base deficiency, (ii) prepay the borrowing base deficiency in full or (iii)
commit to repay the borrowing base deficiency in six equal monthly installments, with the first
installment being due within 30 days after receipt of notice from the agent bank. There is no
guarantee that, in the event of such a borrowing base deficiency, we would be able to timely cure
the deficiency.
Contractual Obligations
There have been no material changes to our contractual obligations during the six months ended
June 30, 2010.
Off-Balance Sheet Arrangements
From time to time, we enter into off-balance sheet arrangements and transactions that can give
rise to off-balance sheet obligations. As of June 30, 2010, the off-balance sheet arrangements and
transactions that we have entered into include undrawn letters of credit, operating lease
agreements and gas delivery commitments. We do not believe that these arrangements are reasonably
likely to materially affect our liquidity or availability of, or requirements for, capital
resources.
25
|
|
|
Item 3. |
|
Quantitative and Qualitative Disclosures About Market Risk. |
Some of the information below contains forward-looking statements. The primary objective of
the following information is to provide forward-looking quantitative and qualitative information
about our potential exposure to market risks. The term market risk refers to the risk of loss
arising from adverse changes in oil and gas prices, and other related factors. The disclosure is
not meant to be a precise indicator of expected future losses, but rather an indicator of
reasonably possible losses. This forward-looking information provides an indicator of how we view
and manage our ongoing market risk exposures. Our market risk sensitive instruments were entered
into for commodity derivative and investment purposes, not for trading purposes.
Commodity Price Risk
While realized commodity prices improved during the six months ended June 30, 2010, compared
to the prior year period, the outlook for natural gas remains uncertain. Even modest decreases in
commodity prices can materially affect our revenues and cash flow. In addition, if commodity
prices remain suppressed for a significant amount of time, we could be required under successful
efforts accounting rules to perform a write down of our oil and gas properties.
We enter into financial swaps to reduce the risk of commodity price fluctuations. We do not
designate such instruments as cash flow hedges. Accordingly, we record open commodity derivative
positions on our consolidated balance sheets at fair value and recognize changes in such fair
values as income (expense) on our consolidated statements of operations as they occur.
At June 30, 2010, we have the following commodity derivative positions outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
$/MMBtu |
|
Period |
|
Monthly |
|
|
Total |
|
|
Fixed |
|
NYMEX Henry Hub |
|
|
|
|
|
|
|
|
|
|
|
|
Price swaps 2010 |
|
|
150,000 |
|
|
|
900,000 |
|
|
$ |
5.85 |
|
Price swaps 2010 |
|
|
150,000 |
|
|
|
900,000 |
|
|
$ |
6.40 |
|
Price swaps 2010 |
|
|
100,000 |
|
|
|
600,000 |
|
|
$ |
6.36 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average price ($/MMBtu) |
|
|
|
|
|
|
|
|
|
$ |
6.18 |
|
|
|
|
|
|
|
|
|
|
|
|
|
WAHA basis differential |
|
|
|
|
|
|
|
|
|
|
|
|
Basis swaps 2010 |
|
|
415,000 |
|
|
|
2,490,000 |
|
|
$ |
(0.71 |
) |
Basis swaps 2011 |
|
|
300,000 |
|
|
|
3,600,000 |
|
|
$ |
(0.53 |
) |
At June 30, 2010, and December 31, 2009, the fair value of our open derivative contracts
was a net asset of approximately $1.3 million and a net liability of $1.9 million, respectively.
JPMorgan Chase Bank, National Association and KeyBank National Association are currently the
only counterparties to our commodity derivatives positions. We are exposed to credit losses in the
event of nonperformance by counterparties on our commodity derivatives positions. However, we do
not anticipate nonperformance by the counterparties over the term of the commodity derivatives
positions. JPMorgan is the administrative agent and a participant, and KeyBank is a participant,
in our revolving credit facility and the collateral for the outstanding borrowings under our
revolving credit facility is used as collateral for our commodity derivatives.
Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as
current or noncurrent assets or liabilities based on the anticipated timing of cash settlements
under the related contracts. Changes in the fair value of our commodity derivative contracts are
recorded in net income as they occur and included in other income (expense) on our consolidated
statements of operations. We estimate the fair values of swap contracts based on the present value
of the difference in
26
exchange-quoted forward price curves and contractual settlement prices multiplied by notional
quantities. We use our internal valuations to determine the fair values of the contracts that are
reflected on our consolidated balance sheets. Realized gains and losses are also included in other
income (expense) on our consolidated statements of operations.
