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EXCEL - IDEA: XBRL DOCUMENT - Alta Mesa Holdings, LP | Financial_Report.xls |
EX-32.1 - EX-32.1 - Alta Mesa Holdings, LP | h85469exv32w1.htm |
EX-31.2 - EX-31.2 - Alta Mesa Holdings, LP | h85469exv31w2.htm |
EX-31.1 - EX-31.1 - Alta Mesa Holdings, LP | h85469exv31w1.htm |
EX-32.2 - EX-32.2 - Alta Mesa Holdings, LP | h85469exv32w2.htm |
EX-10.1 - EX-10.1 - Alta Mesa Holdings, LP | h85469exv10w1.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: September 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 þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files.) Yes
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 | Smaller reporting company o | |||
(Do not check if a smaller reporting company) |
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 PRESENTATION LINKBASE DOCUMENT |
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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 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.
3
Table of Contents
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)
September 30, | December 31, | |||||||
2011 | 2010 | |||||||
(unaudited) | ||||||||
ASSETS |
||||||||
CURRENT ASSETS |
||||||||
Cash and cash equivalents |
$ | 4,572 | $ | 4,836 | ||||
Accounts receivable, net |
42,888 | 38,081 | ||||||
Other receivables |
2,697 | 6,338 | ||||||
Prepaid expenses and other current assets |
3,725 | 2,292 | ||||||
Derivative financial instruments |
25,787 | 10,436 | ||||||
TOTAL CURRENT ASSETS |
79,669 | 61,983 | ||||||
PROPERTY AND EQUIPMENT |
||||||||
Oil and natural gas properties, successful efforts method, net |
555,357 | 442,880 | ||||||
Other property and equipment, net |
16,029 | 13,384 | ||||||
TOTAL PROPERTY AND EQUIPMENT, NET |
571,386 | 456,264 | ||||||
OTHER ASSETS |
||||||||
Investment in Partnership cost |
9,000 | 9,000 | ||||||
Deferred financing costs, net |
12,898 | 13,552 | ||||||
Derivative financial instruments |
24,106 | 14,165 | ||||||
Advances to operators |
4,088 | 2,699 | ||||||
Deposits |
1,896 | 576 | ||||||
TOTAL OTHER ASSETS |
51,988 | 39,992 | ||||||
TOTAL ASSETS |
$ | 703,043 | $ | 558,239 | ||||
LIABILITIES AND PARTNERS CAPITAL |
||||||||
CURRENT LIABILITIES |
||||||||
Accounts payable and accrued liabilities |
$ | 79,318 | $ | 87,255 | ||||
Current portion, asset retirement obligations |
3,418 | 1,617 | ||||||
Derivative financial instruments |
1,959 | 3,092 | ||||||
TOTAL CURRENT LIABILITIES |
84,695 | 91,964 | ||||||
LONG-TERM LIABILITIES |
||||||||
Asset retirement obligations |
43,275 | 41,096 | ||||||
Long-term debt |
471,971 | 371,276 | ||||||
Notes payable to founder |
20,606 | 19,709 | ||||||
Derivative financial instruments |
| 2,296 | ||||||
Other long-term liabilities |
5,052 | 7,240 | ||||||
TOTAL LONG-TERM LIABILITIES |
540,904 | 441,617 | ||||||
TOTAL LIABILITIES |
625,599 | 533,581 | ||||||
COMMITMENTS AND CONTINGENCIES (NOTE 10) |
||||||||
PARTNERS CAPITAL |
77,444 | 24,658 | ||||||
TOTAL LIABILITIES AND PARTNERS CAPITAL |
$ | 703,043 | $ | 558,239 | ||||
See notes to consolidated financial statements.
