e10vq
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
|
|
|
þ |
|
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2009
OR
|
|
|
o |
|
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)
|
|
|
Delaware
|
|
51-0424817 |
(State or other jurisdiction of
incorporation or organization)
|
|
(I.R.S. employer
identification number) |
|
|
|
One Ridgmar Centre
6500 W. Freeway, Suite 800
Fort Worth, Texas
|
|
76116 (Zip Code) |
(Address of principal executive offices)
|
|
|
(817) 989-9000
(Registrants telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant 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).
Yes o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act.
|
|
|
|
|
|
|
|
|
|
|
|
|
Large accelerated filer o |
|
Accelerated filer þ |
|
Non-accelerated filer o |
|
Smaller reporting company o |
|
|
|
|
|
|
(Do not check if smaller reporting company) |
|
|
|
|
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Act). Yes o No þ
The number of shares of the registrants common stock, $0.01 par value, outstanding as of October
31, 2009 was 20,738,585.
PART I FINANCIAL INFORMATION
Item 1. Financial statements.
APPROACH RESOURCES INC.
UNAUDITED CONSOLIDATED BALANCE SHEETS
(In thousands, except shares and per-share amounts)
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
ASSETS |
|
|
|
|
|
|
|
|
CURRENT ASSETS: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
700 |
|
|
$ |
4,077 |
|
Accounts receivable: |
|
|
|
|
|
|
|
|
Joint interest owners |
|
|
3,559 |
|
|
|
16,228 |
|
Oil and gas sales |
|
|
2,586 |
|
|
|
5,936 |
|
Unrealized gain on commodity derivatives |
|
|
854 |
|
|
|
8,017 |
|
Prepaid expenses and other current assets |
|
|
510 |
|
|
|
579 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
8,209 |
|
|
|
34,837 |
|
|
|
|
|
|
|
|
|
|
PROPERTIES AND EQUIPMENT: |
|
|
|
|
|
|
|
|
Oil and gas properties, at cost, using the successful efforts method of accounting |
|
|
381,656 |
|
|
|
362,805 |
|
Furniture, fixtures and equipment |
|
|
1,452 |
|
|
|
977 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
383,108 |
|
|
|
363,782 |
|
Less accumulated depletion, depreciation and amortization |
|
|
(79,004 |
) |
|
|
(60,378 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net properties and equipment |
|
|
304,104 |
|
|
|
303,404 |
|
Other assets |
|
|
220 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
312,533 |
|
|
$ |
338,241 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
CURRENT LIABILITIES: |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
3,275 |
|
|
$ |
13,564 |
|
Oil and gas sales payable |
|
|
2,743 |
|
|
|
4,631 |
|
Accrued liabilities |
|
|
2,782 |
|
|
|
9,810 |
|
Current portion of deferred income taxes |
|
|
399 |
|
|
|
2,770 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
9,199 |
|
|
|
30,775 |
|
|
|
|
|
|
|
|
|
|
NON-CURRENT LIABILITIES: |
|
|
|
|
|
|
|
|
Long-term debt |
|
|
36,939 |
|
|
|
43,537 |
|
Unrealized loss on commodity derivatives |
|
|
1,426 |
|
|
|
|
|
Deferred income taxes |
|
|
38,085 |
|
|
|
35,891 |
|
Asset retirement obligations |
|
|
4,454 |
|
|
|
4,225 |
|
|
|
|
|
|
|
|
Total liabilities |
|
|
90,103 |
|
|
|
114,428 |
|
|
|
|
|
|
|
|
|
|
COMMITMENTS AND CONTINGENCIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STOCKHOLDERS EQUITY: |
|
|
|
|
|
|
|
|
Common stock, $0.01 par value, 90,000,000 shares authorized, 20,927,467 and
20,715,357 issued and 20,738,585 and 20,680,584 outstanding, respectively |
|
|
209 |
|
|
|
207 |
|
Additional paid-in capital |
|
|
168,709 |
|
|
|
167,349 |
|
Retained earnings |
|
|
53,806 |
|
|
|
56,753 |
|
Accumulated other comprehensive loss |
|
|
(294 |
) |
|
|
(496 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity |
|
|
222,430 |
|
|
|
223,813 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
312,533 |
|
|
$ |
338,241 |
|
|
|
|
|
|
|
|
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)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
2008 |
|
|
2009 |
|
2008 |
|
|
|
|
|
|
|
|
|
|
REVENUES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales |
|
$ |
8,787 |
|
|
$ |
22,015 |
|
|
$ |
28,767 |
|
|
$ |
65,177 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating |
|
|
1,894 |
|
|
|
1,842 |
|
|
|
6,016 |
|
|
|
5,095 |
|
Severance and production taxes |
|
|
455 |
|
|
|
968 |
|
|
|
1,392 |
|
|
|
2,891 |
|
Exploration |
|
|
534 |
|
|
|
|
|
|
|
534 |
|
|
|
1,478 |
|
General and administrative |
|
|
2,237 |
|
|
|
1,923 |
|
|
|
7,277 |
|
|
|
5,686 |
|
Depletion, depreciation and amortization |
|
|
5,595 |
|
|
|
5,016 |
|
|
|
18,766 |
|
|
|
16,257 |
|
|
|
|
|
|
Total expenses |
|
|
10,715 |
|
|
|
9,749 |
|
|
|
33,985 |
|
|
|
31,407 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING (LOSS) INCOME |
|
|
(1,928 |
) |
|
|
12,266 |
|
|
|
(5,218 |
) |
|
|
33,770 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net |
|
|
(451 |
) |
|
|
(423 |
) |
|
|
(1,353 |
) |
|
|
(914 |
) |
Realized gain (loss) on commodity derivatives |
|
|
4,271 |
|
|
|
(195 |
) |
|
|
11,896 |
|
|
|
(676 |
) |
Unrealized (loss) gain on commodity
derivatives |
|
|
(6,414 |
) |
|
|
18,611 |
|
|
|
(8,589 |
) |
|
|
4,060 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(LOSS) INCOME BEFORE INCOME TAX (BENEFIT)
PROVISION |
|
|
(4,522 |
) |
|
|
30,259 |
|
|
|
(3,264 |
) |
|
|
36,240 |
|
INCOME TAX (BENEFIT) PROVISION |
|
|
(1,378 |
) |
|
|
10,411 |
|
|
|
(317 |
) |
|
|
12,702 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET (LOSS) INCOME |
|
$ |
(3,144 |
) |
|
$ |
19,848 |
|
|
$ |
(2,947 |
) |
|
$ |
23,538 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(LOSS) EARNINGS PER SHARE: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(0.15 |
) |
|
$ |
0.96 |
|
|
$ |
(0.14 |
) |
|
$ |
1.14 |
|
|
|
|
|
|
Diluted |
|
$ |
(0.15 |
) |
|
$ |
0.95 |
|
|
$ |
(0.14 |
) |
|
$ |
1.13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE SHARES OUTSTANDING: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
20,929,508 |
|
|
|
20,651,591 |
|
|
|
20,839,746 |
|
|
|
20,640,327 |
|
Diluted |
|
|
20,929,508 |
|
|
|
20,851,848 |
|
|
|
20,839,746 |
|
|
|
20,837,166 |
|
See accompanying notes to these consolidated financial statements.
2
APPROACH RESOURCES INC. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
|
2009 |
|
2008 |
|
|
|
|
|
|
|
|
|
|
OPERATING ACTIVITIES: |
|
|
|
|
|
|
|
|
Net income |
|
$ |
(2,947 |
) |
|
$ |
23,538 |
|
Adjustments to reconcile net income to net cash provided by
operating activities: |
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization |
|
|
18,766 |
|
|
|
16,257 |
|
Unrealized loss (gain) on commodity derivatives |
|
|
8,589 |
|
|
|
(4,060 |
) |
Exploration expense |
|
|
534 |
|
|
|
1,478 |
|
Share-based compensation expense |
|
|
1,434 |
|
|
|
800 |
|
Deferred income taxes |
|
|
(314 |
) |
|
|
11,789 |
|
Changes in working capital: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
16,019 |
|
|
|
(9,003 |
) |
Prepaid expenses and other assets |
|
|
99 |
|
|
|
285 |
|
Accounts payable |
|
|
(10,315 |
) |
|
|
(1,118 |
) |
Oil and gas sales payable |
|
|
(1,888 |
) |
|
|
6,571 |
|
Accrued liabilities |
|
|
(7,047 |
) |
|
|
(641 |
) |
|
|
|
Cash provided by operating activities |
|
|
22,930 |
|
|
|
45,896 |
|
|
|
|
|
|
|
|
|
|
INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
Additions to oil and gas properties |
|
|
(18,993 |
) |
|
|
(72,213 |
) |
Additions to other property and equipment, net |
|
|
(475 |
) |
|
|
(457 |
) |
|
|
|
Cash used in investing activities |
|
|
(19,468 |
) |
|
|
(72,670 |
) |
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
Proceeds from issuance of common stock |
|
|
|
|
|
|
97 |
|
Borrowings under credit facility, net of debt issuance costs |
|
|
55,677 |
|
|
|
83,878 |
|
Repayment of amounts outstanding under credit facility |
|
|
(62,525 |
) |
|
|
(60,350 |
) |
|
|
|
Cash (used in) provided by financing activities |
|
|
(6,848 |
) |
|
|
23,625 |
|
|
|
|
|
|
|
|
|
|
CHANGE IN CASH AND CASH EQUIVALENTS |
|
|
(3,386 |
) |
|
|
(3,149 |
) |
EFFECT OF FOREIGN CURRENCY TRANSLATION ON CASH AND CASH
EQUIVALENTS |
|
|
9 |
|
|
|
(10 |
) |
CASH AND CASH EQUIVALENTS, beginning of period |
|
|
4,077 |
|
|
|
4,785 |
|
|
|
|
CASH AND CASH EQUIVALENTS, end of period |
|
$ |
700 |
|
|
$ |
1,626 |
|
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: |
|
|
|
|
|
|
|
|
Cash paid for interest |
|
$ |
1,199 |
|
|
$ |
527 |
|
|
|
|
Cash paid for income taxes |
|
$ |
|
|
|
$ |
49 |
|
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL DISCLOSURE OF NON-CASH TRANSACTION: |
|
|
|
|
|
|
|
|
Adjustment to Neo Canyon acquisition purchase price allocation |
|
$ |
|
|
|
$ |
509 |
|
|
|
|
See accompanying notes to these consolidated financial statements.
