Attached files
file | filename |
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EX-10.1 - EX-10.1 - Alta Mesa Holdings, LP | h83108exv10w1.htm |
EX-32.2 - EX-32.2 - Alta Mesa Holdings, LP | h83108exv32w2.htm |
EX-31.2 - EX-31.2 - Alta Mesa Holdings, LP | h83108exv31w2.htm |
EX-10.3 - EX-10.3 - Alta Mesa Holdings, LP | h83108exv10w3.htm |
EX-32.1 - EX-32.1 - Alta Mesa Holdings, LP | h83108exv32w1.htm |
EX-10.2 - EX-10.2 - Alta Mesa Holdings, LP | h83108exv10w2.htm |
EXCEL - IDEA: XBRL DOCUMENT - Alta Mesa Holdings, LP | Financial_Report.xls |
EX-31.1 - EX-31.1 - Alta Mesa Holdings, LP | h83108exv31w1.htm |
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 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: June 30, 2011
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: 333-173751
ALTA MESA HOLDINGS, LP
(Exact name of registrant as specified in its charter)
Texas (State or other jurisdiction of incorporation or organization) |
20-3565150 (I.R.S. Employer Identification No.) |
|
15021 Katy Freeway, Suite 400, Houston, Texas (Address of principal executive offices) |
77094 (Zip Code) |
Registrants telephone number, including area code: 281-530-0991
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 o No þ
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 þ 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 definition of large accelerated filer,
accelerated filer, and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one)
Large accelerated filer o | Accelerated filer o | Non-accelerated filer þ (Do not check if a smaller reporting company) | Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ
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EX-101 INSTANCE DOCUMENT | ||||||||
EX-101 SCHEMA DOCUMENT | ||||||||
EX-101 CALCULATION LINKBASE DOCUMENT | ||||||||
EX-101 LABELS LINKBASE DOCUMENT | ||||||||
EX-101 PRESENTATION LINKBASE DOCUMENT |
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Table of Contents
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
The information in this report includes forward-looking statements. All statements,
other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding
our strategy, future operations, financial position, estimated revenues and losses, projected
costs, prospects, plans and objectives of management are forward-looking statements. When used in
this report, the words could, should, will, play, believe, anticipate, intend,
estimate, expect, project and similar expressions are intended to identify forward-looking
statements, although not all forward-looking statements contain such identifying words. These
forward-looking statements are based on our current expectations and assumptions about future
events and are based on currently available information as to the outcome and timing of future
events. When considering forward-looking statements, you should keep in mind the risk factors and
other cautionary statements described under the heading Risk Factors included in our Registration
Statement on Form S-4 (Commission File No. 333-173751 filed on July 11, 2011, the Form S-4) and
Part II, Item 1A of this report. These forward-looking statements are based on managements current
belief, based on currently available information, as to the outcome and timing of future events.
Forward-looking statements may include statements about our:
| business strategy; | ||
| reserves; | ||
| financial strategy, liquidity and capital required for our development program; | ||
| realized oil and natural gas prices; | ||
| timing and amount of future production of oil and natural gas; | ||
| hedging strategy and results; | ||
| future drilling plans; | ||
| competition and government regulations; | ||
| marketing of oil and natural gas; | ||
| leasehold or business acquisitions; | ||
| costs of developing our properties; | ||
| liquidity and access to capital; | ||
| uncertainty regarding our future operating results; and | ||
| plans, objectives, expectations and intentions contained in this report that are not historical. |
We caution you that these forward-looking statements are subject to all of the risks and
uncertainties, most of which are difficult to predict and many of which are beyond our control,
incident to the exploration for and development and production of oil and natural gas. These risks
include, but are not limited to volatility of oil and natural gas prices, general economic conditions, credit
markets, inflation, the credit rating of U.S. government debt, production timing and volumes, estimates of proved reserves, operating costs and capital expenditures, lack of availability of
drilling and production equipment and services, environmental risks, drilling and other operating
risks, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and
in projecting future rates of production, cash flow and access to capital, and the other risks described under Risk Factors in our Form S-4.
Reserve engineering is a process of estimating underground accumulations of oil and natural
gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the
quality of available
3
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data, the interpretation of such data and price and cost assumptions made by reservoir
engineers. In addition, the results of drilling, testing and production activities may justify
revisions of estimates that were made previously. If significant, such revisions would change the
schedule of any further production and development drilling. Accordingly, reserve estimates may
differ significantly from the quantities of oil and natural gas that are ultimately recovered.
Should one or more of the risks or uncertainties described in the Form S-4 or this report
occur, or should underlying assumptions prove incorrect, our actual results and plans could differ
materially from those expressed in any forward-looking statements.
All forward-looking statements, expressed or implied, included in this report are expressly
qualified in their entirety by this cautionary statement. This cautionary statement should also be
considered in connection with any subsequent written or oral forward-looking statements that we or
persons acting on our behalf may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any
forward-looking statements, all of which are expressly qualified by the statements in this section,
to reflect events or circumstances after the date of this Quarterly Report on Form 10-Q.
4
Table of Contents
PART I FINANCIAL INFORMATION
ITEM 1. Financial Statements
ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
(dollars in thousands)
June 30, | December 31, | |||||||
2011 | 2010 | |||||||
(unaudited) | ||||||||
ASSETS |
||||||||
CURRENT ASSETS |
||||||||
Cash and cash equivalents |
$ | 5,523 | $ | 4,836 | ||||
Accounts receivable, net |
41,509 | 38,081 | ||||||
Other receivables |
1,947 | 6,338 | ||||||
Prepaid expenses and other current assets |
4,608 | 2,292 | ||||||
Derivative financial instruments |
11,125 | 10,436 | ||||||
TOTAL CURRENT ASSETS |
64,712 | 61,983 | ||||||
PROPERTY AND EQUIPMENT |
||||||||
Oil and natural gas properties, successful
efforts method, net |
527,863 | 442,880 | ||||||
Other property and equipment, net |
15,981 | 13,384 | ||||||
TOTAL PROPERTY AND EQUIPMENT, NET |
543,844 | 456,264 | ||||||
OTHER ASSETS |
||||||||
Investment in Partnership cost |
9,000 | 9,000 | ||||||
Deferred financing costs, net |
13,447 | 13,552 | ||||||
Derivative financial instruments |
8,668 | 14,165 | ||||||
Advances to operators |
5,980 | 2,699 | ||||||
Deposits |
1,323 | 576 | ||||||
TOTAL OTHER ASSETS |
38,418 | 39,992 | ||||||
TOTAL ASSETS |
$ | 646,974 | $ | 558,239 | ||||
LIABILITIES AND PARTNERS CAPITAL |
||||||||
CURRENT LIABILITIES |
||||||||
Accounts payable and accrued liabilities |
$ | 74,145 | $ | 87,255 | ||||
Current portion, asset retirement obligations |
1,755 | 1,617 | ||||||
Derivative financial instruments |
3,176 | 3,092 | ||||||
TOTAL CURRENT LIABILITIES |
79,076 | 91,964 | ||||||
LONG-TERM LIABILITIES |
||||||||
Asset retirement obligations |
44,487 | 41,096 | ||||||
Long-term debt |
457,906 | 371,276 | ||||||
Notes payable to founder |
20,309 | 19,709 | ||||||
Derivative financial instruments |
1,704 | 2,296 | ||||||
Other long-term liabilities |
5,440 | 7,240 | ||||||
TOTAL LONG-TERM LIABILITIES |
529,846 | 441,617 | ||||||
TOTAL LIABILITIES |
608,922 | 533,581 | ||||||
COMMITMENTS AND CONTINGENCIES (NOTE 10) |
||||||||
PARTNERS CAPITAL |
38,052 | 24,658 | ||||||
TOTAL LIABILITIES AND PARTNERS CAPITAL |
$ | 646,974 | $ | 558,239 | ||||
See notes to consolidated financial statements.
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Table of Contents
ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(dollars in thousands)
(unaudited)
(dollars in thousands)
(unaudited)
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
REVENUES |
||||||||||||||||
Natural gas |
$ | 38,731 | $ | 30,120 | $ | 74,112 | $ | 57,935 | ||||||||
Oil |
39,292 | 16,278 | 71,489 | 25,799 | ||||||||||||
Natural gas liquids |
2,847 | 1,214 | 5,900 | 1,943 | ||||||||||||
Other revenues |
297 | 386 | 766 | 407 | ||||||||||||
81,167 | 47,998 | 152,267 | 86,084 | |||||||||||||
Unrealized gain (loss) oil and natural
gas derivative contracts |
14,377 | 2,105 | (4,808 | ) | 22,908 | |||||||||||
TOTAL REVENUES |
95,544 | 50,103 | 147,459 | 108,992 | ||||||||||||
EXPENSES |
||||||||||||||||
Lease and plant operating expense |
15,041 | 9,354 | 28,372 | 17,432 | ||||||||||||
Production and ad valorem taxes |
4,069 | 2,785 | 9,470 | 4,398 | ||||||||||||
Workover expense |
2,352 | 1,330 | 3,978 | 3,289 | ||||||||||||
Exploration expense |
5,690 | 1,651 | 8,421 | 4,572 | ||||||||||||
Depreciation, depletion, and amortization |
22,963 | 13,500 | 42,431 | 22,122 | ||||||||||||
Impairment expense |
4,929 | 643 | 10,755 | 2,093 | ||||||||||||
Accretion expense |
476 | 270 | 946 | 415 | ||||||||||||
General and administrative expenses |
8,843 | 4,679 | 14,593 | 6,902 | ||||||||||||
TOTAL EXPENSES |
64,363 | 34,212 | 118,966 | 61,223 | ||||||||||||
INCOME FROM OPERATIONS |
31,181 | 15,891 | 28,493 | 47,769 | ||||||||||||
OTHER INCOME (EXPENSE) |
||||||||||||||||
Interest expense |
(6,843 | ) | (4,530 | ) | (16,323 | ) | (8,729 | ) | ||||||||
Interest income |
12 | 5 | 14 | 5 | ||||||||||||
Gain on contract settlement |
1,285 | | 1,285 | | ||||||||||||
TOTAL OTHER INCOME (EXPENSE) |
(5,546 | ) | (4,525 | ) | (15,024 | ) | (8,724 | ) | ||||||||
INCOME BEFORE STATE INCOME TAXES |
25,635 | 11,366 | 13,469 | 39,045 | ||||||||||||
(PROVISION FOR) STATE INCOME
TAXES |
(75 | ) | | (75 | ) | | ||||||||||
NET INCOME |
$ | 25,560 | $ | 11,366 | $ | 13,394 | $ | 39,045 | ||||||||
See notes to consolidated financial statements.
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Table of Contents
ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)
(unaudited)
(dollars in thousands)
(unaudited)
Six Months Ended June 30, | ||||||||
2011 | 2010 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||
Net income |
$ | 13,394 | $ | 39,045 | ||||
Adjustments
to reconcile net income to net cash provided by operating activities: |
||||||||
Depreciation, depletion, and amortization |
42,431 | 22,122 | ||||||
Impairment expense |
10,755 | 2,093 | ||||||
Accretion expense |
946 | 415 | ||||||
Amortization of loan costs |
1,694 | 629 | ||||||
Amortization of debt discount |
130 | | ||||||
Dry hole expense |
5,267 | 219 | ||||||
Unrealized (gain) loss on derivatives |
4,300 | (23,311 | ) | |||||
(Gain) on contract settlement |
(1,285 | ) | | |||||
Interest converted into debt |
600 | 590 | ||||||
Settlement of asset retirement obligation |
(246 | ) | (463 | ) | ||||
Changes in assets and liabilities: |
||||||||
Accounts receivable |
(3,428 | ) | 619 | |||||
Other receivables |
4,391 | 148 | ||||||
Prepaid expenses and other non-current assets |
(6,344 | ) | (6,331 | ) | ||||
Accounts payable, accrued liabilities, other long-term liabilities |
(1,455 | ) | (19,669 | ) | ||||
NET CASH PROVIDED BY OPERATING ACTIVITIES |
71,150 | 16,106 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||
Capital expenditures for property and equipment |
(94,139 | ) | (32,289 | ) | ||||
Acquisitions |
(61,235 | ) | (101,359 | ) | ||||
NET CASH USED IN INVESTING ACTIVITIES |
(155,374 | ) | (133,648 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||
Proceeds from long-term debt |
86,500 | 95,000 | ||||||
Repayments of long-term debt |
| (167 | ) | |||||
Additions to deferred financing costs |
(1,589 | ) | (7,164 | ) | ||||
Capital contributions |
| 50,000 | ||||||
Capital distributions |
| (55 | ) | |||||
NET CASH PROVIDED BY FINANCING ACTIVITIES |
84,911 | 137,614 | ||||||
NET INCREASE IN CASH |
687 | 20,072 | ||||||
CASH AND CASH EQUIVALENTS, beginning of period |
4,836 | 4,274 | ||||||
CASH AND CASH EQUIVALENTS, end of period |
$ | 5,523 | $ | 24,346 | ||||
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION |
||||||||
Cash paid during the period for interest |
$ | 16,484 | $ | 8,234 | ||||
Cash paid during the period for taxes |
$ | | $ | | ||||
Change in property asset retirement obligations, net |
$ | 2,829 | $ | 326 | ||||
Change in accruals or liabilities for capital expenditures |
$ | (12,170 | ) | $ | 14,871 |
See notes to consolidated financial statements.