5
Table of Contents
ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(dollars in thousands)
(unaudited)
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
REVENUES |
||||||||||||||||
Natural gas |
$ | 40,250 | $ | 34,153 | $ | 114,362 | $ | 92,088 | ||||||||
Oil |
42,213 | 23,794 | 113,702 | 49,593 | ||||||||||||
Natural gas liquids |
3,000 | 2,001 | 8,900 | 3,944 | ||||||||||||
Other revenues |
600 | 380 | 1,366 | 787 | ||||||||||||
86,063 | 60,328 | 238,330 | 146,412 | |||||||||||||
Unrealized gain oil and natural gas derivative contracts |
30,101 | 2,712 | 25,292 | 25,620 | ||||||||||||
TOTAL REVENUES |
116,164 | 63,040 | 263,622 | 172,032 | ||||||||||||
EXPENSES |
||||||||||||||||
Lease and plant operating expense |
16,267 | 12,149 | 44,639 | 29,581 | ||||||||||||
Production and ad valorem taxes |
5,728 | 4,015 | 15,198 | 8,413 | ||||||||||||
Workover expense |
4,413 | 1,569 | 8,391 | 4,858 | ||||||||||||
Exploration expense |
3,889 | 4,342 | 12,310 | 8,914 | ||||||||||||
Depreciation, depletion, and amortization |
23,756 | 17,853 | 66,187 | 39,975 | ||||||||||||
Impairment expense |
5,743 | 416 | 16,498 | 2,509 | ||||||||||||
Accretion expense |
484 | 517 | 1,430 | 932 | ||||||||||||
Loss on sale of assets |
| 87 | | 87 | ||||||||||||
General and administrative expenses |
9,659 | 6,020 | 24,251 | 12,922 | ||||||||||||
TOTAL EXPENSES |
69,939 | 46,968 | 188,904 | 108,191 | ||||||||||||
INCOME FROM OPERATIONS |
46,225 | 16,072 | 74,718 | 63,841 | ||||||||||||
OTHER INCOME (EXPENSE) |
||||||||||||||||
Interest expense |
(6,779 | ) | (5,946 | ) | (23,102 | ) | (14,675 | ) | ||||||||
Interest income |
21 | 6 | 35 | 11 | ||||||||||||
Gain on contract settlement |
| | 1,285 | | ||||||||||||
TOTAL OTHER INCOME (EXPENSE) |
(6,758 | ) | (5,940 | ) | (21,782 | ) | (14,664 | ) | ||||||||
INCOME BEFORE STATE INCOME TAXES |
39,467 | 10,132 | 52,936 | 49,177 | ||||||||||||
PROVISION FOR STATE INCOME TAXES |
(75 | ) | (2 | ) | (150 | ) | (2 | ) | ||||||||
NET INCOME |
$ | 39,392 | $ | 10,130 | $ | 52,786 | $ | 49,175 | ||||||||
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)
Nine Months Ended September 30, | ||||||||
2011 | 2010 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||
Net income |
$ | 52,786 | $ | 49,175 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
Depreciation, depletion, and amortization |
66,187 | 39,975 | ||||||
Impairment expense |
16,498 | 2,509 | ||||||
Accretion expense |
1,430 | 932 | ||||||
(Gain) loss on sale of assets |
| 87 | ||||||
Amortization of loan costs |
2,243 | 1,473 | ||||||
Amortization of debt discount |
195 | | ||||||
Dry hole expense |
6,452 | 292 | ||||||
Expired
leases |
93 | | ||||||
Unrealized (gain) on derivatives |
(28,721 | ) | (26,603 | ) | ||||
(Gain) on contract settlement |
(1,285 | ) | | |||||
Interest converted into debt |
897 | 890 | ||||||
Settlement of asset retirement obligation |
(702 | ) | (658 | ) | ||||
Changes in assets and liabilities: |
||||||||
Accounts receivable |
(4,807 | ) | (1,376 | ) | ||||
Other receivables |
3,641 | (1,271 | ) | |||||
Prepaid expenses and other non-current assets |
(4,142 | ) | (7,445 | ) | ||||
Accounts payable, accrued liabilities, and other long-term liabilities |
4,641 | (20,830 | ) | |||||
NET CASH PROVIDED BY OPERATING ACTIVITIES |
115,406 | 37,150 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||
Capital expenditures for property and equipment |
(147,989 | ) | (66,307 | ) | ||||
Acquisitions |
(66,592 | ) | (101,359 | ) | ||||
NET CASH USED IN INVESTING ACTIVITIES |
(214,581 | ) | (167,666 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||
Proceeds from long-term debt |
100,500 | 256,500 | ||||||
Repayments of long-term debt |
| (162,343 | ) | |||||
Additions to deferred financing costs |
(1,589 | ) | (7,584 | ) | ||||
Capital contributions |
| 50,000 | ||||||
Capital distributions |
| (235 | ) | |||||
NET CASH PROVIDED BY FINANCING ACTIVITIES |
98,911 | 136,338 | ||||||
NET INCREASE (DECREASE) IN CASH |
(264 | ) | 5,822 | |||||
CASH AND CASH EQUIVALENTS, beginning of period |
4,836 | 4,274 | ||||||
CASH AND CASH EQUIVALENTS, end of period |
$ | 4,572 | $ | 10,096 | ||||
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION |
||||||||
Cash paid during the period for interest |
$ | 15,734 | $ | 14,204 | ||||
Cash paid during the period for taxes |
$ | | $ | | ||||
Change in property asset retirement obligations, net |
$ | 3,252 | $ | (3 | ) | |||
Change in accruals or liabilities for capital expenditures |
$ | (13,482 | ) | $ | 22,145 |
See notes to consolidated financial statements.