3
APPROACH RESOURCES INC. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
2008 |
|
|
2009 |
|
2008 |
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
(3,144 |
) |
|
$ |
19,848 |
|
|
$ |
(2,947 |
) |
|
$ |
23,538 |
|
Other comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation, net related income tax |
|
|
111 |
|
|
|
188 |
|
|
|
202 |
|
|
|
127 |
|
|
|
|
|
|
Total comprehensive (loss) income |
|
$ |
(3,033 |
) |
|
$ |
20,036 |
|
|
$ |
(2,745 |
) |
|
$ |
23,665 |
|
|
|
|
|
|
See accompanying notes to these consolidated financial statements.
4
APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2009
(Unaudited)
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 natural gas and oil
properties in the United States and British Columbia. We currently operate in Texas, Kentucky and
New Mexico and have non-operated interests in British Columbia.
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, 2008 and filed with the Securities and Exchange Commission on March 13,
2009.
The accompanying interim consolidated financial statements have been prepared in accordance with
accounting principles generally accepted in the United States of America and include the accounts
of the Company and its wholly-owned subsidiaries. Intercompany accounts and transactions are
eliminated. In preparing the accompanying financial statements, we have made certain estimates and
assumptions that affect reported amounts in the financial statements and disclosures of
contingencies. Actual results may differ from those estimates. Significant assumptions are required
in the valuation of proved oil and natural gas reserves, which affect the amount at which oil and
natural gas properties are recorded. Significant assumptions are also required in estimating our
accrual of capital expenditures, asset retirement obligations and share-based compensation. It is
at least reasonably possible these estimates could be revised in the near term, and these revisions
could be material. Certain prior year amounts have been reclassified to conform to current year
presentation. These classifications have no impact on the net income reported.
2. Current accounting pronouncements
Effective January 1, 2009, we adopted ASC 815-10 (formerly Statement of Financial Accounting
Standards (SFAS) 161, Disclosures about Derivative Instruments and Hedging Activities, an
amendment of FASB Statement 133), which amends and expands the disclosure requirements with the
intent to provide users of financial statements with an enhanced understanding of (i) how and why
an entity uses derivative instruments; (ii) how derivative instruments and the related hedged items
are accounted for; and (iii) how derivative instruments and related hedged items affect an entitys
financial position, financial performance and cash flows. See Note 7 to our consolidated financial
statements in this report for our derivatives disclosures.
In May 2009, the Financial Accounting Standards Board (the FASB) issued ASC 855-10 (formerly SFAS
No. 165) Subsequent Events, which establishes general standards of accounting for and disclosure
5
APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2009
(Unaudited)
of events that occur after September 30, 2009 but before November 5, 2009. We adopted this
standard upon issuance with no impact on our financial position or results of operations.
In June 2009, the FASB issued ASC 105-10 (formerly SFAS No. 168), Accounting Standards
CodificationTM and the Hierarchy of Generally Accepted Accounting Principles. The FASB
Accounting Standards CodificationTM (the Codification) has become the source of
authoritative accounting principles recognized by the FASB to be applied by nongovernmental
entities in the preparation of financial statements in accordance with Generally Accepted
Accounting Principles (GAAP). All existing accounting standard documents are superseded by the
Codification and any accounting literature not included in the Codification will not be
authoritative. Rules and interpretive releases of the SEC issued under the authority of federal
securities laws, however, will continue to be the source of authoritative generally accepted
accounting principles for SEC registrants. Effective September 30, 2009, all references made to
GAAP in our consolidated financial statements will include the new Codification numbering system
along with original references. The Codification does not change or alter existing GAAP and,
therefore, will not have an impact on our financial position, results of operations or cash flows.
3. (Loss) earnings per common share
We report basic (loss) 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 anti-dilutive. The following are reconciliations of the
numerators and denominators of our basic and diluted (loss) earnings per share (dollars in
thousands, except per-share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2009 |
|
|
|
Income (numerator) |
|
|
Shares (denominator) |
|
|
Per-share amount |
|
|
Basic loss per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(3,144 |
) |
|
|
20,929,508 |
|
|
$ |
(0.15 |
) |
Effect of dilutive securities(1): |
|
|
|
|
|
|
|
|
|
|
|
|
Share-based compensation, treasury
method |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss plus assumed conversions |
|
$ |
(3,144 |
) |
|
|
20,929,508 |
|
|
$ |
(0.15 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2008 |
|
|
|
Income (numerator) |
|
|
Shares (denominator) |
|
|
Per-share amount |
|
|
Basic earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
19,848 |
|
|
|
20,651,591 |
|
|
$ |
0.96 |
|
Effect of dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
|
Share-based compensation, treasury
method |
|
|
|
|
|
|
172,214 |
|
|
|
|
|
Non-vested restricted shares |
|
|
|
|
|
|
28,043 |
|
|
|
|
|
|
|
|
|
|
|
|
Net income plus assumed conversions |
|
$ |
19,848 |
|
|
|
20,851,848 |
|
|
$ |
0.95 |
|
|
|
|
|
|
|
|
6
APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2009
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2009 |
|
|
|
Income (numerator) |
|
|
Shares (denominator) |
|
|
Per-share amount |
|
|
Basic earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(2,947 |
) |
|
|
20,839,746 |
|
|
$ |
(0.14 |
) |
Effect of dilutive securities(1): |
|
|
|
|
|
|
|
|
|
|
|
|
Share-based compensation, treasury method |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income plus assumed conversions |
|
$ |
(2,947 |
) |
|
|
20,839,746 |
|
|
$ |
(0.14 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2008 |
|
|
|
Income (numerator) |
|
|
Shares (denominator) |
|
|
Per-share amount |
|
|
Basic earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
23,538 |
|
|
|
20,640,327 |
|
|
$ |
1.14 |
|
Effect of dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
|
Share-based compensation, treasury method |
|
|
|
|
|
|
184,769 |
|
|
|
|
|
Non-vested restricted shares |
|
|
|
|
|
|
12,070 |
|
|
|
|
|
|
|
|
|
|
|
|
Net income plus assumed conversions |
|
$ |
23,538 |
|
|
|
20,837,166 |
|
|
$ |
1.13 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Approximately 416,000 stock options were excluded from assumed conversions because they were anti-dilutive for the three
and nine months ended September 30, 2009. |
4. Revolving credit facility
We have a $200 million revolving credit facility with a borrowing base set at $100 million at
September 30, 2009. The borrowing base is redetermined semi-annually on or before each April 1 and
October 1 based on our oil and gas reserves. We or the lenders can each request one additional
borrowing base redetermination each calendar year.
Effective April 8, 2009, we entered into a fourth amendment (the Fourth Amendment) to our credit
agreement. The Fourth Amendment reaffirmed the borrowing base of $100 million under the credit
agreement as well as the commitment percentages of the agent bank and participating banks. The
Fourth Amendment also revised the applicable rate schedule to (i) increase the Eurodollar rate
margin from a range of 1.25% to 2.00% to a range of 2.25% to 3.25%, determined by the then-current
percentage of the borrowing base that is drawn, (ii) increase the base rate margin from a flat rate
of 0.00% to a range of 1.25% to 2.25%, determined by the then-current percentage of the borrowing
base that is drawn, and (iii) increase the unused commitment fee rate from 0.375% to 0.50%.
On July 8, 2009, we entered into a fifth amendment to our credit agreement, which extended the
maturity date under our revolving credit facility by one year to July 31, 2011. In consideration
for extending the maturity date, we paid a $250,000 extension fee, calculated as 0.25% of the
current commitment amount of $100 million. The $250,000 fee is being amortized into interest
expense through the extended maturity date.
We had outstanding borrowings of $36.9 million and $43.5 million under our revolving credit
facility at September 30, 2009 and December 31, 2008, respectively. The weighted average interest
rate applicable to our outstanding borrowings was 2.92% and 3.25% as of September 30, 2009 and
December 31, 2008, respectively. We also had outstanding unused letters of credit under our
revolving credit facility totaling $400,000
7
APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2009
(Unaudited)
at September 30, 2009, 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.
Effective October 30, 2009, we entered into a sixth amendment to our credit agreement, which
increased the borrowing base under the credit agreement to $115 million from $100 million.
At October 31, 2009, we had $35.8 million outstanding under our revolving credit facility, with a
weighted average interest rate of 3.07%.
Covenants
Our credit agreement contains two principal financial covenants:
|
|
a consolidated modified current ratio covenant that requires us to maintain a ratio of not
less than 1.0 to 1.0 at all times. The consolidated modified current ratio is calculated by
dividing Consolidated Current Assets (as defined in the credit agreement) by Consolidated
Current Liabilities (as defined in the credit agreement). As defined more specifically in the
credit agreement, the consolidated modified current ratio is calculated as current assets less
current unrealized gains on commodity derivatives plus the available borrowing base at the
respective balance sheet date, divided by current liabilities less current unrealized losses
on commodity derivatives at the respective balance sheet date. |
|
|
|
a consolidated funded debt to consolidated EBITDAX ratio covenant that requires us to
maintain a ratio of not more than 3.5 to 1.0 at the end of each fiscal quarter. The
consolidated funded debt to consolidated EBITDAX ratio is calculated by dividing Consolidated
Funded Debt (as defined in the credit agreement) by Consolidated EBITDAX (as defined in the
credit agreement). As defined more specifically in the credit agreement, consolidated EBITDAX
is calculated as net income (loss), plus (1) exploration expense, (2) depletion, depreciation
and amortization expense, (3) share-based compensation expense, (4) unrealized loss on
commodity derivatives, (5) interest expense, (6) income and franchise taxes, and (7) certain
other non-cash expenses, less (1) gains or losses from sales or dispositions of assets, (2)
unrealized gain on commodity derivatives and (3) extraordinary or non-recurring 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
8
APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2009
(Unaudited)
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, 2009, 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
On July 2, 2009, our operating subsidiary filed a lawsuit against the non-operating, joint working
interest owner in our North Bald Prairie project in East Texas. The lawsuit is for breach of the
joint operating agreement (JOA) covering the project in East Texas and seeks damages for
nonpayment of amounts owed under the JOA as well as declaratory relief. As we previously have
disclosed, in December 2008, the non-operating, joint interest owner notified us that it was
exercising its right to become operator of record for joint interest wells in North Bald Prairie
under a carry and earning agreement between the parties. We dispute the right of the joint
interest owner to become the operator of record while it remains in default under the JOA.