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Table of Contents
ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
1. SUMMARY OF ORGANIZATION AND NATURE OF OPERATIONS
The consolidated financial statements reflect the accounts of Alta Mesa Holdings, LP and its
subsidiaries (we, us, our, the Company, and Alta Mesa) after elimination of all significant
intercompany transactions and balances. The financial statements should be read in conjunction
with the consolidated financial statements and notes thereto included in our annual consolidated
financial statements for the year ended December 31, 2010, which were filed with the Securities and
Exchange Commission in our Registration Statement on Form S-4 (Commission File No. 333-173751).
The consolidated financial statements included herein as of June 30, 2011, and for the six month
periods ended June 30, 2011 and 2010, are unaudited, and in the opinion of management, the
information furnished reflects all material adjustments, consisting of normal recurring
adjustments, necessary for a fair presentation of consolidated financial position and of the
results of operations for the interim periods presented. The consolidated financial statements
have been prepared in accordance with accounting principles generally accepted in the U.S. (GAAP)
for interim financial information and with the instructions to Form 10-Q and Article 10 of
Regulation S-X. Accordingly, they do not include all of the information and footnotes required by
GAAP for complete financial statements. Certain minor reclassifications of prior period
consolidated financial statements have been made to conform to current reporting practices. The
consolidated results of operations for interim periods are not necessarily indicative of results to
be expected for a full year.
We use accounting policies which reflect industry practices and conform to GAAP. As used herein,
the following acronyms have the following meanings: FASB means the Financial Accounting
Standards Board; the Codification refers to the Accounting Standards Codification, the collected
accounting and reporting guidance maintained by the FASB; ASC means Accounting Standards
Codification and is generally followed by a number indicating a particular section of the
Codification; and ASU means Accounting Standards Update, followed by an identification number,
which are the periodic updates made to the Codification by the FASB. SEC means the Securities
and Exchange Commission.
Organization: The consolidated financial statements presented herein are of Alta Mesa
Holdings, LP and its (i) wholly-owned subsidiaries: Alta Mesa Finance Services Corp., Alta Mesa
Eagle, LLC, Alta Mesa Acquisition Sub, LLC, and its direct and indirect wholly-owned subsidiaries,
Alta Mesa Energy, LLC, Aransas Resources, LP and its wholly-owned subsidiary ARI Development, LLC,
Brayton Resources II, LP, Buckeye Production Company, LP, Galveston Bay Resources, LP, Louisiana
Exploration & Acquisitions, LP and its wholly-owned subsidiary Louisiana Exploration & Acquisition
Partnership, LLC, Navasota Resources, Ltd., LLP, Nueces Resources, LP, Oklahoma Energy
Acquisitions, LP, Alta Mesa Drilling, LLC, Petro Acquisitions, LP, Petro Operating Company, LP,
Texas Energy Acquisitions, LP, Virginia Oil and Gas, LLC and Alta Mesa Services, LP, and (ii)
partially-owned subsidiaries: Brayton Resources, LP, and Orion Operating Company, LP.
Nature of Operations: We are engaged primarily in the acquisition, exploration,
development, and production of oil and natural gas properties. Our properties are located
primarily in Texas, Oklahoma, Louisiana, Florida and the Appalachian Region.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
As of June 30, 2011, our significant accounting policies are consistent with those discussed in
Note 2 of the consolidated financial statements for the fiscal year ended December 31, 2010.
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Use of Estimates: The preparation of consolidated financial statements in conformity with
GAAP requires management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at the date of the
consolidated financial statements and the reported amounts of revenues and expenses during the
reporting period.
Reserve estimates significantly impact depreciation, depletion and amortization expense and
potential impairments of oil and natural gas properties and are subject to change based on changes
in oil and natural gas prices and trends and changes in estimated reserve quantities. We analyze
estimates, including those related to oil and natural gas reserves, oil and natural gas revenues,
the value of oil and natural gas properties, bad debts, asset
retirement obligations, derivative contracts, income taxes and contingencies and litigation. We
base our estimates on historical experience and various other assumptions that are believed to be
reasonable under the circumstances. Actual results may differ from these estimates.
Property and Equipment: Oil and natural gas producing activities are accounted for using
the successful efforts method of accounting. Under the successful efforts method, lease
acquisition costs and all development costs, including unsuccessful development wells, are
capitalized.
Unproved Properties Acquisition costs associated with the acquisition of leases are recorded as
unproved leasehold costs and capitalized as incurred. These consist of costs incurred in obtaining
a mineral interest or right in a property such as a lease, in addition to options to lease, broker
fees, recording fees and other similar costs related to activities in acquiring properties.
Leasehold costs are classified as unproved until proved reserves are discovered, at which time
related costs are transferred to proved oil and natural gas properties.
Exploration Expense Exploration expenses, other than exploration drilling costs, are charged to
expense as incurred. These costs include seismic expenditures and other geological and geophysical
costs, expired leases, and lease rentals. The costs of drilling exploratory wells and
exploratory-type stratigraphic wells are initially capitalized pending determination of whether the
well has discovered proved commercial reserves. If the exploratory well is determined to be
unsuccessful, the cost of the well is transferred to expense. Exploratory well drilling costs may
continue to be capitalized if the reserve quantity is sufficient to justify completion as a
producing well and sufficient progress in assessing the reserves and the economic and operating
viability of the project is being made. Assessments of such capitalized costs are made quarterly.
Proved Oil and Natural Gas Properties Costs incurred to obtain access to proved reserves and to
provide facilities for extracting, treating, gathering, and storing oil and natural gas are
capitalized. All costs incurred to drill and equip successful exploratory wells, development
wells, development-type stratigraphic test wells, and service wells, including unsuccessful
development wells, are capitalized.
Impairment The capitalized costs of proved oil and natural gas properties are reviewed quarterly
for impairment in accordance with ASC 360-10-35, Property, Plant and Equipment, Subsequent
Measurement, or whenever events or changes in circumstances indicate that the carrying amount of a
long-lived asset or asset group exceeds its fair market value and is not recoverable. The
determination of recoverability is based on comparing the estimated undiscounted future net cash
flows at a producing field level to the carrying value of the assets. If the future undiscounted
cash flows, based on estimates of anticipated production from proved reserves and future crude oil
and natural gas prices and operating costs, are lower than the carrying cost, the carrying cost of
the asset or group of assets is reduced to fair value. For our proved oil and natural gas
properties, we estimate fair value by discounting the projected future cash flows at an appropriate
risk-adjusted discount rate.
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Unproved leasehold costs are assessed quarterly to determine whether they have been impaired.
Individually significant properties are assessed for impairment on a property-by-property basis,
while individually insignificant unproved leasehold costs may be assessed in the aggregate. If
unproved leasehold costs are found to be impaired, an impairment allowance is provided and a loss
is recognized in the consolidated statement of income.
Depreciation, Depletion, and Amortization Depreciation, depletion, and amortization (DD&A) of
capitalized costs of proved oil and natural gas properties is computed using the unit-of-production
method based upon estimated proved reserves. Assets are grouped for DD&A on the basis of
reasonable aggregation of properties with a common geological structural feature or stratigraphic
condition, such as a reservoir or field. The reserve base used to calculate DD&A for leasehold
acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves
and proved undeveloped reserves. The reserve base used to calculate DD&A for lease and well
equipment costs, which include development costs and successful exploration drilling costs,
includes only proved developed reserves.
Accounts Receivable, net: Our receivables arise from the sale of oil and natural gas to
third parties and joint interest owner receivables for properties in which we serve as the
operator. This concentration of customers may impact our overall credit risk, either positively or
negatively, in that these entities may be similarly affected by changes in economic or other
conditions affecting the oil and gas industry. Accounts receivable are generally not
collateralized. Accounts receivable are shown net of an allowance for doubtful accounts of
$957,000 and $338,000 at June 30, 2011 and December 31, 2010, respectively.
Deferred Financing Costs: Deferred financing costs and the amount of discount at which
notes payable have been issued (debt discount) are amortized using the straight-line method, which
approximates the interest method, over the term of the related debt. For the three months ended
June 30, 2011 and 2010, amortization of deferred financing costs included in interest expense
amounted to $790,000 and $506,000, respectively. For the six months ended June 30, 2011 and 2010,
amortization of deferred financing costs included in interest expense amounted to $1.7 million and
$629,000, respectively. Deferred financing costs are listed among our long-term assets, net of
accumulated amortization of $6.4 million and $4.7 million at June 30, 2011 and December 31, 2010,
respectively.
Financial Instruments: The fair value of cash, accounts receivable, other current assets,
and current liabilities approximate book value due to their short-term nature. The estimate of
fair value of long-term debt under our senior secured revolving credit facility (credit facility)
is not considered to be materially different from carrying value due to market rates of interest.
The fair value of the debt to our founder is not practicable to determine. We have estimated the
fair value of our senior notes payable at $299.3 million and $291 million on June 30, 2011 and
December 31, 2010, respectively. See Note 5 for further information on fair values of financial
instruments. See Note 8 for information on long-term debt.
Recent Accounting Pronouncements
On May 12, 2011, the FASB issued ASU No. 2011-04 to Topic 820, Fair Value Measurements, Amendments
to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. The
ASU changes certain definitions of terms used its guidance regarding fair value measurements, as
well as modifying certain disclosure requirements and other aspects of the guidance. We are
reviewing the ASU, which is effective for interim and annual periods beginning after December 15,
2011. We do not expect adoption of the guidance to have a material impact on our consolidated
financial position or results of operations.
On June 16, 2011, the FASB issued ASU No. 2011-05, Presentation of Comprehensive Income. This
standard eliminates the current option to report other comprehensive income and its components in
the statement of changes in equity. Two presentation options remain. Changes in comprehensive
income
10
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may be reported in a continuous statement of comprehensive income which presents the
components of net income as well as the components of comprehensive income. Alternatively, the
components of
comprehensive income may be reported in a separate statement of comprehensive income, which must
immediately follow the statement of net income. The ASU also creates a new requirement that
reclassifications from comprehensive income to net income be presented on a gross basis on the face
of the financial statements (previously net presentation and footnoting gross information was
permitted). The ASU applies to interim and year end reports and is effective for fiscal years
beginning after December 15, 2011, and is to be retrospectively applied to all periods presented in
such reports. Early adoption is permitted. We do not expect adoption of the guidance to have a
material impact on our consolidated financial position or results of operations.
3. SIGNIFICANT ACQUISITIONS
Meridian Acquisition
On and effective May 13, 2010, Alta Mesa Acquisition Sub, LLC (AMAS), a wholly owned subsidiary
of Alta Mesa Holdings, LP, acquired 100% of the shares of and merged with The Meridian Resource
Corporation (Meridian), with AMAS as the surviving entity. Meridian was a publicly traded
company engaged in exploration for and production of oil and natural gas. The oil and natural gas
properties of Meridian are similar and in some cases proximate to our areas of operation. Meridian
shareholders were paid in cash, funded by proceeds of our credit facility as well as a $50 million
equity contribution from our private equity partner Alta Mesa Investment Holdings Inc., an
affiliate of Denham Commodities Partners Fund IV LP (AMIH). The merger increased the oil portion
of our reserves portfolio, improving the balance of our reserves between oil and natural gas, and
provided significant additions to our library of 3-D seismic data.
Total cost of the acquisition was $158 million. It was recorded using the acquisition method of
accounting. The purchase price was allocated to acquired assets and assumed liabilities based on
their estimated fair values at date of acquisition. Acquisition-related costs of approximately
$532,000 were recorded in general and administrative expense for the year ended December 31, 2010.
Sydson Acquisition
On April 21, 2011, we purchased from Sydson Energy
and certain of its related parties (together, Sydson and the Sydson acquisition) certain oil and natural gas
assets primarily located in Texas and South Louisiana in which we had jointly participated with Sydson. The purchase
price was $27.5 million in cash (a total cost
of $28.4 million including abandonment liabilities we assumed). Total net proved reserves acquired are estimated to be
800 MBOE (5 Bcfe), 45% of which is oil. By virtue of this acquisition, we increased our after payout net revenue interest
in the Eagle Ford Shale by over 50%. Funding for the acquisition was provided through our credit facility. In addition,
litigation associated with a portion of the assets purchased was resolved as a result of the transaction.
TODD Acquisition
On June 17, 2011, we purchased from Texas Oil Distribution
& Development, Inc. and Matrix Petroleum LLC and certain other parties (together, TODD and the TODD acquisition)
certain oil and natural gas assets primarily located in Texas and South Louisiana in which we had jointly participated with
TODD. The purchase price was $22.5 million in cash (a total cost of $23.4 million including abandonment liabilities we
assumed). Total net proved reserves acquired are estimated to be 700 MBOE (4 Bcfe), 36% of which is oil. By virtue of
this acquisition, we increased our after payout net revenue interest in the Eagle Ford Shale by an additional 15%.
Funding for the acquisition was provided through our credit facility. In addition, litigation associated with TODD was
resolved as a result of the transaction.
