e10vq
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2011
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
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51-0424817 |
(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.) |
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One Ridgmar Centre
6500 West Freeway, Suite 800
Fort Worth, Texas
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76116 |
(Address of principal executive offices)
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(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).
þ 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, $0.01 par value, outstanding as of
October 31, 2011, was 28,441,142.
TABLE OF CONTENTS
PART I FINANCIAL INFORMATION
Item 1. Financial Statements.
Approach Resources Inc. and Subsidiaries
Unaudited Consolidated Balance Sheets
(In thousands, except shares and per-share amounts)
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September 30, |
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December 31, |
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2011 |
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2010 |
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ASSETS |
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CURRENT ASSETS: |
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Cash and cash equivalents |
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$ |
736 |
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$ |
23,465 |
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Accounts receivable: |
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Joint interest owners |
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241 |
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8,319 |
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Oil, NGL and gas sales |
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9,995 |
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6,044 |
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Unrealized gain on commodity derivatives |
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2,802 |
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862 |
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Prepaid expenses and other current assets |
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273 |
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322 |
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Deferred income taxes current |
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1,307 |
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2,318 |
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Total current assets |
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15,354 |
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41,330 |
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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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687,452 |
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474,917 |
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Furniture, fixtures and equipment |
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1,601 |
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1,077 |
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689,053 |
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475,994 |
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Less accumulated depletion, depreciation and amortization |
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(128,986 |
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(106,784 |
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Net properties and equipment |
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560,067 |
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369,210 |
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OTHER ASSETS |
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1,103 |
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2,549 |
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Total assets |
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$ |
576,524 |
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$ |
413,089 |
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LIABILITIES AND STOCKHOLDERS EQUITY |
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CURRENT LIABILITIES: |
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Advances from non-operators |
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$ |
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$ |
509 |
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Accounts payable |
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22,696 |
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11,426 |
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Oil, NGL and gas sales payable |
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3,844 |
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5,534 |
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Accrued liabilities |
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15,834 |
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10,686 |
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Unrealized loss on commodity derivatives |
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1,085 |
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Total current liabilities |
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42,374 |
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29,240 |
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NON-CURRENT LIABILITIES: |
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Long-term debt |
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122,000 |
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Unrealized loss on commodity derivatives |
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75 |
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871 |
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Deferred income taxes |
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52,727 |
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44,616 |
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Asset retirement obligations |
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6,509 |
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5,416 |
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Total liabilities |
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223,685 |
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80,143 |
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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, $0.01 par value, 90,000,000 shares authorized, 28,439,109 and
28,226,890 issued and outstanding, respectively |
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284 |
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282 |
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Additional paid-in capital |
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277,303 |
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273,912 |
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Retained earnings |
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75,512 |
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58,986 |
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Accumulated other comprehensive loss |
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(260 |
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(234 |
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Total stockholders equity |
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352,839 |
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332,946 |
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Total liabilities and stockholders equity |
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$ |
576,524 |
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$ |
413,089 |
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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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Nine Months Ended |
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September 30, |
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September 30, |
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2011 |
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2010 |
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2011 |
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2010 |
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REVENUES: |
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Oil, NGL and gas sales |
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$ |
27,958 |
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$ |
14,916 |
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$ |
77,264 |
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$ |
41,291 |
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EXPENSES: |
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Lease operating |
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3,564 |
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1,995 |
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9,820 |
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6,038 |
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Severance and production taxes |
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1,419 |
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743 |
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4,223 |
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2,047 |
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Exploration |
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1,969 |
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568 |
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6,877 |
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2,245 |
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General and administrative |
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3,785 |
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3,212 |
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11,878 |
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7,902 |
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Depletion, depreciation and amortization |
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8,355 |
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5,832 |
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22,394 |
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16,677 |
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Total expenses |
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19,092 |
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12,350 |
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55,192 |
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34,909 |
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OPERATING INCOME |
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8,866 |
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2,566 |
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22,072 |
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6,382 |
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OTHER: |
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Interest expense, net |
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(1,016 |
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(615 |
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(2,391 |
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(1,631 |
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Realized gain on commodity derivatives |
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1,392 |
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1,615 |
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1,654 |
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3,613 |
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Unrealized gain (loss) on commodity derivatives |
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1,739 |
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(312 |
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3,821 |
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2,882 |
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Gain on sale of oil and gas properties |
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491 |
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INCOME BEFORE INCOME TAX PROVISION |
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10,981 |
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3,254 |
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25,647 |
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11,246 |
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INCOME TAX PROVISION |
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3,908 |
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1,167 |
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9,121 |
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4,045 |
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NET INCOME |
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$ |
7,073 |
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$ |
2,087 |
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$ |
16,526 |
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$ |
7,201 |
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EARNINGS PER SHARE: |
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Basic |
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$ |
0.25 |
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$ |
0.10 |
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$ |
0.58 |
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$ |
0.34 |
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Diluted |
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$ |
0.25 |
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$ |
0.10 |
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$ |
0.58 |
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$ |
0.34 |
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WEIGHTED AVERAGE SHARES OUTSTANDING: |
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Basic |
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28,440,909 |
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21,357,682 |
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28,398,152 |
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21,139,089 |
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Diluted |
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28,652,211 |
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21,484,465 |
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28,628,074 |
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21,265,794 |
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See accompanying notes to these consolidated financial statements.
2
Approach Resources Inc. and Subsidiaries
Unaudited Consolidated Statements of Comprehensive Income
(In thousands)
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Three Months Ended |
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Nine Months Ended |
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September 30, |
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September 30, |
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2011 |
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2010 |
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2011 |
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2010 |
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Net income |
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$ |
7,073 |
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$ |
2,087 |
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$ |
16,526 |
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$ |
7,201 |
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Other comprehensive income (loss): |
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Foreign currency translation, net of related income tax |
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(24 |
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(3 |
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(26 |
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(3 |
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Total comprehensive income |
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$ |
7,049 |
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$ |
2,084 |
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$ |
16,500 |
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$ |
7,198 |
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See accompanying notes to these consolidated financial statements.
3
Approach Resources Inc. and Subsidiaries
Unaudited Consolidated Statements of Cash Flows
(In thousands)
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Nine Months Ended |
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September 30, |
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2011 |
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2010 |
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OPERATING ACTIVITIES: |
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Net income |
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$ |
16,526 |
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$ |
7,201 |
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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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22,394 |
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16,677 |
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Unrealized gain on commodity derivatives |
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(3,821 |
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(2,882 |
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Gain on sale of oil and gas properties |
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(491 |
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Exploration expense |
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6,877 |
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2,245 |
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Share-based compensation expense |
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3,637 |
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2,043 |
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Deferred income taxes |
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9,121 |
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3,974 |
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Changes in operating assets and liabilities: |
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Accounts receivable |
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6,171 |
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(5,053 |
) |
Prepaid expenses and other assets |
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327 |
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477 |
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Accounts payable |
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10,011 |
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4,182 |
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Oil, NGL and gas sales payable |
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(1,690 |
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2,298 |
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Accrued liabilities |
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5,152 |
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1,293 |
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Cash provided by operating activities |
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74,214 |
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32,455 |
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INVESTING ACTIVITIES: |
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Additions to oil and gas properties |
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(218,385 |
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(52,385 |
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Proceeds from gain on sale of oil and gas properties, net |
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363 |
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Additions to other property and equipment, net |
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(524 |
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(730 |
) |
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Cash used in investing activities |
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(218,546 |
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(53,115 |
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FINANCING ACTIVITIES: |
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Proceeds from issuance of common stock upon exercise of
stock options |
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505 |
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Borrowings under credit facility |
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169,200 |
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81,400 |
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Repayment of amounts outstanding under credit facility |
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(47,200 |
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(62,650 |
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Loan origination fees |
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(875 |
) |
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(354 |
) |
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Cash provided by financing activities |
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121,630 |
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18,396 |
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CHANGE IN CASH AND CASH EQUIVALENTS |
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(22,702 |
) |
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(2,264 |
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EFFECT OF FOREIGN CURRENCY TRANSLATION ON CASH AND CASH
EQUIVALENTS |
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(27 |
) |
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(4 |
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CASH AND CASH EQUIVALENTS, beginning of period |
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$ |
23,465 |
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$ |
2,685 |
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CASH AND CASH EQUIVALENTS, end of period |
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$ |
736 |
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$ |
417 |
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SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: |
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Cash paid for interest |
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$ |
2,340 |
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$ |
1,524 |
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|
See accompanying notes to these consolidated financial statements.