During the three months ended September 30, 2009, the non-operator began suspending payment of
amounts owed under the JOA, in addition to prior amounts either not paid or underpaid by the
non-operator. At September 30, 2009, the non-operator owed us $2.1 million, which is included in
accounts receivable from joint interest owners on our consolidated balance sheet. We have accrued
obligations owed to the non-operator of approximately $210,000, which are included in accrued
liabilities on our consolidated balance sheet at September 30, 2009. While we cannot predict the
outcome of this proceeding with certainty, we believe the receivable balance is collectible and,
therefore, no allowance for uncollectible accounts has been provided.
In addition to the proceeding described above, we are involved in various other legal and
regulatory proceedings arising in the normal course of business. While we cannot predict the
outcome of these proceedings with certainty, we do not believe that an adverse result in any
pending legal or regulatory proceeding, together or in the aggregate, would be material to our
consolidated financial condition, results of operations or cash flows.
6. Income taxes
The effective income tax rate for the three and nine months ended September 30, 2009 was 30.5% and
9.7%, respectively. Total income tax expense differed from the amounts computed by applying the
U.S. federal statutory tax rates to pre-tax income for the nine months ended September 30, 2009 due
primarily to a change in our estimated income tax expense for the year ended December 31, 2008
along with the impact of permanent differences between book and taxable income and increased state
income tax rates. Total income tax expense based on U.S. federal statutory tax rates was not
significantly different from income tax expense for the nine months ended September 30, 2008.
9
APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2009
(Unaudited)
7. Derivatives
At September 30, 2009, we had the following commodity derivatives positions outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
$/MMBtu |
Period |
|
Monthly |
|
Total |
|
Floor |
|
Ceiling |
|
Fixed |
NYMEX Henry Hub |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price collars 2009 |
|
|
180,000 |
|
|
|
540,000 |
|
|
$ |
7.50 |
|
|
$ |
10.50 |
|
|
|
|
|
Price collars 2009 |
|
|
130,000 |
|
|
|
390,000 |
|
|
$ |
8.50 |
|
|
$ |
11.70 |
|
|
|
|
|
Price swaps 2009 |
|
|
150,000 |
|
|
|
450,000 |
|
|
|
|
|
|
|
|
|
|
$ |
4.50 |
|
Price swaps 2010 |
|
|
150,000 |
|
|
|
1,800,000 |
|
|
|
|
|
|
|
|
|
|
$ |
5.85 |
|
Price swaps 2010 |
|
|
150,000 |
|
|
|
1,800,000 |
|
|
|
|
|
|
|
|
|
|
$ |
6.40 |
|
WAHA basis differential |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis swaps 2009 |
|
|
200,000 |
|
|
|
600,000 |
|
|
|
|
|
|
|
|
|
|
$ |
(0.61 |
) |
Basis swaps 2009 |
|
|
300,000 |
|
|
|
900,000 |
|
|
|
|
|
|
|
|
|
|
$ |
(0.67 |
) |
Basis swaps 2010 |
|
|
415,000 |
|
|
|
4,980,000 |
|
|
|
|
|
|
|
|
|
|
$ |
(0.71 |
) |
Basis swaps 2011 |
|
|
300,000 |
|
|
|
3,600,000 |
|
|
|
|
|
|
|
|
|
|
$ |
(0.53 |
) |
The
following summarizes the fair value of our open commodity derivatives
as of September 30, 2009 and December 31, 2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Derivatives |
|
Liability Derivatives |
|
|
Balance Sheet |
|
|
|
|
|
|
|
|
|
Balance Sheet |
|
|
|
|
Location |
|
Fair Value |
|
Location |
|
Fair Value |
|
|
|
|
September 30, |
|
December 31, |
|
|
|
September 30, |
|
December 31, |
|
|
|
|
2009 |
|
2008 |
|
|
|
2009 |
|
2008 |
Derivatives not
designated as
hedging instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivatives
|
|
Unrealized gain on
commodity
derivatives
|
|
$ |
854 |
|
|
$ |
8,017 |
|
|
Unrealized loss on
commodity
derivatives
|
|
$ |
1,426 |
|
|
$ |
10
APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2009
(Unaudited)
The following summarizes the change in the fair value of our commodity derivatives (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Derivatives |
|
|
Income Statement |
|
|
|
|
Location |
|
Fair Value |
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
|
|
September 30, |
|
September 30, |
|
|
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
Derivatives not
designated as
hedging instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivatives |
|
Unrealized
(loss) gain on commodity derivatives |
|
$ |
(6,414 |
) |
|
$ |
18,611 |
|
|
$ |
(8,589 |
) |
|
$ |
4,060 |
|
|
|
Realized
gain (loss) on commodity derivatives |
|
|
4,271 |
|
|
|
(195 |
) |
|
|
11,896 |
|
|
|
(676 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(2,143 |
) |
|
$ |
18,416 |
|
|
$ |
3,307 |
|
|
$ |
3,384 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsequent to September 30, 2009, we entered into a NYMEX Henry Hub price swap at $6.36 per
MMBtu for 100,000 MMBtu per month for 2010.
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 collar 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.
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, 2009, 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
|
11
APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2009
(Unaudited)
|
|
|
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, 2009, 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, 2009, our Level
3 measurements were limited to our asset retirement obligation. |
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.
8. Share-based compensation
During the nine months ended September 30, 2009, we granted 166,354 restricted shares of common
stock to employees. The total fair market value of these restricted shares on the grant date was
$1.5 million, which will be expensed over a service period of three years. A summary of the status
of non-vested shares for the nine months ended September 30, 2009 is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
|
|
Grant-Date |
|
|
|
Shares |
|
|
Fair Value |
|
|
|
|
Nonvested at January 1, 2009 |
|
|
56,023 |
|
|
$ |
18.96 |
|
|
|
|
|
|
|
|
|
Granted |
|
|
166,354 |
|
|
|
8.80 |
|
Vested |
|
|
(10,280 |
) |
|
|
21.75 |
|
Canceled |
|
|
(1,967 |
) |
|
|
11.16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonvested at September 30, 2009 |
|
|
210,130 |
|
|
$ |
10.35 |
|
|
|
|
|
|
|
|
12
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, 2008 filed
with the Securities and Exchange Commission (SEC) on March 13, 2009. 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 statements 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. The
forward-looking statements may include projections and estimates concerning the timing and success
of specific projects and our future reserves, production, revenues, income and capital spending.
When we use the words will, believe, intend, expect, may, should, anticipate,
could, estimate, plan, predict, project or their negatives, other similar expressions or
the statements that include those words, it usually is a forward-looking statement.
The forward-looking statements contained in this report 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 detailed below and discussed in our 2008 Annual
Report on Form 10-K and subsequent filings. All forward-looking statements speak only as of the
date of this report. We do not intend 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:
|
|
global economic and financial market conditions, |
|
|
|
our business strategy, |
|
|
|
estimated quantities of oil and gas reserves, |
|
|
|
uncertainty of commodity prices in oil and gas, |
|
|
|
disruption of credit and capital markets, |
|
|
|
our financial position, |
|
|
|
our cash flow and liquidity, |
|
|
|
replacing our oil and gas reserves,
|
13
|
|
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 rigs, equipment, labor
or other services, |
|
|
|
disruptions to, capacity constraints in or other limitations on the pipeline systems which
deliver our gas and other processing and transportation considerations, |
|
|
|
our inability to obtain additional financing necessary to fund our operations and capital
expenditures and to meet our other obligations, |
|
|
|
competition in the oil and gas industry, |
|
|
|
marketing of oil, gas and natural gas liquids, |
|
|
|
exploitation of our current asset base or property acquisitions, |
|
|
|
the effects of government regulation and permitting and other legal requirements, |
|
|
|
plans, objectives, expectations and intentions contained in this report that are not historical,
and |
|
|
|
other factors discussed in our 2008 Annual Report on Form 10-K and subsequent filings,
including this Quarterly Report on Form 10-Q. |
Overview
We are an independent energy company engaged in the exploration, development, production and
acquisition of natural gas and oil properties. We have assembled leasehold interests aggregating
approximately 302,484 gross (201,267 net) acres as of September 30, 2009. We operate in Texas,
Kentucky and New Mexico and have non-operated interests in British Columbia.
At December 31, 2008, we had estimated proved reserves of approximately 211.1 Bcfe. At September
30, 2009, we owned working interests in 473 producing oil and gas wells. Production for the third
quarter of 2009 was 21.8 MMcfe/d. Our estimated production for the month of October 2009 was 21.1
MMcfe/d.
In December 2008, we announced a capital expenditure budget of $43.8 million for 2009. Due to the
extended decline of oil and natural gas prices, however, in March 2009 we announced that we would
not extend the contracts for our two remaining drilling rigs after March 31, 2009, and we released
these rigs during the first week of April 2009.
We have resumed drilling and currently are operating two rigs in Cinco Terry. We also have begun
3-D seismic operations in Cinco Terry. We plan to move one rig into Ozona Northeast in November
2009 to begin drilling. Given the anticipated increase in activity during the remainder of 2009,
we currently expect that our capital expenditures for the year ending December 31, 2009, including
these projects but excluding any acquisitions, will not exceed $30 million. We intend to fund
remaining 2009 capital expenditures, excluding any acquisitions, with internally-generated cash
flows.
14
Our Board of Directors has approved a capital expenditure budget of up to $53 million for 2010.