A summary of the consideration paid and the allocations of the purchase prices (which are
preliminary for
11
Table of Contents
the Sydson and TODD acquisitions) are as follows (dollars in thousands):
Summary of Consideration: | Meridian | Sydson | TODD | |||||||||
Cash |
$ | 30,948 | $ | 27,500 | $ | 22,500 | ||||||
Debt retired |
82,000 | | | |||||||||
Debt assumed |
5,346 | | | |||||||||
Working capital deficit (1) |
753 | | | |||||||||
Other liabilities assumed |
7,971 | | | |||||||||
Fair value of asset retirement
obligations assumed |
30,920 | 922 | 863 | |||||||||
Total |
$ | 157,938 | $ | 28,422 | $ | 23,363 | ||||||
Summary of Purchase Price Allocations: |
||||||||||||
Proved oil and natural gas properties |
$ | 144,325 | $ | 18,330 | $ | 15,223 | ||||||
Unproved oil and natural gas properties |
3,113 | 10,092 | 8,140 | |||||||||
Other tangible assets |
10,500 | | | |||||||||
Total |
$ | 157,938 | $ | 28,422 | $ | 23,363 | ||||||
(1) | Meridian working capital deficit included a cash balance of $11,589,000. |
The revenue and earnings related to the Meridian, Sydson, and TODD acquisitions are included in our
consolidated statement of income for the six months ended June 30, 2011. The revenue and earnings
related to the Meridian acquisition are included in our consolidated statement of income for the
six months ended June 30, 2010. Revenue and earnings, had the acquisitions occurred on January 1,
2010, are provided below. This unaudited pro forma information has been derived from historical
information and is for illustrative purposes only. The unaudited pro forma financial information
does not attempt to predict or suggest future results. It also does not necessarily reflect what
the historical results of the combined company would have been had the companies been combined
during these periods.
(Unaudited) | ||||||||
Revenue | Income | |||||||
(dollars in thousands) | ||||||||
Actual results of Meridian
included in our statement of
income for the six months
ended June 30, 2011 |
$ | 64,544 | $ | 32,651 | ||||
Actual results of Sydson included
in our statement of income
for the period April 21, 2011
through June 30, 2011 |
$ | 1,817 | $ | 588 | ||||
Actual results of TODD included in
our statement of income for
the period June 17, 2011 through
June 30, 2011 |
$ | 724 | $ | 193 | ||||
Pro forma results for the combined
entity for the six months ended
June 30, 2011 |
$ | 150,653 | $ | 15,347 | ||||
Pro forma results for the combined
entity for the six months ended
June 30, 2010 |
$ | 142,555 | $ | 41,155 |
12
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4. PROPERTY AND EQUIPMENT
Property and equipment consists of the following:
June 30, | December 31, | |||||||
2011 | 2010 | |||||||
(unaudited) | ||||||||
(dollars in thousands) | ||||||||
OIL AND NATURAL GAS PROPERTIES |
||||||||
Unproved properties |
$ | 35,256 | $ | 12,020 | ||||
Accumulated impairment |
(4,679 | ) | (2,686 | ) | ||||
Unproved properties, net |
30,577 | 9,334 | ||||||
Proved oil and natural gas properties |
821,399 | 707,364 | ||||||
Accumulated depreciation, depletion,
amortization and impairment |
(324,113 | ) | (273,818 | ) | ||||
Proved oil and natural gas properties, net |
497,286 | 433,546 | ||||||
TOTAL OIL AND NATURAL GAS PROPERTIES, net |
527,863 | 442,880 | ||||||
LAND |
1,185 | 1,185 | ||||||
DRILLING RIG |
10,500 | 10,500 | ||||||
Accumulated depreciation |
(794 | ) | (444 | ) | ||||
TOTAL DRILLING RIG, net |
9,706 | 10,056 | ||||||
OTHER PROPERTY AND EQUIPMENT |
||||||||
Office furniture and equipment, vehicles |
7,251 | 3,844 | ||||||
Accumulated depreciation |
(2,161 | ) | (1,701 | ) | ||||
OTHER PROPERTY AND EQUIPMENT, net |
5,090 | 2,143 | ||||||
TOTAL PROPERTY AND EQUIPMENT, net |
$ | 543,844 | $ | 456,264 | ||||
5. FAIR VALUE DISCLOSURES
We follow the guidance of ASC 820, Fair Value Measurements and Disclosures, in the estimation of
fair values. ASC 820 provides a hierarchy of fair value measurements, based on the inputs to the
fair value estimation process. It requires disclosure of fair values classified according to
defined levels, which are based on the reliability of the evidence used to determine fair value,
with Level 1 being the most reliable and Level 3 the least. Level 1 evidence consists of observable
inputs, such as quoted prices in an active market. Level 2 inputs typically correlate the fair
value of the asset or liability to a similar, but not identical item which is actively traded.
Level 3 inputs include at least some unobservable inputs, such as valuation models developed using
the best information available in the circumstances.
We utilize the modified Black-Scholes option pricing model to estimate the fair value of oil and
natural gas derivative contracts. Inputs to this model include observable inputs from the New York
Mercantile Exchange (NYMEX) for futures contracts, and inputs derived from NYMEX observable
inputs, such as implied volatility of oil and natural gas prices. We have classified the fair
values of all our oil and natural gas derivative contracts as Level 2.
The fair value of our interest rate derivative contracts was calculated using the modified
Black-Scholes
option pricing model and is also considered a Level 2 fair value.
13
Table of Contents
Oil and natural gas properties are subject to impairment testing and potential impairment write
down. Oil and gas properties with a carrying amount of $24.4 million were written down to their
fair value of $13.6 million, resulting in an impairment charge of $10.8 million for the six months
ended June 30, 2011. Oil and gas properties with a carrying amount of $4.4 million were written
down to their fair value of $2.3 million, resulting in an impairment charge of $2.1 million for the
six months ended June 30, 2010. For the three months ended June 30, 2011, oil and gas properties
with a carrying amount of $14.2 million were written down to their fair value of $9.3 million,
resulting in an impairment charge of $4.9 million, and for the three months ended June 30, 2010,
oil and gas properties with a carrying amount of $1.2 million were written down to their fair value
of $0.6 million, resulting in an impairment charge of $0.6 million. Significant Level 3 assumptions
used in the calculation of estimated discounted cash flows in the impairment analysis included our
estimate of future oil and natural gas prices, production costs, development expenditures,
estimated timing of production of proved reserves, appropriate risk-adjusted discount rates, and
other relevant data.
In connection with the Meridian acquisition, we recorded oil and natural gas properties with a fair
value of $147.4 million in the second quarter of 2010. In connection with the Sydson and TODD
acquisitions, we recorded oil and natural gas properties with a fair value of $28.4 million, and
$23.4 million, respectively, in the second quarter of 2011. For information on these acquisitions,
see Note 3. Significant Level 3 inputs used were the same as those used in determining impairments
based on estimated discounted cash flows for the acquired properties.
New additions to asset retirement obligations result from estimations for new properties, and fair
values for them are categorized as Level 3. Such estimations are based on present value techniques
which utilize company-specific information for such inputs as cost and timing of plug and
abandonment of wells and facilities. We recorded $2.8 million and $34.6 million in additions to
asset retirement obligations measured at fair value during the six months ended June 30, 2011 and
2010, respectively. The significant additions in 2010 were the result of the purchase of Meridian.
The following table presents information about our financial assets and liabilities measured at
fair value on a recurring basis as of June 30, 2011 and December 31, 2010, and indicates the fair
value hierarchy of the valuation techniques we utilized to determine such fair value:
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
(dollars in thousands) | ||||||||||||||||
At June 30, 2011 (unaudited): |
||||||||||||||||
Financial Assets: |
||||||||||||||||
Derivative contracts for oil and
natural gas |
$ | | $ | 59,898 | $ | | $ | 59,898 | ||||||||
Financial Liabilities: |
||||||||||||||||
Derivative contracts for oil and
natural gas |
| 40,105 | | 40,105 | ||||||||||||
Derivative contracts for interest rate |
| 4,880 | | 4,880 | ||||||||||||
At December 31, 2010: |
||||||||||||||||
Financial Assets: |
||||||||||||||||
Derivative contracts for oil and
natural gas |
$ | | $ | 61,623 | $ | | $ | 61,623 | ||||||||
Financial Liabilities: |
||||||||||||||||
Derivative contracts for oil and
natural gas |
| 37,022 | | 37,022 | ||||||||||||
Derivative contracts for interest rate |
| 5,388 | | 5,388 |
The amounts above are presented on a gross basis; presentation on our consolidated balance
sheets utilizes netting of assets and liabilities with the same counterparty where master netting
agreements are in
place. For additional information on derivative contracts, see Note 6.
14
Table of Contents
6. DERIVATIVE FINANCIAL INSTRUMENTS
We account for our derivative contracts under the provisions of ASC 815, Derivatives and Hedging.
We have entered into forward-swap contracts and collar contracts to reduce our exposure to price
risk in the spot market for oil and natural gas. We also utilize financial basis swap contracts,
which address the price differential between market-wide benchmark prices and other benchmark
pricing referenced in certain of our natural gas sales contracts. Substantially all of our hedging
agreements are executed by affiliates of the lenders under the credit facility described in Note 8
below, and are collateralized by the security interests of the respective affiliated lenders in
certain of our assets under the credit facility. The contracts settle monthly and are scheduled to
coincide with either oil production equivalent to barrels (Bbl) per month or gas production
equivalent to volumes in millions of British thermal units (MMbtu) per month. The contracts
represent agreements between us and the counter-parties to exchange cash based on a designated
price. Prices are referenced to the natural gas spot market benchmark price at the Houston Ship
Channel or the NYMEX index. Cash settlement occurs monthly based on the specified price
benchmark. We have not designated any of our derivative contracts as fair value or cash flow
hedges; accordingly we use mark-to-market accounting, recognizing unrealized gains and losses in
the statement of operations at each reporting date. Realized gains and losses on commodities
hedging contracts are included in oil and natural gas revenues.
We have entered into a series of interest rate swap agreements with several financial institutions
to mitigate the risk of loss due to changes in interest rates. The interest rate swaps are not
designated as cash flow hedges in accordance with ASC 815. Both realized gains and losses from
settlement and unrealized gains and losses from changes in the fair market value of the interest
rate swaps are included in interest expense.
The second table below provides information on the location and amounts of realized and unrealized
gains and losses on derivatives included in the consolidated statements of income for each of the
three month and six month periods ended June 30, 2011 and 2010.
The following table summarizes the fair value (see Note 5 for further discussion of fair value) and
classification of our derivative instruments, none of which have been designated as hedging
instruments under ASC 815:
15
Table of Contents
Fair Values of Derivative Contracts | ||||||||||||||||
Balance Sheet Location at June 30, 2011 | ||||||||||||||||
Current asset | Current liability | Long-term asset | Long-term liability | |||||||||||||
portion of | portion of | portion of | portion of | |||||||||||||
Derivative | Derivative | Derivative | Derivative | |||||||||||||
financial | financial | financial | financial | |||||||||||||
instruments | instruments | instruments | instruments | |||||||||||||
(unaudited) | ||||||||||||||||
(dollars in thousands) | ||||||||||||||||
Fair value of oil and gas
commodity contracts, assets |
$ | 25,913 | $ | | $ | 33,985 | $ | | ||||||||
Fair value of oil and gas
commodity contracts,
(liabilities) |
(14,788 | ) | | (25,317 | ) | | ||||||||||
Fair value of interest rate
contracts, (liabilities) |
| (3,176 | ) | | (1,704 | ) | ||||||||||
Total net assets, (liabilities) |
$ | 11,125 | $ | (3,176 | ) | $ | 8,668 | $ | (1,704 | ) | ||||||
Fair Values of Derivative Contracts | ||||||||||||||||
Balance Sheet Location at December 31, 2010 | ||||||||||||||||
Current asset | Current liability | Long-term asset | Long-term liability | |||||||||||||
portion of | portion of | portion of | portion of | |||||||||||||
Derivative | Derivative | Derivative | Derivative | |||||||||||||
financial | financial | financial | financial | |||||||||||||
instruments | instruments | instruments | instruments | |||||||||||||
(dollars in thousands) | ||||||||||||||||
Fair value of oil and gas
commodity contracts, assets |
$ | 27,118 | $ | | $ | 34,505 | $ | | ||||||||
Fair value of oil and gas
commodity contracts,
(liabilities) |
(16,682 | ) | | (20,340 | ) | | ||||||||||
Fair value of interest rate
contracts, (liabilities) |
| (3,092 | ) | | (2,296 | ) | ||||||||||
Total net assets, (liabilities) |
$ | 10,436 | $ | (3,092 | ) | $ | 14,165 | $ | (2,296 | ) | ||||||
Commodity contracts are subject to master netting arrangements and are presented on a net basis in
the consolidated balance sheets. This netting can cause derivative assets to be ultimately
presented in a (liability) account on the consolidated balance sheets. Likewise, derivative
(liabilities) could be presented in an asset account.