4
Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements (Unaudited)
September 30, 2011
1. Summary of Significant Accounting Policies
Organization and Nature of Operations
Approach Resources Inc. (Approach, the Company, we, us or our) is an independent
energy company engaged in the exploration, development, production and acquisition of oil and gas
properties. We focus on finding and developing oil and natural gas reserves in oil shale and tight
sands. Our properties are primarily located in the Permian Basin in West Texas. We also own
interests in the East Texas Basin and the Chama Basin in Northern New Mexico.
During the nine months ended September 30, 2011, we sold our working interest in Northeast
British Columbia for net proceeds of $363,000. The gain on the sale of this interest was $491,000,
and is included under Other on the consolidated statement of operations for the nine months ended
September 30, 2011. Our carrying value and associated plugging obligations related to Northeast
British Columbia previously were written off as an impairment of unproved properties during the
year ended December 31, 2009.
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, 2010, filed with the Securities and Exchange Commission on March 11,
2011.
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.
5
Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements (Unaudited)
September 30, 2011
2. Working Interest Acquisition
In February 2011, we acquired an additional 38% working interest in our Cinco Terry operating
area from two non-operating partners for $76 million, subject to customary post-closing adjustments
(the Working Interest Acquisition). We funded the Working Interest Acquisition with cash on hand
and borrowings under our revolving credit facility.
The following table summarizes the preliminary purchase price paid and its allocation at
September 30, 2011 (in thousands).
|
|
|
|
|
Purchase price: |
|
|
|
|
Acquisition price |
|
$ |
76,000 |
|
Asset retirement obligations assumed |
|
|
547 |
|
Post-closing purchase price adjustments |
|
|
(6,366 |
) |
|
|
|
|
Total |
|
$ |
70,181 |
|
|
|
|
|
Allocation: |
|
|
|
|
Wells, equipment and related facilities |
|
$ |
50,979 |
|
Mineral interests in oil and gas properties |
|
|
19,202 |
|
|
|
|
|
Total |
|
$ |
70,181 |
|
|
|
|
|
3. 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 table provides a
reconciliation of the numerators and denominators of our basic and diluted earnings per share
(dollars in thousands, except per-share amounts).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Income (numerator): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income basic |
|
$ |
7,073 |
|
|
$ |
2,087 |
|
|
$ |
16,526 |
|
|
$ |
7,201 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares (denominator): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares basic |
|
|
28,440,909 |
|
|
|
21,357,682 |
|
|
|
28,398,152 |
|
|
|
21,139,089 |
|
Dilution effect of share-based
compensation, treasury method |
|
|
211,302 |
|
|
|
126,783 |
|
|
|
229,922 |
|
|
|
126,705 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares diluted |
|
|
28,652,211 |
|
|
|
21,484,465 |
|
|
|
28,628,074 |
|
|
|
21,265,794 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.25 |
|
|
$ |
0.10 |
|
|
$ |
0.58 |
|
|
$ |
0.34 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
0.25 |
|
|
$ |
0.10 |
|
|
$ |
0.58 |
|
|
$ |
0.34 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4. Revolving Credit Facility
At September 30, 2011, we had a $300 million revolving credit facility with a borrowing base
set at $200 million. The borrowing base is redetermined semi-annually on or before each April 1
and
October 1 based on our oil, NGL and gas reserves. We or the lenders can each request one
additional borrowing base redetermination each calendar year.
6
Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements (Unaudited)
September 30, 2011
The maturity date under our revolving credit facility is July 31, 2014. Borrowings bear
interest based on the agent banks prime rate plus an applicable margin ranging from 0.75% to
1.75%, or the sum of the Eurodollar rate plus an applicable margin ranging from 1.75% to 2.75%.
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 October 7, 2011, we entered into an eleventh amendment to our credit agreement,
which, among other things, (i) increased the borrowing base to $260 million from $200 million, and
(ii) added Wells Fargo Bank, N.A. as a sixth lender to the bank syndicate.
We had outstanding borrowings of $122 million under our revolving credit facility at September
30, 2011. We had no outstanding borrowings at December 31, 2010. The interest rate applicable to
our revolving credit facility at September 30, 2011, was 2.8%. We also had outstanding unused
letters of credit under our revolving credit facility totaling $350,000 at September 30, 2011,
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 4.0 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 (x) gains or losses from sales or dispositions of assets, (y) unrealized
gain on commodity derivatives and (z) 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.
7
Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements (Unaudited)
September 30, 2011
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 September 30, 2011, we were in compliance with all of our covenants and had not committed
any acts of default under the credit agreement.
5. Commitments and Contingencies
In August 2011, we settled all claims with EnCana Oil & Gas (USA) Inc. (EnCana) arising out
of Approach Operating, LLC v. EnCana Oil & Gas (USA) Inc., Cause No. 29.070A, District Court of
Limestone County, Texas. As previously disclosed, on July 2, 2009, our operating subsidiary filed
a lawsuit against EnCana for breach of the joint operating agreement (JOA) covering our North
Bald Prairie project in East Texas and seeking damages for nonpayment of amounts owed under the JOA
as well as declaratory relief. As part of the release and settlement of all claims by both
parties, EnCana paid us $1.4 million. In addition, we will remain operator of the North Bald
Prairie project, subject to the terms of the JOA.
We are involved in various 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.
We have entered into an 18-month contract for a dedicated, third-party fracture stimulation
fleet, effective September 1, 2011. The contract requires a minimum commitment of $3 million per
month for the contract term. The contract contains customary, early termination provisions for a
monthly fee of less than the minimum monthly commitment in the event of a termination before the
end of the contract term.
6. Income Taxes
The effective income tax rate for the three and nine months ended September 30, 2011, was
35.6%. Total income tax expense for the three and nine months ended September 30, 2011, differed
from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due
primarily to state taxes and the impact of permanent differences between book and taxable income.
The effective income tax rate for the three and nine months ended September 30, 2010, was
35.9% and 36.0%, respectively. Total income tax expense for the three and nine months ended
September 30, 2010, differed from amounts computed by applying the U.S. federal statutory tax rates
to pre-tax income due to the impact of permanent differences between book and taxable income.
8
Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements (Unaudited)
September 30, 2011
7. Derivatives
The following table sets forth our commodity derivative volumes and prices for 2011 and 2012.
|
|
|
|
|
|
|
|
|
|
|
|
|
Period |
|
Contract Type |
|
|
Volume Transacted |
|
Contract Price |
|
Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
|
2011 |
|
Swap |
|
230,000 MMBtu/month |
|
$ |
4.86 |
|
June 2011 December 2011 |
|
Swap |
|
200,000 MMBtu/month |
|
$ |
4.74 |
|
2012 |
|
Call |
|
230,000 MMBtu/month |
|
$ |
6.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Basis Differential |
|
|
|
|
|
|
|
|
|
|
|
|
2011 |
|
Swap |
|
300,000 MMBtu/month |
|
$ |
(0.53 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
|
|
|
|
|
|
|
|
|
|
|
|
May 2011 December 2011 |
|
Collar |
|
1,000 Bbls/day |
|
$ |
100.00 - $127.00 |
|
In October 2011, we added to its 2012 commodity derivatives positions with a crude oil
collar contract covering 700 Bbls/d at a contract price of $85.00/Bbl $97.50/Bbl.
The following table summarizes the fair value of our open commodity derivatives as of
September 30, 2011, and December 31, 2010 (in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Derivatives |
|
|
Liability Derivatives |
|
|
|
|
|
|
|
Fair Value |
|
|
|
|
|
|
Fair Value |
|
|
|
Balance Sheet |
|
|
September 30, |
|
|
December 31, |
|
|
Balance Sheet |
|
|
September 30, |
|
|
December 31, |
|
|
|
Location |
|
|
2011 |
|
|
2010 |
|
|
Location |
|
|
2011 |
|
|
2010 |
|
Derivatives not
designated as
hedging instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives |
|
Unrealized gain on commodity derivatives |
|
$ |
2,802 |
|
|
$ |
862 |
|
|
Unrealized loss on commodity derivatives |
|
$ |
75 |
|
|
$ |
1,956 |
|
The following table summarizes the change in the fair value of our commodity derivatives
(in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
Income Statement |
|
|
September 30, |
|
|
September 30, |
|
|
|
Location |
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Derivatives not designated
as hedging instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives |
|
Realized gain on commodity derivatives |
|
$ |
1,392 |
|
|
$ |
1,615 |
|
|
$ |
1,654 |
|
|
$ |
3,613 |
|
|
|
Unrealized gain (loss) on
commodity derivatives |
|
|
1,739 |
|
|
|
(312 |
) |
|
|
3,821 |
|
|
|
2,882 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
3,131 |
|
|
$ |
1,303 |
|
|
$ |
5,475 |
|
|
$ |
6,495 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9
Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements (Unaudited)
September 30, 2011
Unrealized gains and losses, at fair value, are included on our consolidated balance
sheets as current or non-current 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 earnings 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 internally valued the option contracts using
industry-standard option pricing models and observable market inputs. 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.