For the six months ended June 30, 2010, we recorded an unrealized gain on commodity
derivatives of $3.2 million, compared to an unrealized loss on commodity derivatives of $2.2
million for the six months ended June 30, 2009, from the change in fair value of our commodity
derivatives positions. A hypothetical 10% increase in commodity prices would have resulted in a
$1.1 million decrease in the fair value of our commodity derivative positions recorded on our
balance sheet at June 30, 2010, and a corresponding decrease in the unrealized gain on commodity
derivatives recorded on our consolidated statement of operations for the six months ended June 30,
2010.
|
|
|
Item 4. |
|
Controls and Procedures. |
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information
required to be disclosed in the reports we file under the Exchange Act is recorded, processed,
summarized and reported within the time periods specified in the SECs rules and forms. Such
controls include those designed to ensure that information required to be disclosed by us in the
reports that we file or submit under the Exchange Act is accumulated and communicated to
management, including the President and Chief Executive Officer (CEO) and Chief Financial Officer
(CFO), as appropriate, to allow timely decisions regarding required disclosure.
Our management, with the participation of our CEO and CFO, has evaluated the effectiveness of
our disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Exchange
Act) as of June 30, 2010. Based on this evaluation, the CEO and CFO have concluded that, as of June
30, 2010, our disclosure controls and procedures were effective, in that they ensure that
information required to be disclosed by us in the reports that we file or submit under the Exchange
Act is (1) recorded, processed, summarized and reported within the time periods specified in the
SECs rules and forms, and (2) accumulated and communicated to our management, including our CEO
and CFO, as appropriate to allow timely decisions regarding required disclosure.
Internal Control over Financial Reporting
There were no changes made in our internal control over financial reporting (as defined in
Rule 13a-15(f) promulgated under the Exchange Act) during the three months ended June 30, 2010,
that have materially affected, or are reasonably likely to materially affect, our internal control
over financial reporting.
Limitations Inherent in All Controls
Our management, including the CEO and CFO, recognizes that the disclosure controls and
procedures and internal controls (discussed above) cannot prevent all errors or all attempts at
fraud. Any controls system, no matter how well crafted and operated, can only provide reasonable,
and not absolute, assurance of achieving the desired control objectives. Because of the inherent
limitations in any control system, no evaluation or implementation of a control system can provide
complete assurance that all control issues and all possible instances of fraud have been or will be
detected.
|
|
|
Item 4T. |
|
Controls and Procedures. |
Not applicable.
27
PART IIOTHER INFORMATION
|
|
|
Item 1. |
|
Legal Proceedings. |
There have been no material developments in the legal proceedings described in Part I, Item 3.
Legal Proceedings of our Annual Report on Form 10-K for the year ended December 31, 2009, filed
with the SEC on March 12, 2010.
In addition to the other information set forth in this report, you should carefully consider
the risks discussed in the following reports that we have filed with the SEC, which risks could
materially affect our business, financial condition and results of operations: Annual Report on
Form 10-K for the year ended December 31, 2009, under the headings Items 1. and 2. Business and
Properties Markets and Customers; Competition; and Regulation, Item 1A. Risk Factors, and
Item 7A. Quantitative and Qualitative Disclosures about Market Risk filed with the SEC on March
12, 2010.
Except as provided below, there have been no material changes to the risk factors discussed in
our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on March
12, 2010, which is accessible on the SECs website at www.sec.gov and our website at
www.approachresources.com.
The adoption and implementation of new statutory and regulatory requirements for derivative
transactions could have an adverse impact on our ability to hedge risks associated with our
business.
The U.S. Congress has passed, and the President has signed into law, the Dodd-Frank Wall
Street Reform and Consumer Protection Act (the Act). The Act provides for new statutory and
regulatory requirements for derivative transactions, including oil and gas hedging transactions.
Certain transactions will be required to be cleared on exchanges, and cash collateral will be
required for these transactions. The Act provides for a potential exception from these clearing and
cash collateral requirements for commercial end-users, and it includes a number of defined terms
that will be used in determining how this exception applies to particular derivative transactions
and to the parties to those transactions. The Act requires the Commodities Futures and Trading
Commission (the CFTC) to promulgate rules to define these terms in detail, but we do not know the
definitions that the CFTC will actually promulgate or how these definitions will apply to us.
We enter into financial swaps from time to time in order to hedge against commodity price
uncertainty and enhance the predictability of cash flows from oil and gas sales. Depending on the
rules and definitions adopted by the CFTC, we might in the future be required to provide cash
collateral for our commodities hedging transactions. Posting of cash collateral could cause
significant liquidity issues for us by reducing our ability to use our cash for capital
expenditures or other corporate purposes. A requirement to post cash collateral could therefore
significantly reduce our ability to execute strategic hedges to reduce commodity price uncertainty
and thus protect cash flows.