The 2010 capital expenditure budget provides for us to operate two rigs in Cinco Terry and one rig
in Ozona Northeast until mid-year 2010, when we plan to operate four rigs in Cinco Terry and two
rigs in Ozona Northeast.
Our financial results depend upon many factors, particularly the price of oil 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, commodity price
differentials and other factors. As a result, we cannot accurately predict future oil and gas
prices, and therefore, we cannot determine what effect increases or decreases will have on our
capital program, production volumes and future revenues. A substantial or extended decline in oil
and gas prices could have a material adverse effect on our business, financial condition, results
of operations, quantities of oil and gas reserves that may be economically produced and liquidity
that may be accessed through our borrowing base under our revolving credit facility and through the
capital markets. We enter into financial swaps and collars to partially mitigate the risk of
market price fluctuations related to future oil and gas production. See Note 7 to our consolidated
financial statements in this report for information regarding our commodity derivatives positions
at September 30, 2009.
In addition to production volumes and commodity prices, finding and developing sufficient amounts
of oil and gas reserves at economical costs are critical to our long-term success. Future finding
and development costs are subject to changes in the industry, including the costs of acquiring,
drilling and completing our projects. We focus our efforts on increasing oil and gas reserves and
production while controlling costs at a level that is appropriate for long-term operations. Our
future cash flow from operations will depend on our ability to manage our overall cost structure.
Like all oil and gas production companies, we face the challenge of natural production declines.
Oil and gas production from a given well naturally decreases over time. Additionally, our reserves
have a rapid initial decline. We generally will attempt to overcome this natural decline by
drilling to develop and identify additional reserves, 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.
See Capital expenditures for 2009. A material reduction in capital expenditures and drilling
activities could materially reduce our production volumes and revenues from pre-2009 levels and
increase future expected costs necessary to develop existing reserves. As discussed above, due to
the extended decline of oil and natural gas prices, we released our remaining rigs during the first
week of April 2009. The natural decline of our tight gas fields and reduced drilling activity has
caused a decline in our average daily production since the three months ended March 31, 2009.
Notwithstanding these periods of reduced capital expenditures or curtailed production, our future
growth will depend upon our ability over the long term to continue to add oil and gas reserves in
excess of production at a reasonable cost. We intend to maintain our focus on the costs of adding
reserves through drilling and acquisitions as well as the costs necessary to produce such reserves.
We also face the challenge of financing future acquisitions. We believe we have adequate unused
borrowing capacity under our revolving credit facility for possible acquisitions, temporary working
capital needs and expansion of our drilling program. However, funding for future acquisitions also
may require additional sources of financing, which may not be available.
15
Results of operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
Revenues (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas |
|
$ |
5,001 |
|
|
$ |
14,456 |
|
|
$ |
16,936 |
|
|
$ |
47,900 |
|
Oil |
|
|
2,490 |
|
|
|
5,973 |
|
|
|
7,700 |
|
|
|
13,223 |
|
NGLs |
|
|
1,296 |
|
|
|
1,586 |
|
|
|
4,131 |
|
|
|
4,054 |
|
|
|
|
|
|
|
Total oil and gas sales |
|
|
8,787 |
|
|
|
22,015 |
|
|
|
28,767 |
|
|
|
65,177 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized gain (loss) on commodity derivatives |
|
|
4,271 |
|
|
|
(195 |
) |
|
|
11,896 |
|
|
|
(676 |
) |
|
|
|
|
|
|
Total oil and gas sales including
derivative impact |
|
$ |
13,058 |
|
|
$ |
21,820 |
|
|
$ |
40,663 |
|
|
$ |
64,501 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (MMcf) |
|
|
1,505 |
|
|
|
1,588 |
|
|
|
4,900 |
|
|
|
4,927 |
|
Oil (MBbls) |
|
|
39 |
|
|
|
54 |
|
|
|
155 |
|
|
|
120 |
|
NGLs (MBbls) |
|
|
44 |
|
|
|
28 |
|
|
|
164 |
|
|
|
75 |
|
|
|
|
|
|
|
Total (MMcfe) |
|
|
2,003 |
|
|
|
2,080 |
|
|
|
6,817 |
|
|
|
6,097 |
|
Total (MMcfe/d) |
|
|
21.8 |
|
|
|
22.6 |
|
|
|
25.0 |
|
|
|
22.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (per Mcf) |
|
$ |
3.32 |
|
|
$ |
9.10 |
|
|
$ |
3.46 |
|
|
$ |
9.72 |
|
Oil (per Bbl) |
|
|
63.49 |
|
|
|
110.61 |
|
|
|
49.53 |
|
|
|
110.19 |
|
NGLs (per Bbl) |
|
|
29.72 |
|
|
|
56.64 |
|
|
|
25.18 |
|
|
|
54.05 |
|
|
|
|
|
|
|
Total (per Mcfe) |
|
$ |
4.39 |
|
|
$ |
10.58 |
|
|
$ |
4.22 |
|
|
$ |
10.69 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized gain (loss) on commodity
derivatives (per Mcfe) |
|
|
2.13 |
|
|
|
(0.09 |
) |
|
|
1.75 |
|
|
|
(0.11 |
) |
|
|
|
|
|
|
Total including derivative impact (per
Mcfe) |
|
$ |
6.52 |
|
|
$ |
10.49 |
|
|
$ |
5.97 |
|
|
$ |
10.58 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses (per Mcfe): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating |
|
$ |
0.95 |
|
|
$ |
0.89 |
|
|
$ |
0.88 |
|
|
$ |
0.84 |
|
Severance and production taxes |
|
|
0.23 |
|
|
|
0.47 |
|
|
|
0.20 |
|
|
|
0.47 |
|
Exploration |
|
|
0.27 |
|
|
|
|
|
|
|
0.08 |
|
|
|
0.24 |
|
General and administrative |
|
|
1.12 |
|
|
|
0.92 |
|
|
|
1.07 |
|
|
|
0.93 |
|
Depletion, depreciation and amortization |
|
|
2.79 |
|
|
|
2.41 |
|
|
|
2.75 |
|
|
|
2.67 |
|
Glossary
Bbl. One stock tank barrel, of 42 U.S. gallons liquid volume, used herein to reference oil,
condensate or NGLs.
Bcf.
Billion cubic feet of natural gas.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one
Bbl of oil, condensate or NGLs.
MBbl.
Thousand barrels of oil, condensate or NGLs.
Mcf.
Thousand cubic feet of natural gas.
Mcfe.
Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one
Bbl of oil, condensate or NGLs.
MMBtu.
Million British thermal units.
MMcf.
Million cubic feet of natural gas.
MMcfe.
Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one
Bbl of oil, condensate or NGLs.
NGLs.
Natural gas liquids.
/d.
Per day when used with volumetric units or dollars.
16
Three months ended September 30, 2009 compared to three months ended September 30, 2008
Oil and gas production. Production for the three months ended September 30, 2009 totaled 2.0 Bcfe
(21.8 MMcfe/d), compared to 2.1 Bcfe (22.6 MMcfe/d) produced in the prior year period, a decrease
of 3.7%. Production for the three months ended September 30, 2009 was 75% natural gas and 25% oil
and NGLs, compared to 76% natural gas and 24% oil and NGLs in prior year period. Tight gas sands
are unconventional natural gas reservoirs. Production from these reservoirs has a high initial
rate of decline in the early life of the well. The natural decline of our tight gas fields and
reduced drilling activity has caused a decline in our average daily production from the three
months ended September 30, 2008 to the three months ended September 30, 2009. Production declined
at a faster rate in our Cinco Terry field than Ozona Northeast, which we believe is typical given
its earlier stage of development. Production declined at a slower rate in Ozona Northeast due to
the later stage of development of the field.
Oil and gas sales. Oil and gas sales decreased $13.2 million, or 60.1%, for the three months ended
September 30, 2009 to $8.8 million from $22.0 million for the three months ended September 30,
2008. The decrease in oil and gas sales principally resulted from sharp decreases in the price we
received for our natural gas, oil and NGL production. The average price we received for our
production, before the effect of commodity derivatives, decreased from $10.58 per Mcfe to $4.39 per
Mcfe as oil and gas prices decreased significantly between the two periods. Of the $13.2 million
decrease in revenues, approximately $12.5 million was attributable to a decrease in oil and gas
prices and approximately $749,000 was attributable to a reduction in production volumes.
Commodity derivative activities. Realized gains and losses from our commodity derivative activity
resulted in a gain of $4.3 million and a loss of $195,000 for the three months ended September 30,
2009 and 2008, respectively. Our average realized price, including the effect of commodity
derivatives, was $6.52 per Mcfe for the three months ended September 30, 2009, compared to $10.49
per Mcfe for the three months ended September 30, 2008. Realized gains and losses on commodity
derivatives are derived from the relative movement of gas prices in relation to the range of prices
in our collars or the fixed notional pricing in our price swaps for the applicable periods. The
unrealized loss on commodity derivatives was $6.4 million for the three months ended September 30,
2009, and the unrealized gain on commodity derivatives was $18.6 million for the three months ended
September 30, 2008. As natural gas commodity prices increase, the fair value of the open portion
of those positions decreases. As natural gas commodity prices decrease, the fair value of the open
portion of those positions increases. Historically, we have not designated our derivative
instruments as cash-flow hedges. We record our open derivative instruments at fair value on our
consolidated balance sheets as either unrealized gains or losses on commodity derivatives. We
record changes in such fair value in earnings on our consolidated statements of operations under
the caption entitled unrealized (loss) gain on commodity derivatives.