16
Table of Contents
The following table summarizes the effect of our derivative instruments in the consolidated
statements of operations:
Derivatives not | ||||||||||||||||||||
designated as hedging | For the three months | For the six months ended | ||||||||||||||||||
instruments under ASC | Location of Gain | Classification of | ended June 30, | June 30, | ||||||||||||||||
815 | (Loss) | Gain (Loss) | 2011 | 2010 | 2011 | 2010 | ||||||||||||||
(unaudited) | ||||||||||||||||||||
(dollars in thousands) | ||||||||||||||||||||
Natural gas commodity contracts |
Natural gas revenues | Realized | $ | 5,120 | $ | 6,452 | $ | 10,911 | $ | 9,201 | ||||||||||
Oil commodity contracts
|
Oil revenues | Realized | (2,434 | ) | 39 | (3,918 | ) | 276 | ||||||||||||
Interest rate contracts
|
Interest benefit (expense) |
Realized | 2,298 | (1,024 | ) | 1,928 | (2,051 | ) | ||||||||||||
Total realized gains
(losses) from
derivatives not
designated as hedges
|
$ | 4,984 | $ | 5,467 | $ | 8,921 | $ | 7,426 | ||||||||||||
Natural gas commodity contracts |
Unrealized gain (loss) oil and natural gas derivative contracts | Unrealized | $ | 1,659 | $ | (5,985 | ) | $ | (1,299 | ) | $ | 15,296 | ||||||||
Oil commodity contracts
|
Unrealized gain (loss) oil and natural gas derivative contracts | Unrealized | 12,718 | 8,090 | (3,509 | ) | 7,612 | |||||||||||||
Interest rate contracts
|
Interest benefit (expense) |
Unrealized | 465 |
488 |
508 |
403 |
||||||||||||||
Total unrealized gains
(losses) from
derivatives not
designated as hedges
|
$ | 14,842 | $ | 2,593 | $ | (4,300 | ) | $ | 23,311 | |||||||||||
Although our counterparties provide no collateral, the master derivative agreements with each
counterparty effectively allow us, so long as we are not a defaulting party, after a default or the
occurrence of a termination event, to set-off an unpaid hedging agreement receivable against the
interest of the counterparty in any outstanding balance under the credit facility.
If a counterparty were to default in payment of an obligation under the master derivative
agreements, we could be exposed to commodity price fluctuations, and the protection intended by the
hedge could be lost. The value of our derivative financial instruments would be impacted.
17
Table of Contents
We had the following open derivative contracts for natural gas at June 30, 2011 (unaudited):
NATURAL GAS DERIVATIVE CONTRACTS
Volume in | Weighted | Range | ||||||||||||||
Period and Type of Contract | MMbtu | Average | High | Low | ||||||||||||
2011 |
||||||||||||||||
Price Swap Contracts |
6,030,000 | $ | 5.60 | $ | 8.83 | $ | 4.44 | |||||||||
Collar Contracts |
||||||||||||||||
Short Call Options |
6,760,000 | 5.67 | 7.05 | 5.40 | ||||||||||||
Long Put Options |
3,060,000 | 6.05 | 6.30 | 5.75 | ||||||||||||
Long Call Options |
600,000 | 7.45 | 7.45 | 7.45 | ||||||||||||
Short Put Options |
2,950,000 | 3.86 | 4.00 | 3.65 | ||||||||||||
2012 |
||||||||||||||||
Price Swap Contracts |
7,525,000 | 6.17 | 8.83 | 5.00 | ||||||||||||
Collar Contracts |
||||||||||||||||
Short Call Options |
7,560,000 | 5.76 | 6.00 | 5.50 | ||||||||||||
Long Put Options |
4,350,000 | 5.93 | 6.75 | 5.50 | ||||||||||||
Long Call Options |
3,660,000 | 5.00 | 5.00 | 5.00 | ||||||||||||
Short Put Options |
8,730,000 | 4.11 | 4.50 | 4.00 | ||||||||||||
2013 |
||||||||||||||||
Price Swap Contracts |
4,825,000 | 6.48 | 9.15 | 5.35 | ||||||||||||
Collar Contracts |
||||||||||||||||
Short Call Options |
1,500,000 | 8.51 | 8.80 | 8.31 | ||||||||||||
Long Put Options |
1,500,000 | 6.09 | 6.15 | 6.00 | ||||||||||||
Short Put Options |
900,000 | 5.50 | 5.50 | 5.50 | ||||||||||||
2014 |
||||||||||||||||
Price Swap Contracts |
3,125,000 | 6.27 | 7.50 | 5.60 | ||||||||||||
Collar Contracts |
||||||||||||||||
Short Call Options |
1,650,000 | 8.21 | 9.00 | 7.92 | ||||||||||||
Long Put Options |
1,650,000 | 6.73 | 7.00 | 6.00 | ||||||||||||
Short Put Options |
1,200,000 | 5.50 | 5.50 | 5.50 | ||||||||||||
2015 |
||||||||||||||||
Price Swap Contracts |
1,825,000 | 5.91 | 5.91 | 5.91 | ||||||||||||
2016 |
||||||||||||||||
Collar Contracts |
||||||||||||||||
Short Call Options |
455,000 | 7.50 | 7.50 | 7.50 | ||||||||||||
Long Put Options |
455,000 | 5.50 | 5.50 | 5.50 | ||||||||||||
Short Put Options |
455,000 | 4.00 | 4.00 | 4.00 |
18
Table of Contents
We had the following open derivative contracts for crude oil at June 30, 2011 (unaudited):
OIL DERIVATIVE CONTRACTS
Weighted | Range | |||||||||||||||
Period and Type of Contract | Volume in Bbls | Average | High | Low | ||||||||||||
2011 |
||||||||||||||||
Price Swap Contracts |
230,000 | $ | 83.80 | $ | 103.20 | $ | 67.50 | |||||||||
Collar Contracts |
||||||||||||||||
Short Call Options |
276,000 | 103.15 | 110.00 | 82.25 | ||||||||||||
Long Put Options |
317,400 | 86.67 | 100.00 | 75.00 | ||||||||||||
Long Call Options |
55,200 | 75.00 | 75.00 | 75.00 | ||||||||||||
Short Put Options |
402,592 | 66.42 | 89.85 | 55.00 | ||||||||||||
2012 |
||||||||||||||||
Price Swap Contracts |
228,900 | 85.69 | 96.00 | 67.25 | ||||||||||||
Collar Contracts |
||||||||||||||||
Short Call Options |
491,172 | 115.89 | 123.50 | 100.00 | ||||||||||||
Long Put Options |
522,648 | 80.75 | 85.00 | 80.00 | ||||||||||||
Short Put Options |
635,376 | 62.26 | 65.00 | 60.00 | ||||||||||||
2013 |
||||||||||||||||
Price Swap Contracts |
136,500 | 84.35 | 94.74 | 77.00 | ||||||||||||
Collar Contracts |
||||||||||||||||
Short Call Options |
417,935 | 110.62 | 127.00 | 90.00 | ||||||||||||
Long Put Options |
351,500 | 81.95 | 90.00 | 80.00 | ||||||||||||
Long Call Options |
82,500 | 79.00 | 79.00 | 79.00 | ||||||||||||
Short Put Options |
434,000 | 61.58 | 70.00 | 60.00 | ||||||||||||
2014 |
||||||||||||||||
Price Swap Contracts |
127,300 | 87.63 | 91.05 | 81.00 | ||||||||||||
Collar Contracts |
||||||||||||||||
Short Call Options |
273,750 | 125.70 | 133.50 | 107.50 | ||||||||||||
Long Put Options |
488,450 | 85.33 | 90.00 | 80.00 | ||||||||||||
Short Put Options |
488,450 | 65.33 | 70.00 | 60.00 | ||||||||||||
2015 |
||||||||||||||||
Collar Contracts |
||||||||||||||||
Short Call Options |
246,350 | 125.12 | 135.98 | 116.40 | ||||||||||||
Long Put Options |
319,350 | 87.57 | 90.00 | 85.00 | ||||||||||||
Short Put Options |
319,350 | 66.86 | 70.00 | 60.00 | ||||||||||||
2016 |
||||||||||||||||
Collar Contracts |
||||||||||||||||
Short Call Options |
36,400 | 130.00 | 130.00 | 130.00 | ||||||||||||
Long Put Options |
36,400 | 95.00 | 95.00 | 95.00 | ||||||||||||
Short Put Options |
36,400 | 75.00 | 75.00 | 75.00 |
In those instances where contracts are identical as to time period, volume and strike price,
but opposite as to direction (long and short), the volumes and average prices have been netted in the two tables above. In some instances our counterparties
in the offsetting contracts are not the same, and may have different credit ratings.
19
Table of Contents
We had the following open financial basis swap contracts at June 30, 2011 (unaudited):
Volume in MMbtu | Reference Price | Period | Spread ($ per MMbtu) | |||||||||
1,200,000 |
Houston Ship Channel | Jul 11 Dec 11 | (0.2000 | ) | ||||||||
1,200,000 |
Houston Ship Channel | Jul 11 Dec 11 | (0.1600 | ) | ||||||||
460,000 |
Houston Ship Channel | Jul 11 Dec 11 | (0.0850 | ) | ||||||||
1,380,000 |
Houston Ship Channel | Jul 11 Dec 11 | (0.1550 | ) | ||||||||
1,830,000 |
Houston Ship Channel | Jan 12 Dec 12 | (0.1575 | ) | ||||||||
1,840,000 |
Houston Ship Channel | Jul 11 Dec 11 | (0.1150 | ) | ||||||||
3,660,000 |
Houston Ship Channel | Jan 12 Dec 12 | (0.1400 | ) |
We had the following open interest rate swap contracts at June 30, 2011 (unaudited): |
Interest Rate Swaps | ||||||||
Term | Principal Amount | Interest Rate (1) | ||||||
(dollars in thousands) | ||||||||
Floating to Fixed Rate Swaps: |
||||||||
July 2011 August 2012 |
$ | 50,000 | 4.95 | % | ||||
July 2011 October 2011 |
$ | 25,000 | 3.21 | % | ||||
Fixed to Floating Rate Swaps: |
||||||||
July 2011 June 2015 |
$ | 150,000 | 9.625 | % |
(1) | The floating rate is the three-month LIBOR rate, except the swap for $150 million, which is a fixed to floating rate swap using a floating rate of three-month LIBOR plus 8.06%. |
7. ASSET RETIREMENT OBLIGATIONS
A summary of the changes in asset retirement obligations is included in the table below (unaudited,
dollars in thousands):
Balance, December 31, 2010 |
$ | 42,713 | ||
Liabilities incurred |
332 | |||
Liabilities assumed with acquired producing properties |
2,504 | |||
Liabilities settled |
(246 | ) | ||
Revisions to previous estimates |
(7 | ) | ||
Accretion expense |
946 | |||
Balance, June 30, 2011 |
46,242 | |||
Less: Current portion |
1,755 | |||
Long term portion |
$ | 44,487 | ||
20
Table of Contents
8. LONG-TERM DEBT AND NOTES PAYABLE TO FOUNDER
Long-term debt consists of the following:
June 30, | December 31, | |||||||
2011 | 2010 | |||||||
(unaudited) | ||||||||
(dollars in thousands) | ||||||||
Senior Debt On November 13, 2008, we
entered into a Fifth Amended and
Restated Credit Agreement with a group
of banks, which was replaced by the
Sixth Amended and Restated Credit
Agreement on May 13, 2010, as amended
(credit facility). The credit
facility matures on May 23, 2016 and is
secured by substantially all of our oil
and gas properties. The credit facility
borrowing base is redetermined
periodically and, as of June 30, 2011,
the borrowing base under the facility
was $260 million. The credit facility
bears interest at LIBOR plus applicable
margins between 2.00% and 2.75% or a
Reference Rate, which is based on the
prime rate of Wells Fargo Bank, N. A.,
plus a margin ranging from 1.00% to
1.75%, depending on the utilization of
our borrowing base. The rate was
2.519% as of June 30, 2011 and 2.875% as of December
31, 2010 |
$ | 159,790 | $ | 73,290 | ||||
Senior Notes Payable On October 13,
2010, we issued notes due October 15,
2018 with a face value of $300 million,
at a discount of $2.1 million. The
senior notes carry a face interest rate
of 9 5/8%, with an effective rate of 9
3/4%; interest is payable semi-annually
each April 15th and October
15th. The senior notes are
secured by general corporate credit,
and effectively rank junior to any of
our existing or future secured
indebtedness, which includes the credit
facility. The senior notes are
unconditionally guaranteed on a senior
unsecured basis by each of our material
subsidiaries. The balance is presented
net of unamortized discount of $1.9
million and $2.0 million at June 30,
2011 and December 31, 2010,
respectively. |
298,116 | 297,986 | ||||||
Total long-term debt |
$ | 457,906 | $ | 371,276 | ||||
The senior notes contain an optional redemption provision beginning in October 2013 allowing us to
retire up to 35% of the principal outstanding under the senior notes with the proceeds of an equity
offering, at 109.625%. Additional optional redemption provisions allow for retirement at 104.813%,
102.406%, and 100.0% beginning on each of October 15, 2014, 2015, and 2016, respectively.