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 September 30, 2011, 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 and collars, 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 September 30, 2011, 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 September
30, 2011, our Level 3 measurements were limited to our asset retirement obligation. |
10
Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements (Unaudited)
September 30, 2011
8. Share-Based Compensation
During the nine months ended September 30, 2011, we made a grant of 204,000 restricted shares of
common stock to our executive officers. The total fair market value of these shares on the grant
date was approximately $6.5 million, which will be expensed over a service period of approximately
four years, subject to certain performance measures. We recognized $1.8 million in share-based
compensation expense related to this grant during the nine months ended September 30, 2011.
11
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, 2010,
filed with the Securities and Exchange Commission (SEC) on March 11, 2011. 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.
Cautionary Statement Regarding Forward-Looking 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, potential 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 or referred to 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:
|
|
|
our business strategy, including our ability to recover oil and gas in place
associated with our Wolffork oil resource play in the Permian Basin; |
|
|
|
estimated quantities of oil, NGL and gas reserves; |
|
|
|
uncertainty of commodity prices in oil, gas and NGLs; |
|
|
|
overall United States and global economic and financial market conditions; |
|
|
|
domestic and foreign demand and supply for oil, gas, NGLs and the products derived
from such hydrocarbons; |
|
|
|
|
disruption of credit and capital markets; |
12
|
|
|
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; |
|
|
|
uncertainties in exploring for and producing oil and gas; |
|
|
|
high costs, shortages, delivery delays or unavailability of drilling and completion,
equipment, materials, 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,
including limited availability of oil hauling trucks in the Permian Basin, our primary
area of operation; |
|
|
|
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; |
|
|
|
development 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, 2010, filed with the SEC on March 11, 2011, and in this Quarterly Report
on Form 10-Q for the three months ended September 30, 2011. |
13
Overview
Approach Resources Inc. (Approach, the Company, we, us or our) is an independent
energy company engaged in the exploration, development, production and acquisition of oil and gas
properties. We focus on oil and natural gas reserves in oil shale and tight sands. Our management
and technical team has a proven track record of finding and developing reservoirs through advanced
completion, fracturing and drilling techniques. Our core properties are primarily located in the
Permian Basin in West Texas (Clearfork, Wolfcamp Shale, Canyon Sands, Strawn and Ellenburger). We
also own interests in the East Texas Basin (Cotton Valley Sands and Cotton Valley Lime) and in the
Chama Basin in Northern New Mexico (Mancos Shale). As the operator of all of our estimated proved
reserves and production, we have a high degree of control over capital expenditures and other
operating matters.
At June 30, 2011, we had estimated proved oil and gas reserves of 66.8 MMBoe. Our reserve
base is 55% oil and NGLs, 45% natural gas and 50% proved developed. Over 97% of our proved
reserves and production are located in the Permian Basin in Crockett and Schleicher Counties,
Texas. Our acreage position in the Permian Basin totals approximately 142,000 net, primarily
contiguous acres and is characterized by multiple oil and liquids-rich formations. Our 2011
drilling program includes operating three rigs to target the Wolffork, the Wolfcamp Shale and the
Canyon Sands and deeper zones. We refer to our drilling program in the Permian Basin as Project
Pangea and Pangea West.
Third Quarter of 2011 Activity
During the third quarter of 2011, we drilled a total of 20 gross (20 net) wells, completed 14
gross (14 net) wells and recompleted four gross (four net) wells. Through September 30, 2011, we
drilled 52 gross (47.3 net) wells, completed 49 gross (42.7 net) wells and recompleted six gross
(six net) wells. At September 30, 2011, we had 10 wells waiting on completion. We currently have
one horizontal rig and two vertical rigs running in Project Pangea. At September 30, 2011, we
owned working interests in approximately 613 producing oil and gas wells.
14
Results of Operations
The following table sets forth summary information regarding oil, NGL and gas revenues,
production, average product prices and average production costs and expenses for the three and nine
months ended September 30, 2011 and 2010. We determined the barrel of oil equivalent using the
ratio of six Mcf of natural gas to one barrel of oil equivalent, and one barrel of NGLs to one
barrel of oil equivalent.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Revenues (in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
9,568 |
|
|
$ |
5,135 |
|
|
$ |
27,792 |
|
|
$ |
12,630 |
|
NGLs |
|
|
12,128 |
|
|
|
2,565 |
|
|
|
29,416 |
|
|
|
6,899 |
|
Gas |
|
|
6,262 |
|
|
|
7,216 |
|
|
|
20,056 |
|
|
|
21,762 |
|
|
|
|
|
|
Total oil, NGL and gas sales |
|
|
27,958 |
|
|
|
14,916 |
|
|
|
77,264 |
|
|
|
41,291 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized gain on commodity derivatives |
|
|
1,392 |
|
|
|
1,615 |
|
|
|
1,654 |
|
|
|
3,613 |
|
|
|
|
|
|
Total oil, NGL and gas sales
including derivative impact |
|
$ |
29,350 |
|
|
$ |
16,531 |
|
|
$ |
78,918 |
|
|
$ |
44,904 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
117 |
|
|
|
71 |
|
|
|
310 |
|
|
|
172 |
|
NGLs (MBbls) |
|
|
233 |
|
|
|
70 |
|
|
|
574 |
|
|
|
174 |
|
Gas (MMcf) |
|
|
1,569 |
|
|
|
1,664 |
|
|
|
4,829 |
|
|
|
4,646 |
|
|
|
|
|
|
Total (MBoe) |
|
|
612 |
|
|
|
418 |
|
|
|
1,689 |
|
|
|
1,120 |
|
Total (MBoe/d) |
|
|
6.7 |
|
|
|
4.5 |
|
|
|
6.2 |
|
|
|
4.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
81.51 |
|
|
$ |
72.19 |
|
|
$ |
89.63 |
|
|
$ |
73.41 |
|
NGLs (per Bbl) |
|
|
52.08 |
|
|
|
36.65 |
|
|
|
51.26 |
|
|
|
39.64 |
|
Gas (per Mcf) |
|
|
3.99 |
|
|
|
4.34 |
|
|
|
4.15 |
|
|
|
4.68 |
|
|
|
|
|
|
Total (per Boe) |
|
$ |
45.70 |
|
|
$ |
35.68 |
|
|
$ |
45.75 |
|
|
$ |
36.87 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized gain on commodity derivatives (per
Boe) |
|
|
2.28 |
|
|
|
3.86 |
|
|
|
0.98 |
|
|
|
3.22 |
|
|
|
|
|
|
Total including derivative impact
(per Boe) |
|
$ |
47.98 |
|
|
$ |
39.54 |
|
|
$ |
46.73 |
|
|
$ |
40.09 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses (per Boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating (1) |
|
$ |
5.82 |
|
|
$ |
4.77 |
|
|
$ |
5.81 |
|
|
$ |
5.39 |
|
Severance and production taxes |
|
|
2.32 |
|
|
|
1.78 |
|
|
|
2.50 |
|
|
|
1.83 |
|
Exploration |
|
|
3.22 |
|
|
|
1.36 |
|
|
|
4.07 |
|
|
|
2.00 |
|
General and administrative |
|
|
6.18 |
|
|
|
7.68 |
|
|
|
7.03 |
|
|
|
7.06 |
|
Depletion, depreciation and amortization |
|
|
13.65 |
|
|
|
13.95 |
|
|
|
13.26 |
|
|
|
14.89 |
|
|
|
|
(1) |
|
Lease operating expense per Boe includes ad valorem taxes. |
Glossary
Bbl. One stock tank barrel, of 42 U.S. gallons liquid volume, used herein to reference oil,
condensate or NGLs.