Lease operating expenses. Our lease operating expenses, or LOE, were relatively constant with an
increase of $52,000, or 2.8%, for the three months ended September 30, 2009 to $1.9 million ($0.95
per Mcfe) from $1.8 million ($0.89 per Mcfe) for the three months ended September 30, 2008. The
increase in LOE per Mcfe over the prior year period was due primarily to increases in pumping and
supervision, well related repairs and maintenance, compression and water hauling, certain of which
are fixed costs, partially offset by lower ad valorem taxes and workover expenses. The following
is a summary of LOE (per Mcfe):
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
|
|
|
|
|
|
September 30, |
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
Change |
|
|
% Change |
|
|
|
|
|
|
|
|
|
|
Compression and gas treating |
|
$ |
0.26 |
|
|
$ |
0.24 |
|
|
$ |
0.02 |
|
|
|
8.3 |
% |
Water hauling, insurance and other |
|
|
0.18 |
|
|
|
0.16 |
|
|
|
0.02 |
|
|
|
12.5 |
|
Pumping and supervision |
|
|
0.18 |
|
|
|
0.13 |
|
|
|
0.05 |
|
|
|
38.5 |
|
Ad valorem taxes |
|
|
0.18 |
|
|
|
0.21 |
|
|
|
(0.03 |
) |
|
|
(14.3 |
) |
Well repairs and maintenance |
|
|
0.14 |
|
|
|
0.11 |
|
|
|
0.03 |
|
|
|
27.3 |
|
Workovers |
|
|
0.01 |
|
|
|
0.04 |
|
|
|
(0.03 |
) |
|
|
(75.0 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
0.95 |
|
|
$ |
0.89 |
|
|
$ |
0.06 |
|
|
|
6.7 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Severance and production taxes. Our production taxes decreased $513,000, or 53.0%, for the
three months ended September 30, 2009 to $455,000 from $968,000 for the three months ended
September 30, 2008. The decrease in production taxes was a function of the decrease in oil and gas
sales between the two periods. Severance and production taxes amounted to approximately 5.2% and
4.4% of oil and gas sales for the respective periods.
Exploration. We recorded $534,000 of exploration expense for the three months ended September 30,
2009. Exploration expense in the 2009 period resulted primarily from the expiration of leases for
approximately 2,300 net acres in our Ozona Northeast and North Bald Prairie fields. We recorded no
exploration expense for the three months ended September 30, 2008.
General and administrative. Our general and administrative, or G&A, expenses increased $314,000, or
16.3%, to $2.2 million ($1.12 per Mcfe) for the three months ended September 30, 2009 from $1.9
million ($0.92 per Mcfe) for the three months ended September 30, 2008. The increase in G&A
expenses was principally due to increased staffing and share-based compensation. Following is a
summary of G&A expenses (in millions and per Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
|
|
|
|
|
|
September 30, |
|
|
|
|
|
|
|
|
|
2009 |
2008 |
|
|
Change |
|
|
|
|
|
|
$MM |
|
|
Mcfe |
|
|
$MM |
|
|
Mcfe |
|
|
$MM |
|
|
Mcfe |
|
|
% Change |
|
Salaries and benefits |
|
$ |
1.0 |
|
|
$ |
0.48 |
|
|
$ |
0.8 |
|
|
$ |
0.40 |
|
|
$ |
0.2 |
|
|
$ |
0.08 |
|
|
|
20.0 |
% |
Share-based compensation |
|
|
0.4 |
|
|
|
0.21 |
|
|
|
0.3 |
|
|
|
0.15 |
|
|
|
0.1 |
|
|
|
0.06 |
|
|
|
40.0 |
|
Professional fees |
|
|
0.3 |
|
|
|
0.15 |
|
|
|
0.3 |
|
|
|
0.15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
0.5 |
|
|
|
0.28 |
|
|
|
0.5 |
|
|
|
0.22 |
|
|
|
|
|
|
|
0.06 |
|
|
|
27.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
2.2 |
|
|
$ |
1.12 |
|
|
$ |
1.9 |
|
|
$ |
0.92 |
|
|
$ |
0.3 |
|
|
$ |
0.20 |
|
|
|
21.7 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization. Our depletion, depreciation and amortization, or
DD&A, expense increased $579,000, or 11.5%, to $5.6 million for the three months ended September
30, 2009 from $5.0 million for the three months ended September 30, 2008. Our DD&A expense per Mcfe
increased by $0.38, or 15.8%, to $2.79 per Mcfe for the three months ended September 30, 2009,
compared to $2.41 per Mcfe for the three months ended September 30, 2008. The increase in DD&A
expense was primarily attributable to an increase in capitalized costs, partially offset by a
decrease in production over the prior year period.
Interest expense, net. Our interest expense, net, increased $28,000, or 6.6%, to $451,000 for the
three months ended September 30, 2009 from $423,000 for the three months ended September 30, 2008.
This increase was substantially the result of our higher average debt level in the 2009 period,
partially offset by lower interest rates in the 2009 period.
Income taxes. Our income taxes decreased $11.8 million to a benefit of $1.4 million for the three
months ended September 30, 2009, from a provision of $10.4 million for the three months ended
September 30,
18
2008. The decrease in income tax provision was due to the decrease in our income before taxes. Our
effective income tax rate for the three months ended September 30, 2009 was 30.5%, compared with
34.4% for the three months ended September 30, 2008. The decrease in the effective tax rate
relates primarily to the increased impact of permanent differences between book and taxable income.
Nine months ended September 30, 2009 compared to nine months ended September 30, 2008
Oil and gas production. Production for the nine months ended September 30, 2009 totaled 6.8 Bcfe
(25.0 MMcfe/d), compared to 6.1 Bcfe (22.3 MMcfe/d) produced in the prior year period, an increase
of 11.8%. Production for the nine months ended September 30, 2009 was 72% natural gas and 28% oil
and NGLs, compared to 81% natural gas and 19% oil and NGLs in prior year period.
Oil and gas sales. Oil and gas sales decreased $36.4 million, or 55.9%, for the nine
months ended September 30, 2009 to $28.8 million from $65.2 million for the nine months ended
September 30, 2008. The decrease in oil and gas sales principally resulted from sharp decreases in
the price we received for our natural gas, oil and NGL production. The decrease in oil and gas
sales was partially offset by a 1.1 MMcfe increase in production from the continued development of
our Cinco Terry field. The average price we received for our production, before the effect of
commodity derivatives, decreased from $10.69 per Mcfe to $4.22 per Mcfe as oil and gas prices
decreased significantly between the two periods. Of the $36.4 million decrease in revenues,
approximately $40.3 million was attributable to a decrease in oil and gas prices, which was
partially offset by approximately $3.9 million attributable to growth in production volume from the
continued development in Cinco Terry.
Commodity derivative activities. Realized gains and losses from our commodity derivative activity
resulted in a gain of $11.9 million and a loss of $676,000 for the nine months ended September 30,
2009 and 2008, respectively. Our average realized price, including the effect of commodity
derivatives, was $5.97 per Mcfe for the nine months ended September 30, 2009, compared to $10.58
per Mcfe for the nine months ended September 30, 2008. Realized gains and losses on commodity
derivatives are derived from the relative movement of gas prices in relation to the range of prices
in our collars or the fixed notional pricing in our price swaps for the applicable periods. The
unrealized loss on commodity derivatives was $8.6 million for the nine months ended September 30,
2009, and the unrealized gain on commodity derivatives was $4.1 million for the nine months ended
September 30, 2008. As natural gas commodity prices increase, the fair value of the open portion
of those positions decreases. As natural gas commodity prices decrease, the fair value of the open
portion of those positions increases. Historically, we have not designated our derivative
instruments as cash-flow hedges. We record our open derivative instruments at fair value on our
consolidated balance sheets as either unrealized gains or losses on commodity derivatives. We
record changes in such fair value in earnings on our consolidated statements of operations under
the caption entitled unrealized (loss) gain on commodity derivatives.
Lease operating expenses. Our LOE increased $921,000, or 18.1%, for the nine months ended September
30, 2009 to $6.0 million ($0.88 per Mcfe) from $5.1 million ($0.84 per Mcfe) for the nine months
ended September 30, 2008. The increase in LOE per Mcfe over the prior year period was due in part
to increases in compression and pumping and supervision, partially offset by lower well-related
repair and maintenance, ad valorem taxes and workover expenses. The following is a summary of LOE
(per Mcfe):
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
|
|
|
|
|
|
September 30, |
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
|
Change |
|
|
% Change |
|
Compression and gas treating |
|
$ |
0.30 |
|
|
$ |
0.24 |
|
|
$ |
0.06 |
|
|
|
25.0 |
% |
Water hauling, insurance and other |
|
|
0.16 |
|
|
|
0.14 |
|
|
|
0.02 |
|
|
|
14.3 |
|
Ad valorem taxes |
|
|
0.16 |
|
|
|
0.17 |
|
|
|
(0.01 |
) |
|
|
(5.9 |
) |
Pumping and supervision |
|
|
0.15 |
|
|
|
0.13 |
|
|
|
0.02 |
|
|
|
15.4 |
|
Well repairs and maintenance |
|
|
0.10 |
|
|
|
0.13 |
|
|
|
(0.03 |
) |
|
|
(23.1 |
) |
Workovers |
|
|
0.01 |
|
|
|
0.03 |
|
|
|
(0.02 |
) |
|
|
(66.7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
0.88 |
|
|
$ |
0.84 |
|
|
$ |
0.04 |
|
|
|
4.8 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Severance and production taxes. Our production taxes decreased $1.5 million, or 51.9%, for the
nine months ended September 30, 2009 to $1.4 million from $2.9 million for the nine months ended
September 30, 2008. The decrease in production taxes was a function of the decrease in oil and gas
sales between the two periods. Severance and production taxes amounted to approximately 4.8% and
4.4% of oil and gas sales for the respective periods.
Exploration. We recorded $534,000 and $1.5 million of exploration expense for the nine months ended
September 30, 2009 and 2008, respectively. Exploration expense in the 2009 period resulted
primarily from the expiration of leases for approximately 2,300 net acres in our Ozona Northeast
and North Bald Prairie fields. Exploration expense in the 2008 period resulted primarily from the
extension of lease terms in our Ozona Northeast field and from one dry hole drilled in Ozona
Northeast.