On October 13, 2010, we entered into a registration rights agreement with the initial purchasers of
the senior notes. Pursuant to the registration rights agreement, we filed a registration statement
with the SEC to allow for registration of exchange notes with terms substantially identical to
the senior notes. The exchange offer was consummated on August 12, 2011, with the tendered
original senior notes exchanged for the exchange notes.
On May 23, 2011, we amended our $500 million senior secured revolving credit facility to, among
other
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things, increase the borrowing base limit from $220 million to $260 million and reduce applicable
interest rates provided thereunder, extend the maturity date from November 13, 2012 to May 23,
2016, and increase the amount of senior debt securities that we are permitted to issue from $500
million to $700 million. The amended credit facility is currently subject to a $260 million
borrowing base limit.
The credit facility and senior notes include covenants requiring us to maintain certain financial
covenants including a Current Ratio, Leverage Ratio, and Interest Coverage Ratio. At June 30,
2011, we were in compliance with the covenants. The terms of the credit facility also restrict our
ability to make distributions and investments.
In addition, we have notes payable to our founder which bear simple interest at 10% with a balance
of $20.3 million and $19.7 million at June 30, 2011 and December 31, 2010, respectively. The notes
mature December 31, 2018. Interest and principal are payable at maturity. The notes are
subordinate to all debt. Interest on the notes payable to our founder amounted to $600,000 and
$590,000 for the six months ended June 30, 2011 and 2010,
respectively, and $302,000 and $297,000
for the three months ended June 30, 2011 and 2010, respectively. Such amounts have been added to
the balance of the notes.
9. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
The following provides the detail of accounts payable and accrued liabilities:
June 30, | December 31, | |||||||
2011 | 2010 | |||||||
(unaudited) | ||||||||
(dollars in thousands) | ||||||||
Capital expenditures |
$ | 32,815 | $ | 22,743 | ||||
Revenues and royalties payable |
5,287 | 5,962 | ||||||
Operating expenses/taxes |
23,152 | 18,220 | ||||||
Compensation |
4,057 | 2,591 | ||||||
Liability related to drilling rig |
| 9,785 | ||||||
Other |
2,513 | 1,775 | ||||||
Total accrued liabilities |
67,824 | 61,076 | ||||||
Accounts payable |
6,321 | 26,179 | ||||||
Accounts payable and accrued liabilities |
$ | 74,145 | $ | 87,255 | ||||
The following provides the detail of other long-term liabilities:
June 30, | December 31, | |||||||
2011 | 2010 | |||||||
(unaudited) | ||||||||
(dollars in thousands) | ||||||||
Acquisition obligation |
$ | 985 | $ | 411 | ||||
Remediation liability |
966 | 943 | ||||||
Other |
3,489 | 5,886 | ||||||
Total other long-term liabilities |
$ | 5,440 | $ | 7,240 | ||||
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10. COMMITMENTS AND CONTINGENCIES
Contingencies
Deep Bossier litigation: On July 23, 2009, we made a payment of $25.5 million and took
assignment of substantially all working interests that had been held by Chesapeake Energy
Corporation in an approximate 50,000 acre area of Leon and Robertson Counties, Texas in the Deep
Bossier play. We had exercised our preferential right to purchase these interests from Gastar
Exploration Ltd. in late 2005, but Gastar and Chesapeake had opposed this and Chesapeake took
record title until we finally and conclusively prevailed, and in 2008 a Texas court of appeals
directed that specific performance take place. In early 2009, the Texas Supreme Court denied the
defendants request to hear the appeal. As a result, we were able to take working interests in over
30 producing wells and participate in further development of the area, primarily with EnCana, but
also with Gastar. A subsequent payment to EnCana of $15.2 million plus purchase accounting
adjustments of $3.8 million brought the total cost of the acquisition to $44.5 million. While the
ownership of these interests has been decided by the courts, we are pursuing other claims against
Chesapeake; Chesapeake is claiming an additional $36.5 million of past expenses from us. We are
unable to express an opinion with respect to the likelihood of an unfavorable outcome of this
matter or to estimate the amount or range of potential loss should the outcome be unfavorable.
Therefore, we have not provided any amount for this matter in our consolidated financial statements
at June 30, 2011.
Texas Oil Distribution & Development, Inc. and Matrix Petroleum, LLC v. Alta Mesa Holdings, LP
and The Meridian Resource & Exploration, LLC: In November 2010, Texas Oil Distribution &
Development, Inc. and Matrix Petroleum LLC (together, TODD), filed a petition seeking declaratory
relief based on TODDs employment of Thomas Tourek, a former independent contractor of the Company.
TODD subsequently filed an amended petition for declaratory relief, breach of contract and
tortious interference related to certain assignments of oil and gas interests and joined Meridian
as a defendant. On June 17, 2011, the litigation was settled.
See Note 3, Significant Acquisitions TODD
Acquisition for further information.
Ted R. Stalder, TRS LP, Richard Hughart, and Richmar
Interests, Inc. v. Texas Energy Acquisitions, LP: On May 24, 2011, the plaintiffs brought suit against us for breach
of contract, common law fraud, fraud in a real estate transaction, declaratory relief, money had and received, an
accounting, and injunctive relief related to two purchase and sales agreements dated December 23, 2008 and a dispute
over the interpretation of the payment provisions in those
agreements. An ex parte temporary restraining order (TRO)
was entered against us on May 24, 2011, requiring among other things that we deposit into the registry of the court all
payments received from oil, gas and liquids from the properties covered by the agreements. Our motion to dissolve the
TRO was denied and the TRO was amended and extended another 14 days on June 2, 2011. We subsequently agreed to amend
and extend the TRO until July 8, 2011. On July 7, 2011, during a hearing on the temporary injunction, the court
recommended that the parties enter into an agreed temporary injunction. The plaintiffs and us agreed to enter into
a temporary injunction whereby, among other things, we would pay directly to the plaintiffs the portion of the payments
received from oil, gas, and liquids from the properties covered by the agreements that we contend the plaintiffs are due,
less any previous payments. Furthermore, we have agreed to deposit into the registry of the court the amount that the
plaintiffs contend they are owed, less any previous payments made to the registry of the court or to the plaintiffs.
We are still in the process of negotiating the agreed temporary injunction. On July 28, 2011, we filed a motion for
partial summary judgment on the plaintiffs fraud claims, which is set for hearing on August 18, 2011. We intend to
contest the matter vigorously. We are unable to express an opinion with respect to the likelihood of an unfavorable
outcome of this matter or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore,
we have not provided any amount for this matter in our consolidated financial statements at June 30, 2011.
Environmental claims: Management has established a liability for soil contamination in
Florida of $966,000 at June 30, 2011 and $943,000 December 31, 2010, based on our undiscounted
engineering estimates. The obligations are included in other long-term liabilities in the
accompanying consolidated balance sheets.
Various landowners have sued Meridian (along with numerous other oil companies) in lawsuits
concerning several fields in which Meridian has had operations. The lawsuits seek injunctive
relief and
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other relief, including unspecified amounts in both actual and punitive damages for alleged
breaches of mineral leases and alleged failure to restore the plaintiffs lands from alleged
contamination and otherwise from Meridians oil and natural gas operations. We are unable to
express an opinion with respect to the likelihood of an unfavorable outcome of the various
environmental claims or to estimate the amount or range of potential loss should the outcome be
unfavorable. Therefore, we have not provided any amount for these claims in our financial
statements at June 30, 2011.
Due to the nature of our business, some contamination of the real estate property owned or leased
by us is possible. Environmental site assessments of the property would be necessary to adequately
determine remediation costs, if any. No accrual has been made other than the balance noted above.
Title/lease disputes: Title and lease disputes may arise in the normal course of our
operations. These disputes are usually small but could result in an increase or decrease in
reserves once a final resolution to the title dispute is made.
Other contingencies: We are subject to legal proceedings, claims and liabilities arising
in the ordinary course of business. The outcome cannot be reasonably estimated; however, in the
opinion of management, such litigation and claims will be resolved without material adverse effect
on our financial position, results of operations or cash flows. Accruals for losses associated
with litigation are made when losses are deemed probable and can be reasonably estimated.
We have contingent commitments to pay an amount up to a maximum of approximately $6.7 million for
properties acquired in 2008 and prior years. The additional purchase consideration will be paid
only if certain product price conditions are met. We cannot estimate the amounts that will be paid
in the future, if any, or the fiscal years in which such amounts could become due.
Drilling rig: Included in our acquisition of Meridian was a contractual obligation for the
use of a drilling rig, which expired in February 2011. Meridian and Alta Mesa were not able to
fully utilize this rig during the contractual term; however, we were obligated for the dayrate
regardless of whether the rig was working or idle. The operator, Orion Drilling, LP (Orion),
sought other parties to use the rig and agreed to credit Meridians and Alta Mesas obligation,
based on revenues from third parties who utilized the rig when it was not utilized under the
contract. We had provided approximately $9.8 million for the liability under this drilling
contract and under a similar rig contract which had previously expired and was also underutilized.
On May 19, 2011, we fully settled this liability with a payment of $8.5 million to Orion, and
recorded a gain on contact settlement of $1.3 million.
11. SIGNIFICANT RISKS AND UNCERTAINTIES
Our business makes us vulnerable to changes in wellhead prices of crude oil and natural gas. Such
prices have been volatile in the past and can be expected to be volatile in the future. By
definition, proved reserves are based on analysis of current oil and natural gas prices. Price
declines reduce the estimated value of proved reserves and may increase annual amortization expense
(which is based on proved reserves). Price declines may also result in impairments, or non-cash
write-downs, of the value of our oil and gas properties. We mitigate a portion of this
vulnerability by entering into oil and natural gas price derivative contracts. See Note 6.
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12. PARTNERS CAPITAL
In September 2006, our limited partnership agreement was amended such that the affiliates of Alta Mesa Holdings, LP and certain other parties became Class A limited partners (Class A Partners) and AMIH was admitted to the partnership as the sole Class B limited
partner (Class B Partner.)
Management and Control: Our business and affairs are managed by Alta Mesa Holdings GP,
LLC, our general partner (General Partner). With certain exceptions, the General Partner may not
be removed except for the reasons of cause, which are defined in the Alta Mesa Holdings, LP
Partnership Agreement (Partnership Agreement). The Class B limited partner has certain approval
rights, generally over capital plans and significant transactions in the areas of finance,
acquisition, and divestiture.
Distribution and Income Allocation: Net cash flow from operations may be distributed to the Class A and Class B
Partners based on a variable formula as defined in the Partnership
Agreement.
After January 1, 2012, the Class B Partner may require the General Partner to make distributions; however, any distribution must be permitted under the terms of our credit facility and our senior notes.
After January 1, 2012, the Class B Partner may require the General Partner to make distributions; however, any distribution must be permitted under the terms of our credit facility and our senior notes.
Distribution of net cash flow from a Liquidity Event (as defined below) is distributed to the Class
A and Class B Partners according to a variable formula as defined in the Partnership Agreement. A
Liquidity Event is any event in which we receive cash proceeds outside the ordinary course of our
business. Further, after January 1, 2012, the Class B Partner can, without consent of any other
partners, request that the General Partner take action to cause us, or our assets, to be sold to
one or more third parties.
13. SUBSIDIARY GUARANTORS
All of our material wholly-owned subsidiaries are guarantors under the terms of both our senior
notes and our credit facility.
Our consolidated financial statements reflect the combined financial position of these subsidiary
guarantors. Our parent company, Alta Mesa Holdings, LP has no independent operations, assets, or
liabilities. The guarantees are full and unconditional and joint and several. Those subsidiaries
which are not wholly owned and are not guarantors are minor. There are no restrictions on
dividends, distributions, loans, or other transfers of funds from the subsidiary guarantors to our
parent company.
14. SUBSEQUENT EVENTS
Management has evaluated all events subsequent to the balance sheet date of June 30, 2011 to August
12, 2011, which is the date the consolidated financial statements were issued, and has determined
that no events require disclosure.
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ITEM 2. Managements Discussion and Analysis of Financial Condition and Results of
Operations
The following discussion and analysis should be read in conjunction with the financial
statements and related notes included elsewhere in this report. In addition, such analysis should
be read in conjunction with the financial statements and the related notes included in our
Registration Statement on Form S-4 (Commission File No. 333-173751 filed on July 11, 2011, the
Form S-4). The following discussion and analysis contains forward-looking statements that
reflect our future plans, estimates, beliefs and expected performance. The forward-looking
statements are dependent upon events, risks and uncertainties that may be outside our control. Our
actual results could differ materially from those discussed in these forward-looking statements.
Factors that could cause or contribute to such differences include, but are not limited to, the
volatility of oil and natural gas prices, general economic conditions, credit markets, inflation, the credit rating of U.S. government debt, production timing and volumes, estimates of proved
reserves, operating costs and capital expenditures, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory
changes, the uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, cash flow and access to capital and other uncertainties, as well as those factors discussed below and under Risk Factors
in our Form S-4. As a result of these risks, uncertainties and assumptions, the forward-looking
events discussed may not occur. The historical financial information discussed below in this
Managements Discussion and Analysis of Financial Conditions and Results of Operations represents
Alta Mesas financial information for the periods indicated, giving effect to the Meridian
acquisition from the acquisition date of May 13, 2010 and the Sydson and TODD asset acquisitions from
April 21, 2011 and June 17, 2011, respectively.