Boe. Barrel of oil equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil
equivalent, and one Bbl of NGLs to on Bbl of oil equivalent.
MBbl. Thousand barrels of oil, condensate or NGLs.
MBoe. Thousand barrels of oil equivalent, determined using the ratio of six Mcf of gas to one Bbl
of oil equivalent, and one Bbl of NGLs to one Bbl of oil equivalent.
15
Mcf. Thousand cubic feet of natural gas.
MMBoe. Million barrels of oil equivalent, determined using the ratio of six Mcf of gas to one Bbl
of oil equivalent, and one Bbl of NGLs to one Bbl of oil equivalent.
MMcf. Million cubic feet of natural gas.
NGLs. Natural gas liquids.
/d. Per day when used with volumetric units or dollars.
Three Months Ended September 30, 2011, Compared to Three Months Ended September 30, 2010
Oil, NGL and gas sales. Oil, NGL and gas sales increased $13.1 million, or 87%, for the three
months ended September 30, 2011, to $28 million, from $14.9 million for the three months ended
September 30, 2010. Of the $13.1 million increase in oil, NGL and gas sales, approximately $11.9
million was attributable to an increase in oil and NGL production volumes and $1.2 million was
attributable to an increase in oil and NGL prices. Subject to commodity prices, we expect our 2011
oil, NGL and gas sales to continue to increase over 2010 prior periods due to increased production
volumes from our drilling program in the Permian Basin, the acquisition of additional working
interest in northwest Project Pangea in first quarter 2011 (the Working Interest Acquisition) and
realization of NGL revenues in Ozona Northeast resulting from a gas purchase and processing
contract that provides for the sale of NGLs from the gas stream in the southeast portion of Project
Pangea.
Our average realized prices for the three months ended September 30, 2011, before the effect
of commodity derivatives, were $81.51 per Bbl of oil, $52.08 per Bbl of NGLs and $3.99 per Mcf of
natural gas, compared to $72.19 per Bbl of oil, $36.65 per Bbl of NGLs and $4.34 per Mcf of natural
gas, for the three months ended September 30, 2010. Our average realized price, including the
effect of commodity derivatives, was $47.98 per Boe for the three months ended September 30, 2011,
compared to $39.54 per Boe for the three months ended September 30, 2010. The regional index
prices that we use to price our oil, NGL and gas sales sometimes reflect a discount to the relevant
benchmark prices, such as New York Mercantile Exchange (NYMEX) and West Texas Intermediate
(WTI). The difference between the benchmark price and the price we reference in our sales
contacts is called a differential. We currently expect our 2011 oil price differential to increase
over 2010 prior periods due to increased activity levels in the Permian Basin and a shortage of oil
haulers in the region.
Oil, NGL and gas production. Production for the three months ended September 30, 2011,
totaled 612 MBoe (6.7 MBoe/d), compared to 418 MBoe (4.5 MBoe/d) produced in the prior year period,
an increase of 46%. Production for the three months ended September 30, 2011, was 57% oil and NGLs
and 43% natural gas, compared to 34% oil and NGLs and 66% natural gas in the prior year period.
The increase in production in the 2011 period is the result of our continued development of our
Permian Basin properties, the Working Interest Acquisition and processing NGLs in the southeast
portion of Project Pangea; however, production was impacted during the three months ended September
30, 2011, by oil takeaway constraints due to increased industry activity in the Permian Basin and a
shortage of oil trucking capacity. We expect 2011 production to continue to increase over 2010
prior periods due to the Working Interest Acquisition, our expected drilling program in the Permian
Basin and the processing of NGLs from the gas stream in the southeast portion of Project Pangea.
Commodity derivative activities. Our commodity derivative activity resulted in a realized gain
of $1.4 million and $1.6 million for the three months ended September 30, 2011, and 2010,
respectively. Realized gains and losses on commodity derivatives are derived from the relative
movement of
commodity prices in relation to the fixed notional pricing in our price collars, options and
swaps for the applicable periods. The unrealized gain on commodity derivatives was $1.7 million
for the three months
16
ended September 30, 2011, compared to an unrealized loss of $312,000 for the
three months ended September 30, 2010. As commodity prices increase, the fair value of the open
portion of those positions decreases. As 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 gain (loss) on commodity derivatives.
Lease operating expenses. Our lease operating expenses (LOE) increased $1.6 million, or 79%,
for the three months ended September 30, 2011, to $3.6 million ($5.82 per Boe) from $2 million
($4.77 per Boe) for the three months ended September 30, 2010. The increase in LOE for the three
months ended September 30, 2011, was primarily attributable to the Working Interest Acquisition.
In February 2011, we acquired the remaining 38% working interest in northern Project Pangea, which
increased our working interest to approximately 100%. We also experienced an increase in water
hauling, insurance and repair and maintenance expenses as well as generally higher service costs.
For the remainder of 2011, we expect LOE to continue to be higher compared to the prior year
period.
The following table summarizes LOE (per Boe).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
|
|
|
|
|
|
September 30, |
|
|
|
|
|
|
|
|
|
2011 |
|
|
2010 |
|
|
Change |
|
|
% Change |
|
Compression and gas treating |
|
$ |
1.33 |
|
|
$ |
1.42 |
|
|
$ |
(0.09 |
) |
|
|
(6.3 |
)% |
Water hauling, insurance and other |
|
|
1.32 |
|
|
|
1.07 |
|
|
|
0.25 |
|
|
|
23.4 |
|
Well repairs and maintenance |
|
|
1.15 |
|
|
|
0.41 |
|
|
|
0.74 |
|
|
|
180.5 |
|
Ad valorem taxes |
|
|
1.13 |
|
|
|
1.05 |
|
|
|
0.08 |
|
|
|
7.6 |
|
Pumping and supervision |
|
|
0.89 |
|
|
|
0.82 |
|
|
|
0.07 |
|
|
|
8.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
5.82 |
|
|
$ |
4.77 |
|
|
$ |
1.05 |
|
|
|
22.0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Severance and production taxes. Our severance and production taxes increased $676,000, or
91%, for the three months ended September 30, 2011, to $1.4 million from $743,000 for the three
months ended September 30, 2010. The increase in severance and production taxes was primarily the
result of an increase in oil, NGL and gas sales between the two periods. Severance and production
taxes were approximately 5.1% and 5.0% of oil, NGL and gas sales for the respective periods. For
the remainder of 2011, we expect severance and production taxes as a percent of oil, NGL and gas
sales will remain relatively consistent compared to the severance and production taxes for the nine
months ended September 30, 2011.
Exploration. We recorded $2 million ($3.22 per Boe) and $568,000 ($1.36 per Boe) of
exploration expense for the three months ended September 30, 2011 and 2010, respectively.
Exploration expense for the three months ended September 30, 2011 and 2010, includes costs related
to 3-D seismic data in Pangea West and Project Pangea.
General and administrative. Our general and administrative expenses (G&A) increased
$573,000, or 18%, to $3.8 million ($6.18 per Boe) for the three months ended September 30, 2011,
from $3.2 million ($7.68 per Boe) for the three months ended September 30, 2010. The increase in
G&A was principally due to salaries and benefits. The decrease in G&A per Boe was primarily
attributable to an increase in production during the three months ended September 30, 2011,
compared to the three months
ended September 30, 2010. For 2011, we expect G&A to be higher, compared to 2010, as a result
of higher share-based compensation and staffing increases during 2010.