General and administrative. Our G&A expenses increased $1.6 million, or 28.0%, to $7.3 million
($1.07 per Mcfe) for the nine months ended September 30, 2009 from $5.7 million ($0.93 per Mcfe)
for the nine months ended September 30, 2008. G&A expenses for the nine months ended September 30,
2009 included higher share-based compensation resulting from timing of payment of 2009 annual
director fees, as well as higher salaries and related employee benefit costs attributable to our
increase in staff from the prior year period. G&A expenses for the nine months ended September 30,
2009 also included an increase in franchise taxes partially due to the timing of payment compared
to 2008. The following is a summary of G&A expenses (in millions and per Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
|
|
|
|
|
|
September 30, |
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
|
Change |
|
|
|
|
|
|
$MM |
|
|
Mcfe |
|
|
$MM |
|
|
Mcfe |
|
|
$MM |
|
|
Mcfe |
|
|
% Change |
|
Salaries and benefits |
|
$ |
3.0 |
|
|
$ |
0.43 |
|
|
$ |
2.4 |
|
|
$ |
0.39 |
|
|
$ |
0.6 |
|
|
$ |
0.04 |
|
|
|
10.3 |
% |
Share-based compensation |
|
|
1.5 |
|
|
|
0.22 |
|
|
|
0.8 |
|
|
|
0.14 |
|
|
|
0.7 |
|
|
|
0.08 |
|
|
|
57.1 |
|
Professional fees |
|
|
0.9 |
|
|
|
0.14 |
|
|
|
1.1 |
|
|
|
0.17 |
|
|
|
(0.2 |
) |
|
|
(0.03 |
) |
|
|
(17.6 |
) |
State franchise taxes |
|
|
0.4 |
|
|
|
0.06 |
|
|
|
|
|
|
|
|
|
|
|
0.4 |
|
|
|
0.06 |
|
|
|
|
|
Other |
|
|
1.5 |
|
|
|
0.22 |
|
|
|
1.4 |
|
|
|
0.23 |
|
|
|
0.1 |
|
|
|
(0.1 |
) |
|
|
(4.3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
7.3 |
|
|
$ |
1.07 |
|
|
$ |
5.7 |
|
|
$ |
0.93 |
|
|
$ |
1.6 |
|
|
$ |
0.14 |
|
|
|
15.1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization. Our DD&A expenses increased $2.5 million, or 15.4%,
to $18.8 million for the nine months ended September 30, 2009 from $16.3 million for the nine
months ended September 30, 2008. Our DD&A expenses per Mcfe increased by $0.08 or 3.0%, to $2.75
per Mcfe for the nine months ended September 30, 2009, compared to $2.67 per Mcfe for the nine
months ended September 30, 2008.
Interest expense, net. Our interest expense, net, increased $439,000, or 48.0%, to $1.4 million
for the nine months ended September 30, 2009 from $914,000 for the nine months ended September 30,
2008. This increase was substantially the result of our higher average debt level in the 2009
period as partially offset by lower interest rates in the 2009 period.
20
Income taxes. Our income taxes decreased $13.0 million to a benefit of $317,000 for the nine months
ended September 30, 2009, from a provision of $12.7 million for the nine months ended September 30,
2008. The decrease in income tax provision was due to the decrease in our income before taxes.
Our effective income tax rate for the nine months ended September 30, 2009 was 9.7%, compared with
35.0% for the nine months ended September 30, 2008. The decrease in the effective rate resulted
primarily from an increased impact of permanent differences between book and taxable income,
partially offset by an increase in our estimated income tax expenses for the year ended December
31, 2008 and increased effective state income tax rates.
Liquidity and capital resources
We generally will rely on cash generated from operations, borrowings under our revolving credit
facility and, to the extent that credit and capital market conditions will allow, future public
equity and debt offerings to satisfy our liquidity needs. Our ability to fund planned capital
expenditures and to make acquisitions depends upon our future operating performance, 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 debt or equity financings beyond our revolving credit facility
will be available on acceptable terms, or at all, in the foreseeable future.
Our cash flow from operations is driven by commodity prices and 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. Our working capital is
significantly influenced by changes in commodity prices, and significant declines in prices will
cause a decrease in our exploration and development expenditures and production volumes. Our
working capital also is influenced by our efforts to lower our long-term debt and related interest
costs. Cash flows from operations are primarily used to fund exploration and development of our oil
and gas properties.
The following table summarizes our sources and uses of funds for the periods noted (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
|
2009 |
|
2008 |
|
Cash flows provided by operating activities |
|
$ |
22,930 |
|
|
$ |
45,896 |
|
Cash flows used in investing activities |
|
|
(19,468 |
) |
|
|
(72,670 |
) |
Cash flows (used in) provided by financing activities |
|
|
(6,848 |
) |
|
|
23,625 |
|
Effect of Canadian exchange rate |
|
|
9 |
|
|
|
(10 |
) |
|
|
|
|
|
|
|
Net (decrease) in cash and cash equivalents |
|
$ |
(3,377 |
) |
|
$ |
(3,159 |
) |
|
|
|
|
|
|
|
Operating activities
For the nine months ended September 30, 2009, our cash flows from operations, borrowings under our
revolving credit facility and available cash were used for drilling activities and for the payment
of a portion of our long-term debt. The $22.9 million in cash flows generated in the 2009 period
decreased $23.0 million from the same period in 2008 due primarily to a $36.4 million decline in
oil and gas sales and a $774,000 increase in working capital components as well as a net increase
of $12.6 million in other cash income and expense items.
21
Working capital
The decrease in working capital components, specifically joint interest owners accounts receivable,
accounts payable and accrued liabilities, is a result of our decreased drilling activity. The
decrease in oil and gas sales receivable and payable is primarily attributable to the sharp decline
in oil and gas prices.
Investing activities
The cash flows used in investing activities in the 2009 period were for the continued development
of our Cinco Terry and Ozona Northeast fields. For the comparable 2008 period, the cash flows used
in investing activities were primarily for the drilling of wells in our Ozona Northeast, Cinco
Terry and North Bald Prairie fields.
Capital expenditures for 2009
In December 2008, we announced a capital expenditure budget of $43.8 million for 2009. Due to the
extended decline of oil and natural gas prices, however, in March 2009 we announced that we would
not extend the contracts for our two remaining drilling rigs after March 31, 2009, and we released
these rigs during the first week of April 2009.
We have resumed drilling and currently are operating two rigs in Cinco Terry. We also have begun
3-D seismic operations in Cinco Terry. We plan to move one rig into Ozona Northeast in November
2009 to begin drilling. Given the anticipated increase in activity during the remainder of 2009,
we currently expect that our capital expenditures for the year ending December 31, 2009, including
these projects but excluding any acquisitions, will not exceed $30 million. We intend to fund
remaining 2009 capital expenditures, excluding any acquisitions, with internally-generated cash
flows. Our capital expenditure budget is subject to change depending upon a number of factors,
including economic and industry conditions at the time of drilling, prevailing and anticipated
prices for oil and gas, the results of our development and exploration efforts, the availability of
sufficient capital resources for drilling prospects, our financial results, the availability of
leases on reasonable terms and our ability to obtain permits for the drilling locations.
Estimated capital expenditures for 2010
The following table summarizes our estimated capital expenditures for 2010. We intend to fund 2010
capital expenditures, excluding any acquisitions, primarily out of internally-generated cash flows
and, as necessary, borrowings under our revolving credit facility.
|
|
|
|
|
|
|
Estimated |
|
|
|
Year Ended |
|
|
|
December 31, 2010 |
|
Area of Operation |
|
(in thousands) |
|
West Texas |
|
|
|
|
Ozona Northeast |
|
$ |
25,600 |
|
Cinco Terry |
|
|
19,950 |
|
Exploratory |
|
|
3,075 |
|
Lease acquisition, geological and geophysical |
|
|
4,375 |
|
|
|
|
|
Total capital expenditures |
|
$ |
53,000 |
|
|
|
|
|
Our capital expenditure budget for 2010 is subject to change depending upon a number of
factors, including economic and industry conditions at the time of drilling, prevailing and
anticipated prices for oil and gas, the results of our development and exploration efforts, the
availability of sufficient capital
22
resources for drilling prospects, our financial results, the
availability of leases on reasonable terms and our ability to obtain permits for the drilling
locations.
Financing activities
We borrowed $55.9 million and $83.9 million under our revolving credit facility during the nine
months ended September 30, 2009 and 2008, respectively. We repaid $62.5 million and $60.4 million
of the amounts borrowed under our revolving credit facility during the nine months ended September
30, 2009 and 2008, respectively.
Our current goal is to manage our borrowings to help us maintain financial flexibility and
liquidity, and to avoid the problems associated with highly-leveraged companies with large interest
costs and possible debt reductions restricting ongoing operations.
We believe that cash flows from operations and borrowings under our revolving credit facility will
finance substantially all of our capital needs through 2010. We may also use our revolving credit
facility for possible acquisitions and temporary working capital needs. Further, we may determine
to access the public equity or debt markets for potential acquisitions, working capital or other
liquidity needs, if such financing is available on acceptable terms.
Revolving credit facility
We have a $200 million revolving credit facility with a borrowing base set at $115 million. The
borrowing base is redetermined semi-annually on or before each April 1 and October 1 based on our
oil and gas reserves. We or the lenders can each request one additional borrowing base
redetermination each calendar year.
Currently, the maturity date under our revolving credit facility is July 31, 2011. Borrowings bear
interest based on the agent banks prime rate plus an applicable margin ranging from 1.25% to
2.25%, or the sum of the Eurodollar rate plus an applicable margin ranging from 2.25% to 3.25%.
Margins vary based on the borrowings outstanding compared to the borrowing base. In addition, we
pay an annual commitment of 0.50% of non-used borrowings available under our revolving credit
facility.
We had outstanding borrowings of $36.9 million and $43.5 million under our revolving credit
facility at September 30, 2009 and December 31, 2008, respectively. The weighted average interest
rate applicable to our outstanding borrowings was 2.92% and 3.25% as of September 30, 2009 and
December 31, 2008, respectively. We also had outstanding unused letters of credit under our
revolving credit facility totaling $400,000 at September 30, 2009, 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.
At October 31, 2009, we had $35.8 million outstanding under our revolving credit facility, with a
weighted average interest rate of 3.07%.