Overview
We currently generate significant amounts of our revenue, earnings and cash flow from the
production and sale of oil and natural gas from our core properties in the South Louisiana, East
Texas, Oklahoma, the Deep Bossier resource play of East Texas and Eagle Ford Shale play in South
Texas. We operate in one industry segment, oil and natural gas exploration and development, within
one geographical segment, the United States.
The amount of cash we generate from our operations will fluctuate based on, among other
things:
| the prices at which we will sell our production; | ||
| the amount of oil and natural gas we produce; and | ||
| the level of our operating and administrative costs. |
In order to mitigate the impact of changes in oil and natural gas prices on our cash flows, we
are a party to hedging and other price protection contracts, and we intend to enter into such
transactions in the future to reduce the effect of oil and natural gas price volatility on our cash
flows.
Substantially all of our oil and natural gas activities are conducted jointly with others and,
accordingly, amounts presented reflect our proportionate interest in such activities. Inflation has
not had a material impact on our results of operations and is not expected to have a material
impact on our results of operations in the future.
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Significant Acquisitions
Meridian Acquisition
On May 13, 2010, we acquired The Meridian Resource Corporation, a public exploration and production
company, with proved reserves of 75
Bcfe as of December 31, 2009, for approximately $158 million. The oil and natural gas properties
of Meridian were similar and in some cases proximate to our areas of operation. Meridian
shareholders were paid in cash, funded by proceeds of our credit facility as well as a $50 million
equity contribution from our private equity partner Alta Mesa Investment Holdings Inc., an
affiliate of Denham Commodities Partners Fund IV LP (AMIH). The merger increased the oil portion
of our reserves portfolio, improving the balance of our reserves between oil and natural gas, and
provided significant additions to our library of 3-D seismic data.
Sydson Acquisition
On April 21, 2011, we purchased
from Sydson Energy and certain of its related parties (together, Sydson and the Sydson acquisition) certain oil
and natural gas assets primarily located in Texas and South Louisiana in which we had jointly participated with Sydson.
The purchase price
was $27.5 million in cash (a total cost of $28.4 million including abandonment liabilities we assumed). Total
net proved reserves acquired are estimated to be 800 MBOE (5 Bcfe), 45% of which is oil. By virtue of this acquisition,
we increased our after payout net revenue interest in the Eagle Ford Shale by over 50%. Funding for the acquisition was
provided through our credit facility. In addition, litigation associated with a portion of the assets purchased was resolved as a result of the transaction.
TODD Acquisition
On June 17, 2011, we purchased from
Texas Oil Distribution & Development, Inc. and Matrix Petroleum LLC and certain other parties (together, TODD and the
TODD acquisition) certain oil and natural gas assets primarily located in Texas and South Louisiana in which we had
jointly participated
with TODD. The purchase price was $22.5 million in cash (a total cost of $23.4 million including abandonment liabilities
we assumed). Total net proved reserves acquired are estimated to be 700 MBOE (4 Bcfe), 36% of which is oil. By virtue
of this acquisition, we increased our after payout net revenue interest in the Eagle Ford Shale by an additional 15%.
Funding for the acquisition was provided through our credit facility. In addition, litigation associated with TODD was
resolved as a result of the transaction.
Outlook
The U.S. and other world economies suffered a severe recession lasting well into 2009 and
economic conditions remain uncertain. These uncertain economic conditions reduced demand for oil
and natural gas, resulting in a decline in oil and natural gas prices received for our production
in 2009 compared with years prior to and including 2008. In 2010 and 2011 we have benefitted from
increasing prices for oil, but natural gas prices remain at lower levels.
While oil and natural gas prices have strengthened, we expect them to
remain volatile in the future. Factors affecting the price of oil include worldwide economic
conditions, geopolitical activities, worldwide supply disruptions, weather conditions, actions
taken by the Organization of Petroleum Exporting Countries, the credit rating of U.S. goverment debt and the value of the U.S. dollar in
international currency markets. Factors affecting the price of
natural gas include U.S. economic conditions, North American
weather conditions, industrial and consumer demand for natural gas, storage levels of natural gas, the credit rating of U.S. goverment debt and the availability and accessibility of natural gas deposits in North America. If the global
economic uncertainty continues, commodity prices may be depressed for an extended period of time,
which could alter our development plans and adversely affect our growth strategy and our ability to
access additional funding in the capital markets.
We have used, and expect to continue to use, oil and natural gas derivative contracts to
reduce our exposure to the risks of changes in the prices of oil and natural gas. Pursuant to our
risk management
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policy, we engage in these activities as a hedging mechanism against price
volatility associated with pre-existing or anticipated sales of oil and natural gas. As of June 30, 2011, we have hedged
approximately 63% of our forecasted production from proved developed reserves through 2016 at
minimum average annual prices ranging from $5.50 per MMBtu to $6.40 per MMBtu and $82.26 per Bbl to
$95.00 per Bbl.
The primary factors affecting our production levels are capital availability, the success of
our drilling program and our inventory of drilling prospects. In addition, we face the challenge of
natural production declines. As initial reservoir pressures are depleted, production from a given
well decreases. We attempt to overcome this natural decline primarily through developing our existing
undeveloped reserves. Our future growth will depend on our ability to continue to add reserves in
excess of production. Our ability to add reserves through drilling and other development techniques is dependent on our capital
resources and can be limited by many factors, including our ability to timely obtain drilling
permits and regulatory approvals. Any delays in drilling, completing or connecting our new wells to
gathering lines will negatively affect our production, which will have an adverse effect on our
revenues and, as a result, cash flow from operations.
Operations Update
Deep
Bossier: This remains our largest producing area, contributing an average of about
53 MMcf/d (million cubic feet of gas per day). Since the end of the
first quarter of 2011 we have
participated in drilling five successful wells in this area, with initial production rates ranging from 20
MMcf/d to 1.5 MMcf per day. Additionally, one well was recompleted resulting in a new production rate of approximately 34 MMcf/d. We have a 33% working interest in this EnCana operated
well. Currently one well is drilling and one well is waiting on completion in this field.
Eagle Ford Shale: We are participating
with our operating partner, Murphy Oil, in a multi-year drilling
effort in the liquids window of Karnes County, where we have 21% to 25% working interests in
approximately 19,000 gross acres. Currently we have interests in 14 producing wells. Since the end of the
first quarter of 2011, we have participated in the drilling of nine wells. Of those nine wells, four wells
have been brought online and five wells are waiting to be fracture stimulated or completed. Two wells are
currently drilling, and five locations have been prepared for future drilling. The operator has secured a
hydraulic fracturing contractor who will be dedicated to our wells in the area for the next two years.
Weeks
Island: We began our multi-well drilling program during the
second quarter of 2011, drilling two
successful wells, one of which is expected to reach approximately 200
Bbls per day and is currently producing at rates between 60 and 150 Bbls per day. The second
well was also productive and is under analysis for optimal reservoir
exploitation. We also recently finished two recompletions in Weeks Island, with one producing at approximately
180 Bbls per day and the other reflecting an initial rate of
500 Bbls of oil per day,
although it is temporarily off-line for a gravel-packing operation.
Cold Springs Field:
We took over as operator of the Cold Springs Field in the second quarter, and are continuing development of multiple
stacked pays, primarily in the Wilcox sand. During the quarter, we established production in two previously un-tested
Wilcox zones. The shallower of these zones tested at an initial production rate of 300 Bbls of oil per day, and is
present in several wells in the field. It will be tested in the next recompletion in early August 2011. We believe
there are at least 12 wells to drill in the extension area for this field, the first of which is scheduled to be
spudded in the third quarter of 2011. We also made a small acquisition in this field in the second quarter
of 2011.
Oklahoma: We are continuing with our infill drilling program in the Lincoln North Unit which is
designed to further exploit the unitized Oswego and Big Lime formations and will also target other deeper, prospective
formations,
including the Mississippi Lime formation. The East Hennessey Unit waterflood
expansion is now underway with water injection in the initial pilot area for the flood.
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Results of Operations: Three Months Ended June 30, 2011 v. Three Months Ended June 30, 2010
Three Months Ended June 30, | Increase | |||||||||||||||
2011 | 2010 | (Decrease) | % Change | |||||||||||||
($ in thousands, except average sales price and unit costs) | ||||||||||||||||
Summary Operating Information: |
||||||||||||||||
Net Production: |
||||||||||||||||
Natural gas (MMcf) |
7,979 | 5,701 | 2,278 | 40 | % | |||||||||||
Oil (MBbls) |
376 | 213 | 163 | 77 | % | |||||||||||
Natural gas liquids (MBbls) |
50 | 26 | 24 | 92 | % | |||||||||||
Total natural gas equivalent (MMcfe) |
10,535 | 7,135 | 3,400 | 48 | % | |||||||||||
Average daily gas production (MMcfe per day) |
115.8 | 78.4 | 37.4 | 48 | % | |||||||||||
Average Sales Price: |
||||||||||||||||
Natural gas (per Mcf) realized |
$ | 4.85 | $ | 5.28 | $ | (0.43 | ) | (8 | %) | |||||||
Natural gas (per Mcf) unhedged |
4.21 | 4.15 | 0.06 | 1 | % | |||||||||||
Oil (per Bbl) realized |
104.50 | 76.38 | 28.12 | 37 | % | |||||||||||
Oil (per Bbl) unhedged |
110.97 | 76.20 | 34.77 | 46 | % | |||||||||||
Natural gas liquids (per Bbl) realized (1) |
56.87 | 46.73 | 10.14 | 22 | % | |||||||||||
Combined (per Mcfe) realized |
7.68 | 6.67 | 1.01 | 15 | % | |||||||||||
Hedging Activities: |
||||||||||||||||
Realized natural gas revenue gain |
$ | 5,120 | $ | 6,452 | $ | (1,332 | ) | (21 | %) | |||||||
Realized oil revenue gain (loss) |
(2,434 | ) | 39 | (2,473 | ) | (6,341 | %) | |||||||||
Summary Financial Information |
||||||||||||||||
Revenues |
||||||||||||||||
Natural gas |
$ | 38,731 | $ | 30,120 | $ | 8,611 | 29 | % | ||||||||
Oil |
39,292 | 16,278 | 23,014 | 141 | % | |||||||||||
Natural gas liquids |
2,847 | 1,214 | 1,633 | 135 | % | |||||||||||
Other revenues |
297 | 386 | (89 | ) | (23 | %) | ||||||||||
Unrealized gain (loss) oil and natural gas derivative contracts |
14,377 | 2,105 | 12,272 | 583 | % | |||||||||||
95,544 | 50,103 | 45,441 | 91 | % | ||||||||||||
Expenses |
||||||||||||||||
Lease and plant operating expense |
15,041 | 9,354 | 5,687 | 61 | % | |||||||||||
Production
and ad valorem taxes |
4,069 | 2,785 | 1,284 | 46 | % | |||||||||||
Workover expense |
2,352 | 1,330 | 1,022 | 77 | % | |||||||||||
Exploration expense |
5,690 | 1,651 | 4,039 | 245 | % | |||||||||||
Depreciation, depletion, and amortization |
22,963 | 13,500 | 9,463 | 70 | % | |||||||||||
Impairment expense |
4,929 | 643 | 4,286 | 667 | % | |||||||||||
Accretion expense |
476 | 270 | 206 | 76 | % | |||||||||||
General and
administrative expenses |
8,843 | 4,679 | 4,164 | 89 | % | |||||||||||
Interest expense, net |
6,831 | 4,525 | 2,306 | 51 | % | |||||||||||
(Gain) on contract settlement |
(1,285 | ) | | (1,285 | ) | NA | ||||||||||
Provision for state income taxes |
75 | | 75 | NA | ||||||||||||
Net income |
$ | 25,560 | $ | 11,366 | $ | 14,194 | 125 | % | ||||||||
Average Unit Costs per Mcfe: |
||||||||||||||||
Lease and plant operating expense |
$ | 1.43 | $ | 1.31 | $ | 0.12 | 9 | % | ||||||||
Production
and ad valorem taxes |
0.39 | 0.39 | | 0 | % | |||||||||||
Workover expense |
0.22 | 0.19 | 0.03 | 16 | % | |||||||||||
Exploration expense |
0.54 | 0.23 | 0.31 | 135 | % | |||||||||||
Depreciation, depletion and amortization |
2.18 | 1.89 | 0.29 | 15 | % | |||||||||||
General and
administrative expenses |
0.84 | 0.66 | 0.18 | 27 | % |
(1) | The Company does not utilize hedges for natural gas liquids. |
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Revenues
Natural gas revenues for the three months ended June 30, 2011 were $38.7 million, compared to
$30.1 million for the same period in 2010, representing an $8.6 million or 29% increase. The
increase in revenue was attributable to increased production volumes partially offset by lower
realized prices during the three months ended June 30, 2011. The increase in production volumes of
2.3 Bcf resulted in increased revenue of approximately $12.0 million primarily related to
production from our Meridian acquisition in May 2010 (.7 Bcf) and new production in the Deep
Bossier (1.9 Bcf). The decrease in realized prices (including hedge activity) from $5.28 per Mcf
in the second quarter of 2010 to $4.85 per Mcf in the second quarter of 2011 resulted in decreased
revenue of approximately $3.4 million. The price of gas before
hedging increased from $4.15 per Mcf
in the second quarter of 2010 to $4.21 per Mcf in the second quarter of 2011.