7
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 September 30, 2011, and for the nine
month periods ended September 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 September 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.
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.
8
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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. 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 $661,000
and $338,000 at September 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
September 30, 2011 and 2010, amortization of deferred financing costs included in interest expense
amounted to $0.5 million and $0.8 million, respectively. For the nine months ended September 30,
2011 and 2010, amortization of deferred financing costs included in interest expense amounted to
$2.2 million and $1.5 million, respectively. Deferred financing costs are listed among our
long-term assets, net of accumulated amortization of $6.9 million and $4.7 million at September 30,
2011 and
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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 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 $273 million and $291 million at September 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
In September 2011, the FASB issued ASU 2011-08,
Testing Goodwill for Impairment. ASU 2011-08 amends the guidance for testing goodwill for impairment.
Previously, goodwill was required to be tested at least annually, by comparing the fair value of a reporting unit
with its carrying value, including goodwill. If the carrying value exceeded the fair value, a second test would be
performed to measure the impairment loss, if any. Under the new guidance, testing of goodwill is not prescribed
annually, but rather, when events and circumstances make it more likely than not that the carrying value of a
reporting unit exceeds its fair value. This is known as a qualitative evaluation. If the qualitative evaluation
indicates a possible loss is more likely than not, the two-step test is to be performed. ASU 2011-08 provides
new examples of events and circumstances which could affect such a qualitative evaluation. The new guidance is
effective for fiscal years beginning after December 15, 2011. 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 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.
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% at the time of the acquisition. 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.
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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% at the time of the acquisition. 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 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 nine months ended September 30, 2011. The revenue and
earnings related to the Meridian acquisition are also included in our consolidated statement of income
for the nine months ended September 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 nine
months ended September 30, 2011 |
$ | 98,949 | $ | 49,803 | ||||
Actual results of Sydson included in our statement of income for the period April 21,
2011 through September 30, 2011 |
$ | 4,521 | $ | 1,904 | ||||
Actual results of TODD included in our statement of income for the period June 17,
2011 through September 30, 2011 |
$ | 1,518 | $ | 119 | ||||
Pro forma results for the combined entity for the nine months ended September 30, 2011 |
$ | 266,816 | $ | 54,995 | ||||
Pro forma results for the combined entity for the nine months ended September 30, 2010 |
$ | 208,004 | $ | 52,222 |
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4. PROPERTY AND EQUIPMENT
Property and equipment consists of the following:
September 30, | December 31, | |||||||
2011 | 2010 | |||||||
(unaudited) | ||||||||
(dollars in thousands) | ||||||||
OIL AND NATURAL GAS PROPERTIES |
||||||||
Unproved properties |
$ | 36,923 | $ | 12,020 | ||||
Accumulated impairment |
(5,246 | ) | (2,686 | ) | ||||
Unproved properties, net |
31,677 | 9,334 | ||||||
Proved oil and natural gas properties |
876,286 | 707,364 | ||||||
Accumulated depreciation, depletion, amortization and impairment |
(352,606 | ) | (273,818 | ) | ||||
Proved oil and natural gas properties, net |
523,680 | 433,546 | ||||||
TOTAL OIL AND NATURAL GAS PROPERTIES, net |
555,357 | 442,880 | ||||||
LAND |
1,185 | 1,185 | ||||||
DRILLING RIG |
10,500 | 10,500 | ||||||
Accumulated depreciation |
(969 | ) | (444 | ) | ||||
TOTAL DRILLING RIG, net |
9,531 | 10,056 | ||||||
OTHER PROPERTY AND EQUIPMENT |
||||||||
Office furniture and equipment, vehicles |
6,393 | 3,844 | ||||||
Accumulated depreciation |
(1,080 | ) | (1,701 | ) | ||||
OTHER PROPERTY AND EQUIPMENT, net |
5,313 | 2,143 | ||||||
TOTAL PROPERTY AND EQUIPMENT, net |
$ | 571,386 | $ | 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.