17
The following table summarizes G&A (in millions and per Boe).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
|
|
|
|
|
|
September 30, |
|
|
|
|
|
|
|
|
|
2011 |
|
|
2010 |
|
|
Change |
|
|
|
|
|
|
$MM |
|
|
Boe |
|
|
$MM |
|
|
Boe |
|
|
$MM |
|
|
Boe |
|
|
% Change |
|
Salaries and benefits |
|
$ |
1.6 |
|
|
$ |
2.59 |
|
|
$ |
1.1 |
|
|
$ |
2.57 |
|
|
$ |
0.5 |
|
|
$ |
0.02 |
|
|
|
0.8 |
% |
Share-based compensation |
|
|
1.1 |
|
|
|
1.78 |
|
|
|
1.1 |
|
|
|
2.74 |
|
|
|
|
|
|
|
(0.96 |
) |
|
|
(35.0 |
) |
Professional fees |
|
|
0.2 |
|
|
|
0.39 |
|
|
|
0.4 |
|
|
|
1.05 |
|
|
|
(0.2 |
) |
|
|
(0.66 |
) |
|
|
(62.9 |
) |
Other |
|
|
0.9 |
|
|
|
1.42 |
|
|
|
0.6 |
|
|
|
1.32 |
|
|
|
0.3 |
|
|
|
0.10 |
|
|
|
7.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
3.8 |
|
|
$ |
6.18 |
|
|
$ |
3.2 |
|
|
$ |
7.68 |
|
|
$ |
0.6 |
|
|
$ |
(1.50 |
) |
|
|
(19.5 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization. Our depletion, depreciation and amortization
expense (DD&A) increased $2.6 million, or 43%, to $8.4 million for the three months ended
September 30, 2011, from $5.8 million for the three months ended September 30, 2010. The increase
in DD&A expense over the prior year period was primarily due to an increase in capital expenditures
in the three months ended September 30, 2011. Our DD&A per Boe decreased by $0.30, or 2%, to
$13.65 per Boe for the three months ended September 30, 2011, compared to $13.95 per Boe for the
three months ended September 30, 2010. The decrease in DD&A per Boe was primarily attributable to
an increase in estimated proved developed reserves, partially offset by an increase in production
and capitalized costs over the prior year period.
Interest expense, net. Our interest expense, net, increased $401,000, or 65%, to $1 million
for the three months ended September 30, 2011, from $615,000 for the three months ended September
30, 2010. This increase was the result of a higher average debt level in the 2011 period. For the
remainder of 2011, we expect interest expense to continue to be higher compared to the prior year
period.
Income taxes. Our income taxes increased $2.7 million to $3.9 million for the three months
ended September 30, 2011, from $1.2 million for the three months ended September 30, 2010. The
increase in income taxes was due to higher net income in the 2011 period. Our effective income tax
rate for the three months ended September 30, 2011, was 35.6%, compared with 35.9% for the three
months ended September 30, 2010.
Nine Months Ended September 30, 2011, Compared to Nine Months Ended September 30, 2010
Oil, NGL and gas sales. Oil, NGL and gas sales increased $36 million, or 87%, for the nine
months ended September 30, 2011, to $77.3 million, from $41.3 million for the nine months ended
September 30, 2010. Of the $36 million increase in oil, NGL and gas sales, approximately $33.7
million was attributable to an increase in production volumes and $2.3 million was attributable to
an increase in oil and NGL prices. Subject to commodity prices, we expect our 2011 oil, NGL and
gas sales to continue to increase over 2010 prior periods due to increased production volumes from
our drilling program in the Permian Basin, the Working Interest Acquisition and realization of NGL
revenues in Ozona Northeast resulting from a gas purchase and processing contract that provides for
the sale of NGLs from the gas stream in the southeast portion of Project Pangea.
Our average realized prices for the nine months ended September 30, 2011, before the effect of
commodity derivatives, were $89.63 per Bbl of oil, $51.26 per Bbl of NGLs and $4.15 per Mcf of
natural gas, compared to $73.41 per Bbl of oil, $39.64 per Bbl of NGLs and $4.68 per Mcf of natural
gas, for the nine months ended September 30, 2010. Our average realized price, including the
effect of commodity derivatives, was $46.73 per Boe for the nine months ended September 30, 2011,
compared to $40.09 per
Boe for the nine months ended September 30, 2010. The regional index prices that we use to
price our
18
oil, NGL and gas sales sometimes reflect a discount to the relevant benchmark prices,
such as NYMEX and WTI. The difference between the benchmark price and the price we reference in
our sales contacts is called a differential. We currently expect our 2011 oil price differential
to increase over 2010 prior periods due to increased activity levels in the Permian Basin and a
shortage of oil haulers in the region.
Oil, NGL and gas production. Production for the nine months ended September 30, 2011, totaled
1,689 MBoe (6.2 MBoe/d), compared to 1,120 MBoe (4.1 MBoe/d) produced in the prior year period, an
increase of 51%. Production for the nine months ended September 30, 2011, was 52% oil and NGLs and
48% natural gas, compared to 31% oil and NGLs and 69% natural gas in the prior year period. The
increase in production in the 2011 period is the result of our continued development of our Permian
Basin properties, the Working Interest Acquisition and processing NGLs in the southeast portion of
Project Pangea; however, production was impacted during the nine months ended September 30, 2011,
by oil takeaway constraints due to increased industry activity in the Permian Basin and a shortage
of oil trucking capacity. We expect production to continue to increase during 2011 over 2010 prior
periods due to the Working Interest Acquisition, our expected drilling program in the Permian Basin
and the processing of NGLs from the gas stream in the southeast portion of Project Pangea.
Commodity derivative activities. Our commodity derivative activity resulted in a realized gain
of $1.7 million and $3.6 million for the nine months ended September 30, 2011, and 2010,
respectively. Realized gains and losses on commodity derivatives are derived from the relative
movement of commodity prices in relation to the fixed notional pricing in our price collars,
options and swaps for the applicable periods. The unrealized gain on commodity derivatives was
$3.8 million and $2.9 million for the nine months ended September 30, 2011 and 2010, respectively.
As commodity prices increase, the fair value of the open portion of those positions decreases. As
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 gain (loss) on
commodity derivatives.
Lease operating expenses. Our LOE increased $3.8 million, or 63%, for the nine months ended
September 30, 2011, to $9.8 million ($5.81 per Boe) from $6 million ($5.39 per Boe) for the nine
months ended September 30, 2010. The increase in LOE for the nine months ended September 30, 2011,
was primarily attributable to the Working Interest Acquisition. In February 2011, we acquired the
remaining 38% working interest in northern Project Pangea, which increased our working interest to
approximately 100%. We also experienced an increase in water hauling, insurance and other
expenses, as well as repair and maintenance expenses partially due to inclement winter weather in
southwest Texas during the nine months ended September 30, 2011. The increase in LOE was partially
offset by a decrease in compression and gas treating expense. For the remainder of 2011, we expect
LOE to continue to be higher compared to the prior year period.
19
The following table summarizes LOE (per Boe).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
|
|
|
|
|
|
September 30, |
|
|
|
|
|
|
|
|
|
2011 |
|
|
2010 |
|
|
Change |
|
|
% Change |
|
Water hauling, insurance and other |
|
$ |
1.31 |
|
|
$ |
1.16 |
|
|
$ |
0.15 |
|
|
|
12.9 |
% |
Compression and gas treating |
|
|
1.22 |
|
|
|
1.49 |
|
|
|
(0.27 |
) |
|
|
(18.1 |
) |
Ad valorem taxes |
|
|
1.19 |
|
|
|
1.18 |
|
|
|
0.01 |
|
|
|
0.8 |
|
Well repairs and maintenance |
|
|
1.12 |
|
|
|
0.60 |
|
|
|
0.52 |
|
|
|
86.7 |
|
Pumping and supervision |
|
|
0.97 |
|
|
|
0.96 |
|
|
|
0.01 |
|
|
|
1.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
5.81 |
|
|
$ |
5.39 |
|
|
$ |
0.42 |
|
|
|
7.8 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Severance and production taxes. Our severance and production taxes increased $2.2
million, or 106%, for the nine months ended September 30, 2011, to $4.2 million from $2 million for
the nine months ended September 30, 2010. The increase in severance and production taxes was
primarily a function of the increase in oil, NGL and gas sales between the two periods. Severance
and production taxes were approximately 5.5% and 5.0% of oil, NGL and gas sales for the respective
periods. For the remainder of 2011, we expect severance and production taxes as a percent of oil,
NGL and gas sales will remain relatively consistent compared to the nine months ended September 30,
2011.
Exploration. We recorded $6.9 million ($4.07 per Boe) and $2.2 million ($2.00 per Boe) of
exploration expense for the nine months ended September 30, 2011 and 2010, respectively.
Exploration expense for the nine months ended September 30, 2011, resulted primarily from lease
extensions and expirations in the Permian Basin and the acquisition of 3-D seismic data in Pangea
West. During the three months ended March 31, 2011, we extended the acreage terms for an
additional four years for approximately 9,200 acres in the northwest area of Project Pangea for
$3.2 million, or approximately $350 per acre. Further, approximately 5,000 acres in the southeast
area of Project Pangea expired during the three months ended March 31, 2011, resulting in
approximately $1.2 million of exploration expense. We expect exploration expense to increase from
2010 levels during the remainder of 2011 due to 3-D seismic activity in Pangea West and Project
Pangea. Exploration expense for the nine months ended September 30, 2010, resulted primarily from
our acquisition of 3-D seismic data across Cinco Terry.