Oil
revenues for the three months ended June 30, 2011 increased $23 million, or 141%, to $39.3
million from $16.3 million for the three months ended June 30, 2010. The increase in revenue was
due to higher production volumes and higher realized prices. Oil production for the second quarter
of 2011 increased to 376 MBbls from 213 MBbls for the same period in 2010, an increase of 77%. The
increase is primarily related to the full-quarter effect of production from our Meridian
acquisition (105 MBbls higher than the second quarter of 2010)
and to new production from our Eagle Ford Shale area (52 MBbls).
During the three months ended June
30, 2011, our average realized oil price (including hedge activity) increased from $76.38 per Bbl
in the second quarter of 2010 to $104.50 per Bbl in the comparable period of 2011. The price of oil
before hedging increased from $76.20 per Bbl to $110.97 per Bbl for the comparative periods.
Natural gas liquids revenues increased during the second quarter of 2011 to $2.8 million from
$1.2 million for the second quarter of 2010. The increase was due to an increase in volume sold,
from 26 MBbls to 50 MBbls, and increased prices, from $46.73 to
$56.87 for the three months ended
June 30, 2010 and 2011, respectively. The increased production is primarily related to our
Meridian acquisition in May 2010.
Other
revenues were $297,000 during the three months ended June 30, 2011 as compared to
$386,000 during the three months ended June 30, 2010. The decrease is primarily the result of a
decrease in income from investments, offset by increased income from rental of our drilling rig.
Unrealized
gain (loss) oil and natural gas derivative contracts was a gain of $14.4 million
during the three months ended June 30, 2011 as compared to a gain of $2.1 million during the same
period in 2010. The significant fluctuation from period to period is due to the volatility of oil
and natural gas prices and changes in our outstanding hedging contracts during these periods.
Expenses
Lease and plant operating expense increased $5.7 million in the second quarter of 2011 as
compared to the second quarter of 2010, due partially to the full quarter effect of lease operating
expenses related to our Meridian acquisition in May 2010, $2.2 million. In addition, expenditures
at Deep Bossier increased $3.3 million, primarily due to an increase in the number of producing
wells and increased gas marketing fees. On a unit basis, lease and plant operating expense
increased from $1.31 per Mcfe to $1.43 per Mcfe for the three months ended June 30, 2010 and 2011,
respectively.
30
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Production
and ad valorem taxes increased $1.3 million, or 46%, to $4.1 million for the second
quarter of 2011, as compared to $2.8 million for the second quarter of 2010. Ad valorem taxes
increased $0.4 million, due to our Meridian acquisition in May 2010 and increased taxable values of
our properties. The remaining increase of $0.9 million is attributable to production taxes, which
increased 37%, following an increase in our revenue from products of 70%. The change in the mix of
our sales toward a higher percentage of revenues from oil impacts the variance in this expense.
Tax rates on oil are higher than for gas in Louisiana, where the majority of our oil is produced.
Oil as a percentage of product revenues increased from 34% to 49% in the second quarter of 2011 as
compared to the same period in 2010.
Workover expense increased from the second quarter of 2010 as compared to the second quarter
of 2011, from $1.3 million to $2.4 million, respectively. This expense varies depending on
activities in the field.
Exploration expense includes the costs of our geology departments, costs of geological and
geophysical data, delay rentals, expired leases, and dry holes. Exploration expense increased from
$1.7 million for the second quarter of 2010 to $5.7 million for the second quarter of 2011. The
increase is primarily due to dry hole expense recorded in the second quarter of 2011 of
approximately $4.5 million.
Depreciation, depletion and amortization increased $9.5 million to $23 million for the second
quarter of 2011 as compared to an expense of $13.5 million for the second quarter of 2010. On a
per unit basis, this expense increased from $1.89 to $2.18 per Mcfe. The rate is a function of
capitalized costs of proved properties, reserves and production by field.
Impairment expense increased from $0.6 million in the second quarter of 2010 to $4.9 million
in the second quarter of 2011. This expense varies with the results of exploratory drilling, as
well as with price declines which may render some projects uneconomic, resulting in impairment.
Accretion expense is related to our obligation for retirement of oil and natural gas wells and
facilities. We record these liabilities when we place the assets in service, using discounted
present values of the estimated future obligation. We then record accretion of the liabilities as
they approach maturity. Accretion expense was $0.5 million and $0.3 million for the second quarter
of 2011 and 2010, respectively. The increase was due to the acquisition of Meridian.
General and administrative expenses increased $4.1 million for the three months ended June 30,
2011 to $8.8 million from $4.7 million for the three months ended June 30, 2010. The increase in
general and administrative expenses resulted principally from increased payroll and burden costs of
$1.1 million, which are predominately related to increased headcount from our Meridian acquisition
and additional personnel. Consulting expenses increased $2.2 million, primarily for legal fees,
accounting fees (primarily related to the registration of our bonds), and to other consulting
services, including risk management (hedging strategy) and expenses assumed with the Meridian
acquisition. Office expenditures increased $0.4 million in the second quarter of 2011 as compared
to 2010, primarily due to the assumption of Meridian office space in
May 2010. On a per unit basis,
general and administrative expenses increased from $0.66 to $0.84 per Mcfe.
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Interest expense, net increased $2.3 million for the three months ended June 30, 2011 to $6.8
million from $4.5 million for the three months ended
June 30, 2010, primarily due to $7.3 million in interest on
our 9 5/8% senior notes issued in October 2010, and increased amortization of
deferred loan costs of $0.3 million. This increase is partially offset by decreased
interest rate hedge losses of $3.3 million, primarily due to hedge gains of $2.8 million related to
interest rate hedge contract modifications and decreased interest on bank debt of $1.9 million due
to a decrease in the amount outstanding under our credit facility and to the retirement of our $40
million subordinated debt in October 2010.
Gain on contract settlement is related to the settlement of an obligation the Company assumed
upon the purchase of Meridian. The obligation related to underutilization of two contracted
drilling rigs, as described in Note 10 of the accompanying notes to our financial statements. We
recorded an estimated liability of $9.8 million for the obligation upon purchase of Meridian in
2010. The obligation was subsequently settled in the second quarter of 2011 for $8.5 million,
resulting in a gain of $1.3 million.
32
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Results of Operations: Six Months Ended June 30, 2011 v. Six Months Ended June 30, 2010
Six Months Ended June 30, | Increase | |||||||||||||||
2011 | 2010 | (Decrease) | % Change | |||||||||||||
($ in thousands, except average sales price and unit costs) | ||||||||||||||||
Summary Operating Information: |
||||||||||||||||
Net Production: |
||||||||||||||||
Natural gas (MMcf) |
15,345 | 10,670 | 4,675 | 44 | % | |||||||||||
Oil (MBbls) |
724 | 335 | 389 | 116 | % | |||||||||||
Natural gas liquids (MBbls) |
108 | 39 | 69 | 177 | % | |||||||||||
Total natural gas equivalent (MMcfe) |
20,338 | 12,918 | 7,420 | 57 | % | |||||||||||
Average daily gas production (MMcfe per day) |
112.4 | 71.4 | 41.0 | 57 | % | |||||||||||
Average Sales Price: |
||||||||||||||||
Natural gas (per Mcf) realized |
$ | 4.83 | $ | 5.43 | $ | (0.60 | ) | (11 | %) | |||||||
Natural gas (per Mcf) unhedged |
4.12 | 4.57 | (0.45 | ) | (10 | %) | ||||||||||
Oil (per Bbl) realized |
98.70 | 76.96 | 21.74 | 28 | % | |||||||||||
Oil (per Bbl) unhedged |
104.11 | 76.14 | 27.97 | 37 | % | |||||||||||
Natural gas liquids (per Bbl) realized (1) |
54.73 | 49.30 | 5.43 | 11 | % | |||||||||||
Combined (per Mcfe) realized |
7.45 | 6.63 | 0.82 | 12 | % | |||||||||||
Hedging Activities: |
||||||||||||||||
Realized natural gas revenue gain |
$ | 10,911 | $ | 9,201 | $ | 1,710 | 19 | % | ||||||||
Realized oil revenue gain (loss) |
(3,918 | ) | 276 | (4,194 | ) | (1520 | %) | |||||||||
Summary Financial Information |
||||||||||||||||
Revenues |
||||||||||||||||
Natural gas |
$ | 74,112 | $ | 57,935 | $ | 16,177 | 28 | % | ||||||||
Oil |
71,489 | 25,799 | 45,690 | 177 | % | |||||||||||
Natural gas liquids |
5,900 | 1,943 | 3,957 | 204 | % | |||||||||||
Other revenues |
766 | 407 | 359 | 88 | % | |||||||||||
Unrealized gain (loss) oil and natural gas derivative contracts |
(4,808 | ) | 22,908 | (27,716 | ) | (121 | %) | |||||||||
147,459 | 108,992 | 38,467 | 35 | % | ||||||||||||
Expenses |
||||||||||||||||
Lease and plant operating expense |
28,372 | 17,432 | 10,940 | 63 | % | |||||||||||
Production and ad valorem taxes |
9,470 | 4,398 | 5,072 | 115 | % | |||||||||||
Workover expense |
3,978 | 3,289 | 689 | 21 | % | |||||||||||
Exploration expense |
8,421 | 4,572 | 3,849 | 84 | % | |||||||||||
Depreciation, depletion, and amortization |
42,431 | 22,122 | 20,309 | 92 | % | |||||||||||
Impairment expense |
10,755 | 2,093 | 8,662 | 414 | % | |||||||||||
Accretion expense |
946 | 415 | 531 | 128 | % | |||||||||||
General and administrative expenses |
14,593 | 6,902 | 7,691 | 111 | % | |||||||||||
Interest expense, net |
16,309 | 8,724 | 7,585 | 87 | % | |||||||||||
(Gain) on contract settlement |
(1,285 | ) | | (1,285 | ) | NA | ||||||||||
Provision for state income taxes |
75 | | 75 | NA | ||||||||||||
Net income |
$ | 13,394 | $ | 39,045 | $ | (25,651 | ) | (66 | %) | |||||||
Average Unit Costs per Mcfe: |
||||||||||||||||
Lease and plant operating expense |
$ | 1.40 | $ | 1.35 | $ | 0.05 | 4 | % | ||||||||
Production and ad valorem taxes |
0.47 | 0.34 | 0.13 | 38 | % | |||||||||||
Workover expense |
0.20 | 0.25 | (0.05 | ) | (20 | %) | ||||||||||
Exploration expense |
0.41 | 0.35 | 0.06 | 17 | % | |||||||||||
Depreciation, depletion and amortization |
2.09 | 1.71 | 0.38 | 22 | % | |||||||||||
General and administrative expenses |
0.72 | 0.53 | 0.19 | 36 | % |
(1) | The Company does not utilize hedges for natural gas liquids. |
33
Table of Contents
Revenues
Natural gas revenues for the six months ended June 30, 2011 were $74.1 million, compared to
$57.9 million for the same period in 2010, representing a $16.2 million or 28% increase. The
increase in revenue was attributable to increased production volumes partially offset by lower
realized prices during the six months ended June 30, 2011. The increase in production volumes of
4.7 Bcf resulted in increased revenue of approximately $25.4 million primarily related to
production from our Meridian acquisition in May 2010 (2.3 Bcf) and new production in the Deep
Bossier (2.9 Bcf). The decrease in realized prices (including hedge activity) from $5.43 per Mcf
in the first half of 2010 to $4.83 per Mcf in the first half of 2011 resulted in decreased
revenue of approximately $9.2 million. The price of gas before
hedging decreased from $4.57 per Mcf
in the first half of 2010 to $4.12 per Mcf in the first half of 2011.
Oil
revenues for the six months ended June 30, 2011 increased $45.7 million, or 177%, to $71.5
million from $25.8 million for the six months ended June 30, 2010. The increase in revenue was due
to higher production volumes and higher realized prices. Oil production for the first half of 2011
increased to 724 MBbls from 335 MBbls for the same period in 2010, an increase of 116%. The
increase is primarily related to production from our Meridian
acquisition in May 2010 (320 MBbls higher than the second
quarter of 2010) and to new production from our Eagle Ford Shale area
(58 MBbls).
During the six months ended June 30, 2011, our average realized oil price (including hedge
activity) increased from $76.96 per Bbl in the first half of 2010 to $98.70 per Bbl in the
first half of 2011. The price of oil before hedging increased from $76.14 per Bbl to $104.11 per
Bbl for the same comparative periods.
Natural
gas liquids revenues increased during the first half of 2011 to $5.9 million from $1.9
million for the first half of 2010. The increase was due to an increase in volume sold, from 39
MBbls to 108 MBbls, and increased prices, from $49.30 to $54.73 per Bbl for the six months ended
June 30, 2010 and 2011, respectively. The increased production is primarily related to our
Meridian acquisition in May 2010.
Other revenues were $766,000 during the six months ended June 30, 2011 as compared to $407,000
during the six months ended June 30, 2010. The increase is primarily the result of increased
income from rental of our drilling rig, and from sales of prospects, offset by a decrease in income
from investments.