Our senior notes are carried at historical cost, net of amortized discount; we estimate the fair value of the senior notes for disclosure purposes (see Note 2).
This estimation is based on the most recent trading values of the notes at or near the reporting dates.
Oil and natural gas properties are subject to impairment testing and potential impairment write
down. Oil and gas properties with a carrying amount of $31.8 million were written down to their
fair value of $15.3 million, resulting in an impairment charge of $16.5 million for the nine months
ended September 30, 2011. Oil and gas properties with a carrying amount of $7.3 million were
written down to their fair value of $4.8 million, resulting in an impairment charge of $2.5 million
for the nine months ended September 30, 2010. For the three months ended September 30, 2011, oil
and gas properties with a carrying amount of $7.4 million were written down to their fair value of
$1.7 million, resulting in an impairment charge of $5.7 million, and for the three months ended
September 30, 2010, oil and gas properties with a carrying amount of $2.9 million were written down
to their fair value of $2.5 million, resulting in an impairment charge of $0.4 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.
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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 $3.3 million and $34.6 million in additions to
asset retirement obligations measured at fair value during the nine months ended September 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 September 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 September 30, 2011 (unaudited): |
||||||||||||||||
Financial Assets: |
||||||||||||||||
Derivative contracts for oil and natural gas |
$ | | $ | 93,586 | $ | | $ | 93,586 | ||||||||
Financial Liabilities: |
||||||||||||||||
Derivative contracts for oil and natural gas |
| 43,693 | | 43,693 | ||||||||||||
Derivative contracts for interest rate |
| 1,959 | | 1,959 | ||||||||||||
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.
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 crude oil and 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 NYMEX indices. 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 nine month periods ended September 30, 2011 and 2010.
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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:
Fair Values of Derivative Contracts | ||||||||||||||||
Balance Sheet Location at September 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 |
$ | 46,514 | $ | | $ | 47,072 | $ | | ||||||||
Fair value of oil and gas commodity contracts, (liabilities) |
(20,727 | ) | | (22,966 | ) | | ||||||||||
Fair value of interest rate contracts, (liabilities) |
| (1,959 | ) | | | |||||||||||
Total net assets, (liabilities) |
$ | 25,787 | $ | (1,959 | ) | $ | 24,106 | $ | | |||||||
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.
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 ended | For the nine months ended | ||||||||||||||||||
instruments under ASC | Location of Gain | Classification of | September 30, | September 30, | ||||||||||||||||
815 | (Loss) | Gain (Loss) | 2011 | 2010 | 2011 | 2010 | ||||||||||||||
(unaudited) | ||||||||||||||||||||
(dollars in thousands) | ||||||||||||||||||||
Natural gas commodity contracts |
Natural gas revenues | Realized | $ | 5,986 | $ | 7,003 | $ | 16,897 | $ | 16,204 | ||||||||||
Oil commodity contracts |
Oil revenues | Realized | 162 | 273 | (3,756 | ) | 549 | |||||||||||||
Interest rate contracts |
Interest benefit (expense) | Realized | 76 | (1,384 | ) | 2,004 | (3,436 | ) | ||||||||||||
Total realized gains (losses)
from derivatives not designated
as hedges |
$ | 6,224 | $ | 5,892 | $ | 15,145 | $ | 13,317 | ||||||||||||
Natural gas commodity contracts |
Unrealized gain (loss) oil and natural gas derivative contracts | Unrealized | $ | 7,724 | $ | 8,562 | $ | 6,425 | $ | 23,858 | ||||||||||
Oil commodity contracts |
Unrealized gain (loss) oil and natural gasderivative contracts | Unrealized | 22,377 | (5,850 | ) | 18,867 | 1,762 | |||||||||||||
Interest rate contracts |
Interest benefit (expense) | Unrealized | 2,921 | 580 | 3,429 | 983 | ||||||||||||||
Total unrealized gains (losses)
from derivatives not designated
as hedges |
$ | 33,022 | $ | 3,292 | $ | 28,721 | $ | 26,603 | ||||||||||||
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.