We are at risk unless and until the CFTC adopts rules and definitions that confirm that
companies such as ourselves are not required to post cash collateral for our derivative hedging
contracts. In addition, even if we ourselves are not required to post cash collateral for our
derivative contracts, the banks and other derivatives dealers who are our contractual
counterparties will be required to comply with the Acts new requirements, and the costs of their
compliance will likely be passed on to customers such as ourselves, thus decreasing the benefits to
us of hedging transactions and reducing our profitability.
28
|
|
|
Item 2. |
|
Unregistered Sales of Equity Securities and Use of Proceeds. |
The following table provides information relating to our purchase of shares of our common
stock during the three months ended June 30, 2010. The repurchases reflect shares withheld upon
vesting of restricted stock under our 2007 Stock Incentive Plan to satisfy statutory minimum tax
withholding obligations.
ISSUER PURCHASES OF EQUITY SECURITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
|
|
|
|
|
(c) |
|
|
(d) |
|
|
|
Total |
|
|
(b) |
|
|
Total Number of |
|
|
Maximum Number of |
|
|
|
Number of |
|
|
Average |
|
|
Shares Purchased |
|
|
Shares that May Yet Be |
|
|
|
Shares |
|
|
Price Paid |
|
|
as Part of Publicly |
|
|
Purchased Under the |
|
Period |
|
Purchased |
|
|
Per Share |
|
|
Announced Plans |
|
|
Plans or Programs |
|
Month #1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
April 1, 2010 April 30, 2010 |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
Month #2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
May 1,
2010 May 31, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Month #3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 1,
2010 June 30, 2010 |
|
|
8,244 |
|
|
|
7.35 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
8,244 |
|
|
$ |
7.35 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Index to Exhibits following the signature page of this report for a description of the
exhibits furnished as part of this report.
29
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.
|
|
|
|
|
|
APPROACH RESOURCES INC.
|
|
Date: August 4, 2010 |
By: |
/s/ J. Ross Craft
|
|
|
|
J. Ross Craft |
|
|
|
President and Chief Executive Officer
(Principal Executive Officer) |
|
|
|
|
|
Date: August 4, 2010 |
By: |
/s/ Steve P. Smart
|
|
|
|
Steven P. Smart |
|
|
|
Executive Vice President and Chief Financial Officer
(Principal Financial and Chief Accounting Officer) |
|
|
Index to Exhibits
|
|
|
Exhibit |
|
|
Number |
|
Description of Exhibit |
3.1
|
|
Restated Certificate of Incorporation of Approach
Resources Inc. (filed as Exhibit 3.1 to the Companys
Quarterly Report on Form 10-Q filed December 13, 2007,
and incorporated herein by reference). |
3.2
|
|
Restated Bylaws of Approach Resources Inc. (filed as
Exhibit 3.2 to the Companys Quarterly Report on Form
10-Q filed December 13, 2007, and incorporated herein
by reference). |
4.1
|
|
Specimen Common Stock Certificate (filed as Exhibit
4.1 to the Companys Registration Statement on Form
S-1/A filed October 18, 2007 (File No. 333-144512) and
incorporated herein by reference). |
10.1
|
|
Amendment No. 8 dated as of May 3, 2010, to Credit
Agreement dated as of January 18, 2008, among Approach
Resources Inc., as Borrower, JPMorgan Chase Bank,
N.A., as Agent and Lender, The Frost National Bank,
BNP Paribas and KeyBank National Association, as
Lenders, Fortis Capital Corp., as Departing Lender and
Approach Oil & Gas Inc., Approach Oil & Gas (Canada)
Inc. and Approach Resources I, LP, as guarantors
(filed as Exhibit 10.1 to the Companys Current Report
on Form 8-K filed May 6, 2010, and incorporated herein
by reference). |
*23.1
|
|
Consent of DeGolyer and MacNaughton. |
*31.1
|
|
Certification by the President and Chief Executive
Officer Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002. |
*31.2
|
|
Certification by the Chief Financial Officer Pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002. |
*32.1
|
|
Certification by the President and Chief Executive
Officer Pursuant to 18 U.S.C. Section 1350, as adopted
Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002. |
*32.2
|
|
Certification by the Chief Financial Officer Pursuant
to U.S.C. Section 1350, as adopted Pursuant to Section
906 of the Sarbanes-Oxley Act of 2002. |
*99.1
|
|
Report of DeGolyer and MacNaughton. |