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 |
23
|
|
Current Assets (as defined in the credit agreement) by Consolidated
Current Liabilities (as defined in the credit agreement). As defined more specifically in the
credit agreement, the consolidated
modified current ratio is calculated as current assets less current unrealized gains on
commodity derivatives plus the available borrowing base at the respective balance sheet date,
divided by current liabilities less current unrealized losses on commodity derivatives at the
respective balance sheet date. |
|
|
|
a consolidated funded debt to consolidated EBITDAX ratio covenant that requires us to
maintain a ratio of not more than 3.5 to 1.0 at the end of each fiscal quarter. The
consolidated funded debt to consolidated EBITDAX ratio is calculated by dividing Consolidated
Funded Debt (as defined in the credit agreement) by Consolidated EBITDAX (as defined in the
credit agreement). As defined more specifically in the credit agreement, consolidated EBITDAX
is calculated as net income (loss), plus (1) exploration expense, (2) depletion, depreciation
and amortization expense, (3) share-based compensation expense, (4) unrealized loss on
commodity derivatives, (5) interest expense, (6) income and franchise taxes, and (7) certain
other non-cash expenses, less (1) gains or losses from sales or dispositions of assets, (2)
unrealized gain on commodity derivatives and (3) extraordinary or non-recurring 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 more specifically defined in the credit agreement) of the Company occurs, and
dissolution of the Company.
At September 30, 2009, we were in compliance with all of our covenants and had not committed any
acts of default under the credit agreement.
To date we have experienced no disruptions in our ability to access our revolving credit facility.
However, our lenders have substantial ability to reduce our borrowing base on the basis of
subjective factors, including the loan collateral value that each lender, in its discretion and
using the methodology, assumptions and discount rates as such lender customarily uses in evaluating
oil and gas properties, assigns to our properties.
We cannot predict with certainty the impact to us of any further disruption in the credit
environment or guarantee that the lenders under our revolving credit facility will not decrease our
borrowing base in the future. If our borrowing base was decreased below our total outstanding
borrowings, resulting in a borrowing base deficiency, then we would be required under the credit
agreement, within 15 days after notice from
24
the agent bank, to (i) pledge additional collateral to
cure the borrowing base deficiency, (ii) prepay the borrowing base deficiency in full, or (iii)
commit to repay the borrowing base deficiency in six equal monthly installments, with the first
installment being due within 30 days after receipt of notice from the agent bank. There is no
guarantee that, in the event of such a borrowing base deficiency, we would be able to timely cure
the deficiency.
Contractual obligations
There have been no material changes to our contractual obligations during the nine months ended
September 30, 2009.
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, 2009, the off-balance sheet arrangements and
transactions that we have entered into include undrawn letters of credit, operating lease
agreements and gas marketing commitments. We do not believe that these arrangements are reasonably
likely to materially affect our financial condition, changes in financial condition, revenues or
expenses, results of operations, liquidity, capital expenditures or capital resources.
|
|
|
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 flows. 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 non-cash write down of our oil and gas properties.
We enter into financial swaps and collars to partially mitigate the risk of market price
fluctuations. We do not designate such instruments as cash flow hedges. Accordingly, we record
open commodity derivative positions on our consolidated balance sheets at fair value and recognize
changes in such fair values as income (expense) on our consolidated statements of operations as
they occur.
25
At September 30, 2009, we had the following commodity derivatives positions outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
$/MMBtu |
|
Period |
|
Monthly |
|
|
Total |
|
|
Floor |
|
|
Ceiling |
|
|
Fixed |
|
NYMEX Henry Hub |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price collars 2009 |
|
|
180,000 |
|
|
|
540,000 |
|
|
$ |
7.50 |
|
|
$ |
10.50 |
|
|
|
|
|
Price collars 2009 |
|
|
130,000 |
|
|
|
390,000 |
|
|
$ |
8.50 |
|
|
$ |
11.70 |
|
|
|
|
|
Price swaps 2009 |
|
|
150,000 |
|
|
|
450,000 |
|
|
|
|
|
|
|
|
|
|
$ |
4.50 |
|
Price swaps 2010 |
|
|
150,000 |
|
|
|
1,800,000 |
|
|
|
|
|
|
|
|
|
|
$ |
5.85 |
|
Price swaps 2010 |
|
|
150,000 |
|
|
|
1,800,000 |
|
|
|
|
|
|
|
|
|
|
$ |
6.40 |
|
WAHA basis differential |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis swaps 2009 |
|
|
200,000 |
|
|
|
600,000 |
|
|
|
|
|
|
|
|
|
|
$ |
(0.61 |
) |
Basis swaps 2009 |
|
|
300,000 |
|
|
|
900,000 |
|
|
|
|
|
|
|
|
|
|
$ |
(0.67 |
) |
Basis swaps 2010 |
|
|
415,000 |
|
|
|
4,980,000 |
|
|
|
|
|
|
|
|
|
|
$ |
(0.71 |
) |
Basis swaps 2011 |
|
|
300,000 |
|
|
|
3,600,000 |
|
|
|
|
|
|
|
|
|
|
$ |
(0.53 |
) |
At September 30, 2009 and December 31, 2008, the fair value of our open derivative contracts
was a net liability of approximately $572,000 and a net asset of approximately $8.0 million,
respectively.
Subsequent to September 30, 2009, we entered into a NYMEX Henry Hub price swap at $6.36 per
MMBtu for 100,000 MMBtu per month for 2010.
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 value the collar 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.
|
|
|
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 Securities and Exchange Act of 1934, as
amended (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 for disclosure is 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) under the Exchange Act) as of
September 30, 2009. Based on this evaluation, the CEO and CFO have concluded that, as of September
30, 2009, 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.
26
Internal control over financial reporting
There were no changes made in our internal control over financial reporting (as defined in Rule
13a-15(f) under the Exchange Act) during the three months ended September 30, 2009, that have
materially affected, or are reasonably likely to materially affect, our internal control over
financial reporting.
Limitations inherent in all controls
Our management, including the CEO and CFO, recognizes that the disclosure controls and procedures
and internal controls (discussed above) cannot prevent all errors or all attempts at fraud. Any
controls system, no matter how well crafted and operated, can only provide reasonable, and not
absolute, assurance of achieving the desired control objectives. Because of the inherent
limitations in any control system, no evaluation or implementation of a control system can provide
complete assurance that all control issues and all possible instances of fraud have been or will be
detected.
27
PART II OTHER INFORMATION
Item 1. Legal proceedings.
Our operating subsidiary filed a lawsuit in July 2009 against EnCana Oil & Gas (USA) Inc.
(EnCana) in the District Court of Limestone County, Texas, for breach of the joint operating
agreement (JOA) covering our North Bald Prairie project in East Texas. This proceeding is
described in more detail in Part II, Item 1, Legal Proceedings, in our Quarterly Report on Form
10-Q for the three months ended June 30, 2009 filed with the SEC on August 7, 2009 and Note 5 to our consolidated financial statements
in this Quarterly Report on Form 10-Q for the three months ended September 30, 2009.
During the three months ended September 30, 2009, EnCana began suspending payment of amounts owed
under the JOA, in addition to prior amounts either not paid or underpaid by EnCana. In October
2009, EnCana filed a Motion to Compel Arbitration and Stay Litigation and delivered a demand for
arbitration, alleging that the parties claims, including EnCanas claim that we should have
transferred operatorship of North Bald Prairie in December 2008, should be subject to binding
arbitration under a carry and earning agreement between the parties. We have opposed EnCanas
filing, informed the court that we will transfer operatorship to EnCana when EnCana has made all
payments it owes under the JOA and requested that the court stay any arbitration proceeding until
such payment issues have been resolved.
We also are involved in various other legal and regulatory proceedings arising in the normal course
of business. While we cannot predict the outcome of these proceedings with certainty, we do not
believe that an adverse result in any pending legal or regulatory proceeding, together or in the
aggregate, would be material to our consolidated financial condition, results of operations or cash
flows.
Item 1A. Risk factors.
In addition to the other information set forth in this report, you should carefully consider the
risks discussed in the following reports that we have filed with the SEC, which risks could
materially affect our business, financial condition and results of operations: Annual Report on
Form 10-K for the year ended December 31, 2008, under the headings Items 1. and 2. Business and
Properties Markets and Customers; Competition; and Regulation, Item 1A. Risk Factors, and
Item 7A. Quantitative and Qualitative Disclosures about Market Risk filed with the SEC on March
13, 2009 and Quarterly Report on Form 10-Q for the three months ended June 30, 2009 filed with the
SEC on August 7, 2009.
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, 2008 and in our Quarterly Report on Form 10-Q for the three months
ended June 30, 2009 filed with the SEC on March 13, 2009 and August 7, 2009, respectively, which
are accessible on the SECs website at www.sec.gov and our website at www.approachresources.com.
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, 2009. The repurchases reflect shares withheld upon
vesting of restricted stock under our 2007 Stock Incentive Plan to satisfy statutory minimum tax
withholding obligations.
28
Issuer purchases of equity securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
|
|
|
|
|
(c) |
|
|
(d) |
|
|
|
Total |
|
|
(b) |
|
|
Total Number of |
|
|
Maximum Number of |
|
|
|
Number of |
|
|
Average |
|
|
Shares Purchased |
|
|
Shares that May Yet Be |
|
|
|
Shares |
|
|
Price Paid |
|
|
as Part of Publicly |
|
|
Purchased Under the |
|
Period |
|
Purchased |
|
|
Per Share |
|
|
Announced Plans |
|
|
Plans or Programs |
|
Month #1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(July 1, 2009 July 31, 2009) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Month #2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(August 1, 2009 August 31, 2009) |
|
|
719 |
|
|
$ |
7.47 |
|
|
|
|
|
|
|
|
|
Month #3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(September 1, 2009 September 30, 2009) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
719 |
|
|
$ |
7.47 |
|
|
|
|
|
|
|
|
|
Item 3. Defaults upon senior securities.
None.
Item 4. Submission of matters to a vote of security holders.
None.
Item 5. Other information.
None.
Item 6. Exhibits.
See Index to Exhibits following the signature page of this report for a description of the
exhibits filed as part of this report.