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We had the following open derivative contracts for natural gas at September 30, 2011 (unaudited):
NATURAL GAS DERIVATIVE CONTRACTS
Volume in | Weighted | Range | ||||||||||||||
Period and Type of Contract | MMbtu | Average | High | Low | ||||||||||||
2011 |
||||||||||||||||
Price Swap Contracts |
5,815,000 | $ | 5.63 | $ | 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 |
1,480,000 | 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 |
9,810,000 | 4.10 | 4.50 | 4.00 | ||||||||||||
2013 |
||||||||||||||||
Price Swap Contracts |
6,650,000 | 6.18 | 9.15 | 5.35 | ||||||||||||
Collar Contracts |
||||||||||||||||
Short Call Options |
1,500,000 | 6.50 | 6.50 | 6.50 | ||||||||||||
Long Put Options |
1,500,000 | 6.09 | 6.15 | 6.00 | ||||||||||||
Short Put Options |
900,000 | 5.00 | 5.00 | 5.00 | ||||||||||||
2014 |
||||||||||||||||
Price Swap Contracts |
3,125,000 | 6.27 | 7.50 | 5.60 | ||||||||||||
Collar Contracts |
||||||||||||||||
Short Call Options |
3,475,000 | 7.05 | 9.00 | 6.00 | ||||||||||||
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 |
We had the following open derivative contracts for crude oil at September 30, 2011 (unaudited):
OIL DERIVATIVE CONTRACTS
Weighted | Range | |||||||||||||||
Period and Type of Contract | Volume in Bbls | Average | High | Low | ||||||||||||
2011 |
||||||||||||||||
Price Swap Contracts |
184,000 | $ | 82.13 | $ | 103.20 | $ | 67.50 | |||||||||
Collar Contracts |
||||||||||||||||
Short Call Options |
419,900 | 101.01 | 110.00 | 82.25 | ||||||||||||
Long Put Options |
317,400 | 86.67 | 100.00 | 75.00 | ||||||||||||
Long Call Options |
162,300 | 81.60 | 85.00 | 75.00 | ||||||||||||
Short Put Options |
402,592 | 66.42 | 89.85 | 55.00 | ||||||||||||
2012 |
||||||||||||||||
Price Swap Contracts |
36,600 | 80.20 | 80.20 | 80.20 | ||||||||||||
Collar Contracts |
||||||||||||||||
Short Call Options |
1,171,008 | 121.29 | 132.00 | 100.00 | ||||||||||||
Long Put Options |
1,190,618 | 100.32 | 105.00 | 70.00 | ||||||||||||
Long Call Options |
228,600 | 103.79 | 123.50 | 90.20 | ||||||||||||
Short Put Options |
1,311,008 | 79.34 | 85.00 | 60.00 |
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Weighted | Range | |||||||||||||||
Period and Type of Contract | Volume in Bbls | Average | High | Low | ||||||||||||
2013 |
||||||||||||||||
Price Swap Contracts |
136,500 | 84.35 | 94.74 | 77.00 | ||||||||||||
Collar Contracts |
||||||||||||||||
Short Call Options |
527,435 | 113.38 | 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.
We had the following open financial basis swap contracts for gas at September 30, 2011 (unaudited):
Volume in MMbtu | Reference Price | Period | Spread ($ per MMbtu) | |||||||||
600,000 | Houston Ship Channel |
Oct 11 Dec 11 | (0.2000) | |||||||||
600,000 | Houston Ship Channel |
Oct 11 Dec 11 | (0.1600) | |||||||||
230,000 | Houston Ship Channel |
Oct 11 Dec 11 | (0.0850) | |||||||||
690,000 | Houston Ship Channel |
Oct 11 Dec 11 | (0.1550) | |||||||||
1,830,000 | Houston Ship Channel |
Jan 12 Dec 12 | (0.1575) | |||||||||
920,000 | Houston Ship Channel |
Oct 11 Dec 11 | (0.1150) | |||||||||
3,660,000 | Houston Ship Channel |
Jan 12 Dec 12 | (0.1400) |
We had the following open financial basis swap contract for oil at September 30, 2011 (unaudited):
Volume in BBL | Reference Price | Period | Spread ($ per MMbtu) | |||||||||
46,000 | Argus Louisiana Light Sweet Crude |
Oct 11 Dec 11 | 19.40 |
We had the following open interest rate swap contracts at September 30, 2011 (unaudited):
Interest Rate Swaps
Term | Principal Amount | Interest Rate (1) | ||||||
(dollars in thousands) | ||||||||
Floating to Fixed Rate Swaps: |
||||||||
October 2011 August 2012
|
$ | 50,000 | 4.95 | % | ||||
October 2011 October 2011
|
$ | 25,000 | 3.21 | % |
(1) | The floating rate is the three-month LIBOR rate. |
16
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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 |
445 | |||
Liabilities assumed with acquired producing properties |
2,807 | |||
Liabilities settled |
(702 | ) | ||
Accretion expense |
1,430 | |||
Balance, September 30, 2011 |
46,693 | |||
Less: Current portion |
3,418 | |||
$ | 43,275 | |||
8. LONG-TERM DEBT AND NOTES PAYABLE TO FOUNDER
Long-term debt consists of the following:
September 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 September 30, 2011, the borrowing base
under the facility was $260 million. As of November 7, 2011, the borrowing base was increased to $325 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 2.615% as of September 30, 2011
and 2.875% as of December 31, 2010. |
$ | 173,790 | $ | 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 $1.8
million and $2.0 million at September 30,
2011 and December 31, 2010, respectively. |
298,181 | 297,986 | ||||||
Total long-term debt |
$ | 471,971 | $ | 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.