Unrealized gain (loss) oil and natural gas derivative contracts was a loss of $4.8 million
during the six months ended June 30, 2011 as compared to a gain of $22.9 million during the same
period in 2010. The significant fluctuation from period to period is due to the volatility of oil
and natural gas prices and changes in our outstanding hedging contracts during these periods.
Expenses
Lease
and plant operating expense increased $10.9 million in the first half of 2011 as compared
to the first half of 2010, due partially to the full six-month effect of lease operating expenses
related to our Meridian acquisition in May 2010, $6.3 million. In addition, expenditures in Deep
Bossier increased $5.2 million, primarily due to an increase in the number of producing wells and
increased gas marketing fees. On a unit basis, lease and plant operating expense increased from
$1.35 per Mcfe to $1.40 per Mcfe for the six months ended
June 30, 2010 and 2011, respectively.
34
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Production
and ad valorem taxes increased $5.1 million, or 115%, to $9.5 million for the first
half of 2011, as compared to $4.4 million for the first half of 2010. Ad valorem taxes increased
$1.3 million, due to our Meridian acquisition in May 2010 and increased taxable values of our
properties. The remaining increase of $3.8 million is attributable to production taxes, which
increased 100%, following an increase in our revenue from products of 77%. The change in the mix of
our sales toward a higher percentage of revenues from oil impacts the variance in this expense.
Tax rates on oil are higher than for gas in Louisiana, where the majority of our oil is produced.
Oil as a percentage of product revenues increased from 30% to 47% in the first half of 2011 as
compared to 2010.
Workover expense increased from the first half of 2010 as compared to the first half of 2011,
from $3.3 million to $4.0 million, respectively. This expense varies depending on activities in the
field.
Exploration expense includes the costs of our geology departments, costs of geological and
geophysical data, delay rentals, expired leases, and dry holes. Exploration expense increased $3.8
million for the first half of 2011 to $8.4 million from
$4.6 million for the first half of 2010. The
increase is primarily due to dry hole expense recorded in the first half of 2011 of approximately
$5.3 million.
Depreciation, depletion and amortization increased $20.3 million to $42.4 million for the
first half of 2011 as compared to an expense of $22.1 million for the first half of 2010. On a per
unit basis, this expense increased from $1.71 to $2.09 per Mcfe. The rate is a function of
capitalized costs of proved properties, reserves and production by field.
Impairment
expense increased from $2.1 million in the first half of 2010 to $10.8 million in
the first half of 2011. This expense varies with the results of exploratory drilling, as well as
with price declines which may render some projects uneconomic, resulting in impairment.
Accretion expense is related to our obligation for retirement of oil and natural gas wells and
facilities. We record these liabilities when we place the assets in service, using discounted
present values of the estimated future obligation. We then record accretion of the liabilities as
they approach maturity. Accretion expense was $0.9 million and
$0.4 million for the first half of
2011 and 2010, respectively. The increase was due to the acquisition of Meridian.
General and administrative expenses increased $7.7 million for the six months ended June 30,
2011 to $14.6 million from $6.9 million for the six months ended June 30, 2010. The increase in
general and administrative expenses resulted principally from increased payroll and burden costs of
$3.5 million, which are predominately related to increased headcount from our Meridian acquisition
and additional personnel. Other general and administrative costs related to the acquisition of
Meridian also increased, including office rent, which increased $0.8 million in the first half of
2011 as compared to 2010. Consulting expenses increased $2.8 million, primarily for legal fees,
accounting fees,and other consulting services, including risk management (hedging) and expenses
assumed in the acquisition of Meridian. On a unit basis, general and administrative expense
increased from $0.53 to $0.72 per Mcfe.
Interest expense, net increased $7.6 million for the six months ended June 30, 2011 to $16.3
million from $8.7 million for the six months ended June 30,
2010, primarily due to $14.5 million in interest on our
9 5/8% senior notes issued in October 2010, and increased amortization of deferred
loan costs of $1.1 million. This increase is partially offset by decreased interest
rate hedge losses of $4.1 million, primarily due to hedge gains of $2.8 million recorded in the
first half of 2011 related to interest hedge contract modifications. In addition, interest on bank
debt decreased $3.9 million due to a decrease in the amount outstanding under our credit facility
and to the retirement of our $40 million subordinated debt in October 2010.
Gain on contract settlement is related to the settlement of an obligation the Company assumed
upon the purchase of Meridian. The obligation related to underutilization of two contracted
drilling rigs, as described in Note 10 of the accompanying notes to our financial statements. We
recorded an estimated liability of $9.8 million for the obligation upon purchase of Meridian in
2010. The obligation was subsequently settled in the second quarter of 2011 for $8.5 million,
resulting in a gain of $1.3 million.
35
Table of Contents
Liquidity and Capital Resources
Our principal requirements for capital are to fund our day-to-day operations, development
activities, and to satisfy our contractual obligations, primarily for the repayment of debt and any
amounts owed during the period related to our hedging positions.
Our 2011 capital budget is primarily focused on the development of existing core areas through
exploitation and development. Currently, we plan to spend a total of approximately $180 million
during 2011, of which, approximately $80 million has been expended or accrued through June 30, 2011. Approximately 83% of our 2011 capital budget is allocated to our properties in Deep
Bossier, East Texas, Eagle Ford, and South Louisiana. Our future drilling plans, plans of our
drilling operators and capital budgets are subject to change based upon various factors, some of
which are beyond our control, including drilling results, oil and natural gas prices, the
availability and cost of capital, drilling and production costs, availability of drilling services
and equipment, actions of our operators, gathering system and pipeline transportation constraints
and regulatory approvals. Because a large percentage of our acreage is held by production, we have
the ability to materially decrease our drilling and recompletion budget in response to market
conditions with minimal risk of losing significant acreage.
We expect to fund our 2011 capital budget predominantly with cash flows from operations,
supplemented by use of our credit facility. If necessary, we may also access capital through
proceeds from potential asset dispositions, and the
future issuance of debt and/or equity securities, subject to the distribution of proceeds therefrom
as set forth in our partnership agreement. We strive to maintain financial flexibility and may
access capital markets as necessary to maintain substantial borrowing capacity under our senior
secured revolving credit facility, facilitate drilling on our large undeveloped acreage position
and permit us to selectively expand our acreage position. In the event our cash flows are
materially less than anticipated and other sources of capital we historically have utilized are not
available on acceptable terms, we may curtail our capital spending.
Senior Notes
In October 2010, we adjusted our capital structure by issuing $300 million of 9 5/8% senior
notes due 2018 (senior notes). The senior notes were issued at a discount of $2.1 million,
bringing the effective rate to 9 3/4%.
The senior notes are unsecured senior general corporate obligations, and effectively rank
junior to any of our existing or future secured indebtedness, which includes our credit facility.
The senior notes are unconditionally guaranteed on a senior unsecured basis by each of our
material, wholly owned
36
Table of Contents
subsidiaries. We entered into a registration rights agreement with the purchasers of the
senior notes. We filed a registration statement with the SEC to allow for registration of
exchanges notes substantially identical to the senior notes, which was declared effective by the
SEC on July 14, 2011. On August 12, 2011, the exchange notes were exchanged for the original
senior notes tendered in connection with the exchange offer.
Credit Facility
We have a senior secured revolving credit facility (credit facility) with Wells Fargo Bank,
N.A. as the administrative agent. As of June 30, 2011, the credit facility was subject to a $260
million borrowing base limit, and we had $159.8 million outstanding under the credit facility. Our
restricted subsidiaries are guarantors of the credit facility.
Our credit facility provides for two alternative interest rate bases and margins. Eurodollar
loans accrue interest generally at the one-month London Interbank Offered Rate plus a margin
ranging from 2.00% to 2.75%, depending on the utilization of our borrowing base. Reference rate
loans accrue interest at the prime rate of Wells Fargo Bank, N.A., plus a margin ranging from 1.00%
to 1.75%, depending on the utilization of our borrowing base. The total rate on all loans
outstanding as of June 30, 2011 under the credit facility was 2.519%, which was based on the
Eurodollar option.
The credit facility and senior notes include covenants requiring us to maintain certain
financial covenants including a current ratio, leverage ratio, and interest coverage ratio. At
June 30, 2011, we were in compliance with the covenants. The terms of the credit facility also
restrict our ability to make distributions and investments.
Cash flow provided by operating activities
Operating activities provided cash of $71.2 million during the six months ended June 30, 2011
as compared to $16.1 million during the comparable period in 2010. The $55.1 million increase in
operating cash flows was attributable to an increase in the cash-based portions of our earnings, as
well as changes in working capital accounts. Cash-based items of net income, including revenues
(exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and
administrative expenses, and the cash portion of our interest expense, provided a net increase of
approximately $36.7 million in earnings and a related positive impact on cash flow. Augmenting
this were changes in our working capital accounts, which used $6.8 million of cash flows as
compared to having used $25.2 million in cash in 2010. This reversal resulted in a total increase
of $18.4 million in cash flow, which as noted above, augments the positive effects of increased
cash-based earnings.
Cash flow used in investing activities
Investing activities used cash of $155.4 million during the six months ended June 30, 2011 as
compared to cash used in investing of $133.6 million during the comparable period of 2010. The
decrease in cash used in acquisition activities was due to the $101.4 million invested in the
Meridian acquisition in the first half of 2010. Acquisitions in the first half of 2011 were $61.2
million, primarily for the additional interest in legacy Meridian properties acquired from Sydson
and TODD. The total cash purchase price of these two acquisitions was approximately $50 million.
See Note 3 of the accompanying financial statements for further information. Aside from the
acquisitions, investment in property and equipment increased by $61.8 million as compared to the
prior year period, primarily related to development activities in our Deep Bossier, Eagle Ford
Shale, and East Texas area properties. We also invested in development activities in South
Louisiana and Oklahoma.
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Table of Contents
Cash flow provided by financing activities
Financing activities provided cash of $84.9 million during the six months ended June 30, 2011
as compared to cash provided by financing of $137.6 million during the six months ended June 30,
2010. The decrease is due to the large drawdown of funds under our credit agreement ($95 million)
and the capital infusion of $50 million in the first half of 2010, which funded the Meridian
acquisition. Cash from financing activities in the first half of 2011 included drawdowns of $86.5
million, of which approximately $50 million was directly used for the Sydson and TODD acquisitions.
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk
For information regarding our exposure to certain market risks, see Managements Discussion
and Analysis of Financial Condition and Results of OperationsQuantitative and Qualitative
Disclosures about Market Risk, Commodity Price Risk and Hedges and Interest Rates in the
Form S-4. There have been no material changes to the disclosure regarding market risks.
ITEM 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
In accordance
with Exchange Act Rule 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation
of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our
disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation,
our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were
effective as of June 30, 2011 to provide reasonable assurance that information required to be disclosed in our reports
filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified
in the Securities and Exchange Commissions rules and forms. Our disclosure controls and procedures include controls
and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the
Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial
Officer, as appropriate, to allow timely decisions regarding required disclosure.
Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting during the three
months ended June 30, 2011 that has materially affected, or is reasonably likely to materially
affect, our internal control over financial reporting.
PART II OTHER INFORMATION
ITEM 1. Legal Proceedings
See Part I, Item 1, Note 10 to our consolidated financial statements entitled Commitments and
Contingencies, which is incorporated in this item by reference.
ITEM 1A. Risk Factors
We are subject to certain risks and hazards due to the nature of the business activities we
conduct. For a discussion of these risks, see Risk Factors in the Form S-4. There have been no
material changes with respect to the risk factors disclosed in the Form S-4 during the quarter
ended June 30, 2011.
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
38
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ITEM 3. Defaults Upon Senior Securities
None.
ITEM 4. (Removed and Reserved)
ITEM 5. Other Information
None.
ITEM 6. Exhibits
10.1
|
Purchase and Sale Agreement between Michael J. Mayell and Alta Mesa Energy, LLC, dated April 21, 2011. | |
10.2
|
Purchase and Sale Agreement between Sydson Energy, Inc. and Alta Mesa Energy, LLC, dated April 21, 2011. | |
10.3
|
Purchase and Sale Agreement by and among Texas Oil Distribution & Development, Inc., JAR Resource Holdings, L.P., Joseph A. Reeves, Jr., Dianne S. Reeves and Alta Mesa Energy, LLC, dated June 17, 2011. | |
31.1
|
Certification of the Companys Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241). | |
31.2
|
Certification of the Companys Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241). | |
32.1
|
Certification of the Companys Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350). | |
32.2
|
Certification of the Companys Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350). | |
*101
|
Interactive Data Files. |
* | Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability. |
39
Table of Contents
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 hereunto duly authorized.
ALTA MESA HOLDINGS, LP (Registrant) |
||||
By: | ALTA MESA HOLDINGS GP, LLC, its general partner | |||
August 12, 2011 | By: | /s/ Harlan H. Chappelle | ||
Harlan H. Chappelle | ||||
President and Chief Executive Officer | ||||
August 12, 2011 | By: | /s/ Michael A. McCabe | ||
Michael A. McCabe | ||||
Vice President and Chief Financial Officer |
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