29
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
|
|
|
|
|
APPROACH RESOURCES INC.
|
|
|
By: |
/s/ J. Ross Craft
|
|
|
|
J. Ross Craft |
|
|
|
President and Chief Executive Officer
(Principal Executive Officer) |
|
|
|
|
|
|
By: |
/s/ Steven P. Smart
|
|
|
|
Steven P. Smart |
|
|
|
Executive Vice President and Chief Financial Officer (Principal
Financial and Chief Accounting Officer) |
|
|
Date: November 5, 2009
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
|
|
Form of Indemnity Agreement between Approach Resources Inc. and
each of its directors and officers (filed as Exhibit 10.1 to
the Companys Registration Statement on Form S-1/A filed
September 13, 2007 (File No. 333-144512) and incorporated
herein by reference). |
10.2
|
|
First Amendment to Form of Indemnity Agreement between Approach
Resources Inc. and each of its directors and officers (filed as
Exhibit 10.5 to the Companys Current Report on Form 8-K filed
December 31, 2008 and incorporated herein by reference). |
10.3
|
|
Employment Agreement by and between Approach Resources Inc. and
J. Ross Craft dated January 1, 2003 (filed as Exhibit 10.3 to
the Companys Registration Statement on Form S-1 filed July 12,
2007 and incorporated herein by reference). |
10.4
|
|
First Amendment to Employment Agreement by and between Approach
Resources Inc. and J. Ross Craft dated December 31, 2008 (filed
as Exhibit 10.2 to the Companys Current Report on Form 8-K
filed December 31, 2008 and incorporated herein by reference). |
10.5
|
|
Employment Agreement by and between Approach Resources Inc. and
Steven P. Smart dated January 1, 2003 (filed as Exhibit 10.4 to
the Companys Registration Statement on Form S-1 filed July 12,
2007 and incorporated herein by reference). |
10.6
|
|
First Amendment to Employment Agreement by and between Approach
Resources Inc. and Steven P. Smart dated December 31, 2008
(filed as Exhibit 10.3 to the Companys Current Report on Form
8-K filed December 31, 2008 and incorporated herein by
reference). |
10.7
|
|
Employment Agreement by and between Approach Resources Inc. and
Glenn W. Reed dated January 1, 2003 (filed as Exhibit 10.5 to
the Companys Registration Statement on Form S-1 filed July 12,
2007 and incorporated herein by reference). |
10.8
|
|
First Amendment to Employment Agreement by and between Approach
Resources Inc. and Glenn W. Reed dated December 31, 2008 (filed
as Exhibit 10.4 to the Companys Current Report on Form 8-K
filed December 31, 2008 and incorporated herein by reference). |
10.9
|
|
Approach Resources Inc. 2007 Stock Incentive Plan, effective as
of June 28, 2007 (filed as Exhibit 10.6 to the Companys
Registration Statement on Form S-1 filed July 12, 2007 and
incorporated herein by reference). |
|
|
|
Exhibit |
|
|
Number |
|
Description of Exhibit |
10.10
|
|
First Amendment dated December 31, 2008 to Approach Resources
Inc. 2007 Stock Incentive Plan, effective as of June 28, 2007
(filed as Exhibit 10.1 to the Companys Current Report on Form
8-K filed December 31, 2008 and incorporated herein by
reference). |
10.11
|
|
Form of Business Opportunities Agreement among Approach
Resources Inc. and the other signatories thereto (filed as
Exhibit 10.11 to the Companys Registration Statement on Form
S-1/A filed October 18, 2007 (File No. 333-144512) and
incorporated herein by reference). |
10.12
|
|
Form of Option Agreement under 2003 Stock Option Plan (filed as
Exhibit 10.12 to the Companys Registration Statement on Form
S-1 filed July 12, 2007 and incorporated herein by reference). |
10.13
|
|
Restricted Stock Award Agreement by and between Approach
Resources Inc. and J. Curtis Henderson dated March 14, 2007
(filed as Exhibit 10.13 to the Companys Registration Statement
on Form S-1 filed July 12, 2007 and incorporated herein by
reference). |
10.14
|
|
Form of Summary of Stock Option Grant under Approach Resources
Inc. 2007 Stock Incentive Plan (filed as Exhibit 10.14 to the
Companys Registration Statement on Form S-1/A filed October
18, 2007 (File No. 333-144512) and incorporated herein by
reference). |
10.15
|
|
Form of Restricted Stock Award Agreement under Approach
Resources Inc. 2007 Stock Incentive Plan (filed as Exhibit
10.10 to the Companys Quarterly Report on Form 10-Q filed
November 6, 2008 and incorporated herein by reference). |
10.16
|
|
Registration Rights Agreement dated as of November 14, 2007, by
and among Approach Resources Inc. and investors identified
therein (filed as Exhibit 10.1 to the Companys Current Report
on Form 8-K/A filed December 3, 2007 and incorporated herein by
reference). |
10.17
|
|
Gas Purchase Contract dated May 1, 2004 between Ozona Pipeline
Energy Company, as Buyer, and Approach Resources I, L.P. and
certain other parties identified therein (filed as Exhibit
10.18 to the Companys Registration Statement on Form S-1/A
filed September 13, 2007 (File No. 333-144512) and incorporated
herein by reference). |
10.18
|
|
Agreement Regarding Gas Purchase Contract dated May 26, 2005
between Ozona Pipeline Energy Company, as Buyer, and Approach
Resources I, L.P. and certain other parties identified therein
(filed as Exhibit 10.19 to the Companys Registration Statement
on Form S-1/A filed September 13, 2007 (File No. 333-144512)
and incorporated herein by reference). |
10.19
|
|
Oil & Gas Lease dated February 27, 2007 between the lessors
identified therein and Approach Oil & Gas Inc., as successor to
Lynx Production Company, Inc. (filed as Exhibit 10.23 to the
Companys Registration Statement on Form S-1/A filed September
13, 2007 (File No. 333-144512) and incorporated herein by
reference). |
10.20
|
|
Specimen Oil and Gas Lease for Boomerang prospect between
lessors and Approach Oil & Gas Inc., as successor to The Keeton
Group, LLC, as lessee (filed as Exhibit 10.24 to the Companys
Registration Statement on Form S-1/A filed September 13, 2007
(File No. 333-144512) and incorporated herein by reference). |
10.21
|
|
Lease Crude Oil Purchase Agreement dated May 1, 2004 by and
between ConocoPhillips and Approach Operating LLC (filed as
Exhibit 10.26 to the Companys Registration Statement on Form
S-1/A filed October 18, 2007 (File No. 333-144512) and
incorporated herein by reference). |
|
|
|
Exhibit |
|
|
Number |
|
Description of Exhibit |
10.22
|
|
Gas Purchase Agreement dated as of November 21, 2007 between
WTG Benedum Joint Venture, as Buyer, and Approach Oil & Gas
Inc. and Approach Operating, LLC, as Seller (filed as Exhibit
10.1 to the Companys Current Report on Form 8-K filed November
28, 2007 and incorporated herein by reference). |
10.23
|
|
$200,000,000 Revolving Credit Agreement dated as of January 18,
2008 among Approach Resources Inc., as borrower, The Frost
National Bank, as administrative agent and lender, and the
financial institutions named therein (filed as Exhibit 10.1 to
the Companys Current Report on Form 8-K filed January 23, 2008
and incorporated herein by reference). |
10.24
|
|
Amendment dated February 19, 2008 to Credit Agreement among
Approach Resources Inc., as borrower, The Frost National Bank,
as administrative agent and lender, JPMorgan Chase Bank, NA, as
lender, and Approach Oil & Gas Inc., Approach Oil & Gas
(Canada) Inc. and Approach Resources I, LP, as guarantors,
dated as of January 18, 2008 (filed as Exhibit 10.1 to the
Companys Current Report on Form 8-K filed February 22, 2008
and incorporated herein by reference). |
10.25
|
|
Amendment dated May 6, 2008 to Credit Agreement among Approach
Resources Inc., as borrower, The Frost National Bank, as
administrative agent and lender, JPMorgan Chase Bank, NA, as
lender, and Approach Oil & Gas Inc., Approach Oil & Gas
(Canada) Inc. and Approach Resources I, LP, as guarantors,
dated as of January 18, 2008 (filed as Exhibit 99.1 to the
Companys Current Report on Form 8-K filed August 28, 2008 and
incorporated herein by reference). |
10.26
|
|
Amendment dated August 26, 2008 to Credit Agreement among
Approach Resources Inc., as borrower, The Frost National Bank,
as administrative agent and lender, JPMorgan Chase Bank, NA,
Fortis Capital Corp. and KeyBank National Association, as
lenders, and Approach Oil & Gas Inc., Approach Oil & Gas
(Canada) Inc. and Approach Resources I, LP, as guarantors,
dated as of January 18, 2008 (filed as Exhibit 10.1 to the
Companys Current Report on Form 8-K filed August 28, 2008 and
incorporated herein by reference). |
10.27
|
|
Amendment dated April 8, 2009 to Credit Agreement among
Approach Resources Inc., as borrower, The Frost National Bank,
as administrative agent and lender, JPMorgan Chase Bank, NA,
Fortis Capital Corp. and KeyBank National Association, as
lenders, and Approach Oil & Gas Inc., Approach Oil & Gas
(Canada) Inc. and Approach Resources I, LP, as guarantors,
dated as of January 18, 2008 (filed as Exhibit 10.1 to the
Companys Current Report on Form 8-K filed April 16, 2009 and
incorporated herein by reference). |
10.28
|
|
Amendment dated July 8, 2009 to Credit Agreement among Approach
Resources Inc., as borrower, The Frost National Bank, as
administrative agent and lender, JPMorgan Chase Bank, NA,
Fortis Capital Corp. and KeyBank National Association, as
lenders, and Approach Oil & Gas Inc., Approach Oil & Gas
(Canada) Inc. and Approach Resources I, LP, as guarantors,
dated as of January 18, 2008 (filed as Exhibit 10.1 to the
Companys Current Report on Form 8-K filed July 14, 2009 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. |
|
|
|
Exhibit |
|
|
Number |
|
Description of Exhibit |
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. |
|
|
|
* |
|
Filed herewith. |
|
|
|
Denotes management contract or compensatory plan or arrangement. |