General and administrative. Our G&A increased $4 million, or 50%, to $11.9 million ($7.03 per
Boe) for the nine months ended September 30, 2011, from $7.9 million ($7.06 per Boe) for the nine
months ended September 30, 2010. The increase in G&A was principally due to higher share-based
compensation, salaries and benefits and professional fees. As discussed in Note 8 to our financial
statements in this report, during the nine months ended September 30, 2011, we recognized $1.8
million in share-based compensation expense related to a grant of 204,000 restricted shares of
common stock to our executive officers. For 2011, we expect G&A to be higher, compared to 2010, as
a result of higher share-based compensation and staffing increases during 2010. Higher production
volumes during the nine months ended September 30, 2011, however, resulted in consistent G&A per
Boe, compared to the nine months ended September 30, 2010.
20
The following table summarizes G&A (in millions and per Boe).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
|
|
|
|
|
|
September 30, |
|
|
|
|
|
|
|
|
|
2011 |
|
|
2010 |
|
|
Change |
|
|
|
|
|
|
$MM |
|
|
Boe |
|
|
$MM |
|
|
Boe |
|
|
$MM |
|
|
Boe |
|
|
% Change |
|
Salaries and benefits |
|
$ |
4.5 |
|
|
$ |
2.63 |
|
|
$ |
3.3 |
|
|
$ |
2.90 |
|
|
$ |
1.2 |
|
|
$ |
(0.27 |
) |
|
|
(9.3 |
)% |
Share-based compensation |
|
|
3.6 |
|
|
|
2.15 |
|
|
|
2.0 |
|
|
|
1.82 |
|
|
|
1.6 |
|
|
|
0.33 |
|
|
|
18.1 |
|
Professional fees |
|
|
1.1 |
|
|
|
0.64 |
|
|
|
1.0 |
|
|
|
0.87 |
|
|
|
0.1 |
|
|
|
(0.23 |
) |
|
|
(26.4 |
) |
Other |
|
|
2.7 |
|
|
|
1.61 |
|
|
|
1.6 |
|
|
|
1.47 |
|
|
|
1.1 |
|
|
|
0.14 |
|
|
|
9.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
11.9 |
|
|
$ |
7.03 |
|
|
$ |
7.9 |
|
|
$ |
7.06 |
|
|
$ |
4.0 |
|
|
$ |
(0.03 |
) |
|
|
(0.4 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization. Our DD&A increased $5.7 million, or 34%, to
$22.4 million for the nine months ended September 30, 2011, from $16.7 million for the nine months
ended September 30, 2010. The increase in DD&A expense over the prior year period was primarily
due to an increase in capital expenditures in the nine months ended September 30, 2011. Our DD&A
per Boe decreased by $1.63, or 11%, to $13.26 per Boe for the nine months ended September 30, 2011,
compared to $14.89 per Boe for the nine months ended September 30, 2010. The decrease in DD&A per
Boe was primarily attributable to an increase in estimated proved developed reserves, partially
offset by an increase in production and capitalized costs over the prior year period.
Interest expense, net. Our interest expense, net, increased $760,000, or 47%, to $2.4 million
for the nine months ended September 30, 2011, from $1.6 million for the nine months ended September
30, 2010. This increase was the result of a higher average debt level in the 2011 period. For the
remainder of 2011, we expect interest expense to continue to be higher compared to the prior year
period.
Income taxes. Our income taxes increased $5.1 million, or 125%, to $9.1 million for the nine
months ended September 30, 2011, from $4 million for the nine months ended September 30, 2010. The
increase in income taxes was due to higher net income in the 2011 period. Our effective income tax
rate for the nine months ended September 30, 2011, was 35.6% compared with 36.0% for the nine
months ended September 30, 2010.
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 or private 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, availability of borrowings 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 operations are driven by commodity prices, production volumes and the
effect of commodity derivatives. 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. Cash flows from operations
are primarily used to fund exploration and development of our oil and gas properties.
21
We believe we have adequate liquidity from cash generated from operations and unused
borrowing capacity under our revolving credit facility for current working capital needs and
maintenance of our current drilling program. However, we may determine to access the public or
private equity or debt markets for future development of reserves, acquisitions, expansion of our
current drilling program, additional working capital, repayment of borrowings or other liquidity
needs, if such financing is available on acceptable terms. We cannot guarantee that financing will
be available on acceptable terms or at all.
Liquidity
We define liquidity as funds available under our revolving credit facility plus cash and cash
equivalents. At September 30, 2011, we had $122 million in long-term debt outstanding. We had no
long-term debt outstanding at December 31, 2010. Our liquidity was $78.4 million and $173.1
million at September 30, 2011 and December 31, 2010, respectively. Effective October 7, 2011, we
entered into an eleventh amendment to our credit agreement, which, among other things, increased
our borrowing base 30% to $260 million from $200 million. Including the increase in our borrowing
base, our liquidity would have been $138.4 million at September 30, 2011.
The table below summarizes our liquidity position at September 30, 2011 and December 31, 2010
(dollars in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquidity with Borrowing |
|
|
|
|
|
|
Base Increase at |
|
|
Liquidity at |
|
|
|
September 30, |
|
|
September 30, |
|
|
December 31, |
|
|
|
2011 |
|
|
2011 |
|
|
2010 |
|
Borrowing base |
|
$ |
260,000 |
|
|
$ |
200,000 |
|
|
$ |
150,000 |
|
Cash and cash equivalents |
|
|
736 |
|
|
|
736 |
|
|
|
23,465 |
|
Long-term debt |
|
|
(122,000 |
) |
|
|
(122,000 |
) |
|
|
|
|
Unused letters of credit |
|
|
(350 |
) |
|
|
(350 |
) |
|
|
(350 |
) |
|
|
|
|
|
|
|
|
|
|
Liquidity |
|
$ |
138,386 |
|
|
$ |
78,386 |
|
|
$ |
173,115 |
|
|
|
|
|
|
|
|
|
|
|
Working Capital
Our working capital is affected primarily by our cash and cash equivalents balance and our
capital expenditure program. We had a working capital deficit of $27 million at September 30,
2011, compared to a working capital surplus of $12.1 million at December 31, 2010. The primary
reason for the change in working capital was the use of cash to partially fund the Working Interest
Acquisition and an increase in accounts payable relating to expenditures for drilling and
development in our core operation area in the Permian Basin. As a result of the Working Interest
Acquisition and our planned capital expenditure budget for 2011, we expect to continue to operate
and end the year 2011 with a working capital deficit. Historically, our working capital deficits
have been substantially attributable to current payables and accrued liabilities and have been more
than offset by liquidity available under our revolving credit facility. To the extent we operate
or end the year 2011 with a working capital deficit, we expect such deficit to be more than offset
by liquidity available under our revolving credit facility.
22
Cash Flows
The following table summarizes our sources and uses of funds for the periods noted (in
thousands).
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
|
2011 |
|
|
2010 |
|
Cash flows provided by operating activities |
|
$ |
74,214 |
|
|
$ |
32,455 |
|
Cash flows used in investing activities |
|
|
(218,546 |
) |
|
|
(53,115 |
) |
Cash flows provided by financing activities |
|
|
121,630 |
|
|
|
18,396 |
|
Effect of Canadian exchange rate |
|
|
(27 |
) |
|
|
(4 |
) |
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents |
|
$ |
(22,729 |
) |
|
$ |
(2,268 |
) |
|
|
|
|
|
|
|
For the nine months ended September 30, 2011, our primary sources of cash were from
financing activities and operating activities. Approximately $121.6 million of cash from financing
activities and $74.2 million of cash from operations were used to fund a portion of our drilling
program.
Operating Activities
For the nine months ended September 30, 2011, our cash flows from operations, borrowings under
our revolving credit facility and available cash were used primarily for drilling activities and
leasehold acquisitions in our operating area in the Permian Basin. Cash flows from operating
activities increased by 129%, or $41.8 million, to $74.2 million from the 2010 period primarily due
to a 87% increase in oil, NGL and gas sales in the 2011 period.
Investing Activities
Cash flows used in investing activities increased by $165 million for nine months ended
September 30, 2011, compared to the 2010 period, which primarily reflects the acquisition of the
remaining 38% working interest in northern Project
Pangea for $70.2 million, net of purchase price adjustments,
and expenditures for drilling and lease acquisitions in our core operating area in the Permian
Basin.
Financing Activities
Proceeds from borrowings, net of debt issuance costs, were $168.3 million and $81 million,
respectively, under our revolving credit facility during the nine months ended September 30, 2011
and 2010, respectively. We repaid a total of $47.2 million and $62.7 million, respectively, of
amounts outstanding under our revolving credit facility during the nine months ended September 30,
2011 and 2010, respectively. In addition, in the nine months ended September 30, 2011, we realized
proceeds of $505,000 from the exercise of stock options.
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.
23
Capital Expenditures
2011 Capital Expenditures
Total capital expenditures in 2011 are expected to be $260 million, with approximately $160.7
million allocated to drilling and completion projects in the Permian Basin, approximately $70.2
million allocated to the acquisition of the remaining 38% working
interest in northern Project
Pangea, approximately $29.1 million allocated to lease acquisitions, extensions and renewals in the
Permian Basin, acquisition of 3-D seismic in Project Pangea and Pangea West, infrastructure and
other expenditures.
2012 Capital Expenditures
The Companys Board of Directors approved a 2012 capital budget of $160 million for drilling
and recompletions in the Permian Basin. The capital budget excludes acquisitions, and assumes an
activity level similar to the Companys 2011 program, including two vertical rigs, one horizontal
rig and four recompletions per month.
Our 2011 and 2012 capital budgets are subject to change depending upon a number of factors,
including economic and industry conditions at the time of drilling, prevailing and anticipated
prices for oil, NGLs and gas, the availability of sufficient capital resources for drilling
prospects, our financial results and the availability of lease extensions and renewals on
reasonable terms.
Revolving Credit Facility
At September 30, 2011, we had a $300 million revolving credit facility with a borrowing base
set at $200 million. The borrowing base is redetermined semi-annually on or before each April 1
and October 1 based on our oil, NGL 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, 2014. Borrowings bear
interest based on the agent banks prime rate plus an applicable margin ranging from 0.75% to
1.75%, or the sum of the Eurodollar rate plus an applicable margin ranging from 1.75% to 2.75%.
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 October 7, 2011, we entered into an eleventh amendment to our credit agreement,
which, among other things, (i) increased the borrowing base to $260 million from $200 million, and
(ii) added Wells Fargo Bank, N.A. as a sixth lender to the bank syndicate.
We had outstanding borrowings of $122 million under our revolving credit facility at September
30, 2011. We had no outstanding borrowings at December 31, 2010. The interest rate applicable to
our revolving credit facility at September 30, 2011, was 2.8%. We also had outstanding unused
letters of credit under our revolving credit facility totaling $350,000 at September 30, 2011,
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.
24
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 4.0 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 (x) gains or losses from sales or dispositions of assets, (y) unrealized
gain on commodity derivatives and (z) 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 September 30, 2011, 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 assigns to our
properties, using its discretion
and methodology, assumptions and discount rates as such lender customarily uses in evaluating
oil and gas properties.
25
Contractual Obligations
Our contractual obligations include long-term debt, daywork drilling contracts, service
contracts, operating lease obligations, asset retirement obligations and employment agreements with
our executive officers. Since December 31, 2010, there have been no material changes to our
contractual obligations other than, as discussed in Note 4 to our financial statements in this
report, an increase in outstanding borrowings under our credit agreement to $122 million at
September 30, 2011. In addition, as discussed in Note 5 to our financial statements in this
report, we have entered into an 18-month contract for a dedicated, third-party fracture stimulation
fleet, effective September 1, 2011. The contract requires a minimum commitment of $3 million per
month for the contract term. The contract contains customary, early termination provisions for a
monthly fee of less than the minimum monthly commitment in the event of a termination before the
end of the contract term.
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 September 30, 2011, 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 have or are
reasonably likely to have a current or future material effect on our financial condition, revenues
or expenses, results of operations, liquidity, capital expenditures or capital resources.
General Trends and Outlook
Our financial results depend upon many factors, particularly the price of oil, NGLs and gas.
Commodity prices are affected by changes in market demand, which is impacted by overall economic
activity, weather, pipeline capacity constraints, estimates of inventory storage levels, gas price
differentials and other factors. As a result, we cannot accurately predict future oil, NGL 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,
NGL 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 capital markets.
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, NGL 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 attempt to overcome this natural decline by drilling to
develop and identify additional reserves, farm-ins or other joint drilling ventures, and by
acquisitions. However, during times of severe price declines, we may from time to time reduce
current capital expenditures and curtail drilling operations in order to preserve liquidity. 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.
26
We also face the challenge of financing exploration, development and future acquisitions. We
believe we have adequate liquidity from cash generated from operations and unused borrowing
capacity under our revolving credit facility for current working capital needs and maintenance of
our current drilling program. However, we may determine to access the public or private equity or
debt markets for future development of reserves, acquisitions, expansion of our current drilling
program, additional working capital or other liquidity needs, if such financing is available on
acceptable terms. We cannot guarantee that such financing will be available on acceptable terms or
at all.
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
Given the current economic outlook, we expect commodity prices to remain volatile. 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, options and collars 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 other income (expense) on our consolidated statements of operations
as they occur.
The following table sets forth our commodity derivative volumes and prices for 2011 and 2012.
|
|
|
|
|
|
|
Period |
|
Contract Type |
|
Volume Transacted |
|
Contract Price |
Natural Gas |
|
|
|
|
|
|
2011 |
|
Swap |
|
230,000 MMBtu/month |
|
$4.86 |
June 2011 December 2011 |
|
Swap |
|
200,000 MMBtu/month |
|
$4.74 |
2012 |
|
Call |
|
230,000 MMBtu/month |
|
$6.00 |
|
|
|
|
|
|
|
Natural Gas Basis
Differential |
|
|
|
|
|
|
2011 |
|
Swap |
|
300,000 MMBtu/month |
|
$(0.53) |
|
|
|
|
|
|
|
Crude Oil |
|
|
|
|
|
|
May 2011 December 2011 |
|
Collar |
|
1,000 Bbls/day |
|
$100.00 - $127.00 |
In October 2011, we added to its 2012 commodity derivatives positions with a crude oil
collar contract covering 700 Bbls/d at a contract price of $85.00/Bbl $97.50/Bbl.
At September 30, 2011, the fair value of our open derivative contracts was a net asset of
approximately $2.7 million. At December 31, 2010, the fair value of our open derivative contracts
was a net liability of approximately $1.1 million.
27
JPMorgan Chase Bank, National Association (JPMorgan) and KeyBank National Association
(KeyBank) 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 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.
For the nine months ended September 30, 2011 and 2010, we recorded an unrealized gain on
commodity derivatives of $3.8 million and $2.9 million, respectively, 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 September 30, 2011, and a corresponding decrease in the unrealized
gain on commodity derivatives recorded on our consolidated statement of operations for the nine
months ended September 30, 2011.
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 September 30, 2011. Based on this evaluation, the CEO and CFO have concluded that, as of
September 30, 2011, 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 September 30,
2011, that
28
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.
29
PART IIOTHER INFORMATION
Item 1. Legal Proceedings.
The information set forth in Note 5 of Part I, Item 1 of this report regarding Approach
Operating, LLC v. EnCana Oil & Gas (USA) Inc., Cause No. 29.070, is incorporated herein by
reference. Except as set forth in Note 5 of Part I, Item 1 of this Quarterly Report on Form 10-Q,
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, 2010, filed
with the SEC on March 11, 2011.
Item 1A. Risk Factors.
In addition to the other information set forth in this report, you should carefully consider
the risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2010, filed
with the SEC on March 11, 2011, under the headings Item 1. Business Markets and Customers;
Competition; and Regulation, Item 1A. Risk Factors, Item 7. Managements Discussion and
Analysis of Financial Condition and Results of Operations General Trends and Outlook and Item
7A. Quantitative and Qualitative Disclosures about Market Risk. These risks could materially
affect our business, financial condition and results of operations.
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, 2010, filed with the SEC on March
11, 2011, which is accessible on the SECs website at www.sec.gov and our website at
www.approachresources.com.
The adoption of additional federal and state legislative and regulatory initiatives related to
hydraulic fracturing could result in operating restrictions or delays in the completion of oil and
gas wells.
We currently conduct all of our operations in Texas. Texas and other states have adopted, and
other states are considering adopting, regulations that could impose more stringent permitting,
public disclosure and well construction requirements on hydraulic fracturing operations or
otherwise seek to ban hydraulic fracturing activities altogether. In August 2011, the Railroad
Commission of Texas proposed new rules requiring disclosure of the composition of hydraulic
fracturing fluids and total volume of water used in the hydraulic fracturing process. In addition
to state laws, rules and regulations, local land use restrictions, such as city or county
ordinances, may restrict or prohibit drilling in general or hydraulic fracturing in particular. The
adoption of state, local or municipal laws, rules or regulations in areas where we operate may
cause us to incur additional, and potentially significant, compliance costs, to experience delays
in our exploration, development or production activities, or to be precluded from the drilling of
wells.
There are also certain governmental reviews either underway or being proposed that focus on
the environmental aspects of hydraulic fracturing practices. The White House Council on
Environmental Quality is coordinating an administration-wide review of hydraulic fracturing
practices, and a committee of the United States House of Representatives has conducted an
investigation of hydraulic fracturing practices. Further, a number of federal agencies are
analyzing, or have been requested to review, a variety of environmental issues associated with
hydraulic fracturing. The Environmental Protection Agency (EPA) has commenced a study of the
potential environmental effects of hydraulic fracturing on drinking water and groundwater, with
initial results expected to be available by late 2012 and final results by 2014. In addition, the
U.S. Department of Energy is conducting an investigation into practices the
agency could recommend to improve the safety and environmental performance of hydraulic
fracturing
30
methods. Also, the U.S. Department of the Interior is considering disclosure
requirements or other mandates for hydraulic fracturing on federal lands.
In July 2011, the EPA proposed rules that would establish new air emission controls for oil
and gas production and natural gas processing operations. Specifically, the EPAs proposed rule
package includes New Source Performance Standards to address emissions of sulfur dioxide and
volatile organic compounds (VOCs) and a separate set of emission standards to address hazardous
air pollutants frequently associated with oil and gas production and processing activities. The
EPAs proposal would require the reduction of VOC emissions from oil and gas production facilities
by requiring the use of green completions for hydraulic fracturing, which requires the operator
to recover rather than vent the natural gas and natural gas liquids that come to the surface during
the hydraulic fracturing process. The proposed rules also would establish specific requirements
regarding emissions from compressors, dehydrators, storage tanks and other production equipment.
The EPA will receive public comment and hold hearings regarding the proposed rules and take final
action by February 28, 2012. If finalized, these rules could require a number of modifications to
our operations, including the installation of new equipment. Compliance with such rules could
result in additional capital expenditures and operating costs.
In October 2011, the EPA announced that it intends to develop national standards for
wastewater discharges produced by natural gas extraction from shale and coalbed methane formations.
For shale gas wastewater, the EPA will consider imposing pre-treatment standards for discharges to
a wastewater treatment facility. Produced and other flowback water from our current operations in
the Permian Basin is typically re-injected into underground formations that do not contain potable
water. To the extent that re-injection is not available for our operations and discharge to
wastewater treatment facilities is required, new standards from the EPA could increase the cost of
disposing wastewater in connection with our operations.
Certain members of Congress have called upon (i) the U.S. Government Accountability Office to
investigate how hydraulic fracturing might adversely affect water resources, (ii) the SEC to
investigate the natural gas industry and any possible misleading of investors or the public
regarding the economic feasibility of developing shale gas reserves including by means of hydraulic
fracturing, and (iii) the U.S. Energy Information Administration to provide a better understanding
of that agencys estimates regarding natural gas reserves, as well as uncertainties associated with
those estimates. These ongoing or proposed investigations and studies, depending on their degree of
pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic
fracturing under the Safe Drinking Water Act or other regulatory means.
Increased regulation and attention given to the hydraulic fracturing process could lead to
greater opposition, including litigation, to oil and gas production activities that use hydraulic
fracturing. Additional legislation or regulation could also lead to operational delays or increased
operating costs in the production of oil and gas, or could make it more difficult to use hydraulic
fracturing. The adoption of any federal, state or local laws or the implementation of regulations
regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and
gas wells and increased compliance costs and time, which could adversely affect our business,
financial condition, results of operations and cash flows.
31
Our ability to produce oil and gas economically and in commercial quantities could be impaired
if we are unable to acquire adequate supplies of water for our drilling and completions operations
or are unable to dispose of or recycle the water we use at a reasonable cost and in accordance with
applicable environmental laws, rules and regulations.
The hydraulic fracturing processes that we use to produce oil and gas from the Wolffork oil
shale play in the Permian Basin requires the use and disposal of significant quantities of water.
Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in
our operations, could adversely impact our operations in this region. Moreover, new environmental
initiatives and regulations could include restrictions on our ability to conduct certain operations
such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water,
drilling fluids and other wastes associated with the exploration, development or production of
natural gas.
Compliance with environmental regulations and permit requirements governing the withdrawal,
storage and use of surface water or groundwater necessary for hydraulic fracturing of our wells may
increase our operating costs and cause delays, interruptions or cessation of our operations, the
extent of which cannot be predicted, and all of which could have an adverse effect on our business,
financial condition, results of operations and cash flows.
Current
SEC rules could require us to write down our proved undeveloped reserves in the future.
The current SEC rules require that, subject to limited exceptions, proved undeveloped reserves
may only be booked if they relate to wells scheduled to be drilled within five years. These rules
may require us to write down our proved undeveloped reserves if we do not drill certain wells
within the required five-year timeframe.
32
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 September 30, 2011. 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(c) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Number of |
|
|
(d) |
|
|
|
|
|
|
|
|
|
|
|
Shares |
|
|
Maximum |
|
|
|
(a) |
|
|
|
|
|
|
Purchased as |
|
|
Number of Shares |
|
|
|
Total |
|
|
(b) |
|
|
Part of Publicly |
|
|
that May Yet Be |
|
|
|
Number of |
|
|
Average |
|
|
Announced |
|
|
Purchased Under |
|
|
|
Shares |
|
|
Price Paid |
|
|
Plans or |
|
|
the Plans or |
|
Period |
|
Purchased |
|
|
Per Share |
|
|
Programs |
|
|
Programs |
|
Month #1
July 1, 2011 July 31, 2011 |
|
|
2,645 |
|
|
$ |
26.07 |
|
|
|
|
|
|
|
|
|
Month #2
August 1, 2011 August 31, 2011 |
|
|
1,613 |
|
|
$ |
20.33 |
|
|
|
|
|
|
|
|
|
Month #3
September 1, 2011 September 30, 2011 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
4,258 |
|
|
$ |
23.90 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Item 6. Exhibits.
See Index to Exhibits following the signature page of this report for a description of the
exhibits furnished as part of this report.
33
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: November 7, 2011 |
By: |
/s/
J. Ross Craft |
|
|
|
J. Ross Craft |
|
|
|
President and Chief Executive Officer
(Principal Executive Officer) |
|
|
|
|
|
Date: November 7, 2011 |
By: |
/s/
Steven 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. 11 dated as of October 7, 2011, to Credit Agreement dated as of January 18, 2008,
among Approach Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as administrative agent
and lender, BNP Paribas, KeyBank National Association, The Frost National Bank, Royal Bank of
Canada and Wells Fargo Bank, N.A., as lenders, and Approach Oil & Gas Inc. and Approach
Resources I, LP, as guarantors (filed as Exhibit 10.1 to the Companys Current Report on Form
8-K filed October 11, 2011, and incorporated herein by reference). |
|
|
|
*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. |
|
|
|
**101.INS
|
|
XBRL Instance Document. |
|
|
|
**101.SCH
|
|
XBRL Taxonomy Extension Schema Document. |
|
|
|
**101.CAL
|
|
XBRL Taxonomy Extension Calculation Linkbase Document. |
|
|
|
**101.LAB
|
|
XBRL Taxonomy Extension Label Linkbase Document. |
|
|
|
**101.PRE
|
|
XBRL Taxonomy Extension Presentation Linkbase Document. |
|
|
|
* |
|
Filed herewith. |
|
** |
|
Furnished herewith. |