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 September 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 $20.6 million and $19.7 million at September 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 $897,000 and
$890,000 for the nine months ended September 30, 2011 and 2010,
respectively, and $297,000 and
$300,000 for the three months ended September
30, 2011 and 2010, respectively. Such amounts have been added to the balance of the notes.
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9. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
The following provides the detail of accounts payable and accrued liabilities:
September 30, | December 31, | |||||||
2011 | 2010 | |||||||
(unaudited) | ||||||||
(dollars in thousands) | ||||||||
Capital expenditures |
$ | 26,111 | $ | 22,743 | ||||
Revenues and royalties payable |
4,163 | 5,962 | ||||||
Operating expenses/taxes |
30,070 | 18,220 | ||||||
Compensation |
2,431 | 2,591 | ||||||
Liability related to drilling rig |
| 9,785 | ||||||
Other |
2,313 | 1,775 | ||||||
Total accrued liabilities |
65,088 | 61,076 | ||||||
Accounts payable |
14,230 | 26,179 | ||||||
Accounts payable and accrued liabilities |
$ | 79,318 | $ | 87,255 | ||||
The following provides the detail of other long-term liabilities:
September 30, | December 31, | |||||||
2011 | 2010 | |||||||
(unaudited) | ||||||||
(dollars in thousands) | ||||||||
Acquisition obligation |
$ | 435 | $ | 411 | ||||
Remediation liability |
978 | 943 | ||||||
Other |
3,639 | 5,886 | ||||||
Total other long-term liabilities |
$ | 5,052 | $ | 7,240 | ||||
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. Discovery is ongoing and the case is set
for trial on April 24, 2012. 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 September 30, 2011.
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 the
deferred purchase price for oil and gas properties in two purchase and sales agreements dated
December 23, 2008. A temporary restraining order
(TRO) was entered against us on May 24, 2011. At a
July 7, 2011 hearing on the temporary injunction, the court recommended that the parties enter into an agreed
temporary injunction regarding
payment of disputed amounts into the
registry of the court.
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The parties 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 currently set for hearing on November 17, 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 September 30, 2011.
Environmental claims: Management has established a liability for soil contamination in
Florida of $978,000 at September 30, 2011 and $943,000 at 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 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 September 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 $5.9 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 in the second quarter of 2011.
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 natural gas properties. We mitigate a portion of this
vulnerability by entering into oil and natural gas price derivative contracts. See Note 6.
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).
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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.
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 September 30, 2011,
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 South Louisiana, East Texas,
Oklahoma, the Deep Bossier resource play of East Texas and the 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.
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.
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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% at the time of the acquisition. 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% at the time of the
acquisition. 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.
We expect oil and natural gas prices 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. government 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. government 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 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
September 30, 2011, we have hedged approximately 69% of our forecasted production from proved
developed reserves through 2016 at minimum average annual prices ranging from $5.50 per MMBtu to
$6.35 per MMBtu and $82.62 per Bbl to $99.72 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
South Louisiana
We have drilled nine wells at Weeks Island, and executed several recompletions in
Weeks Island and other South Louisiana fields, in 2011. Production was approximately 1,880 BOE per
day (net to our interest) for the third quarter of 2011. We expect to continually utilize one drilling rig and one
workover rig in this field through at least mid-2012.
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Eagle Ford Shale
We are participating with
Murphy Oil Corporation (Murphy), the operator, in a five
year program that began in 2011
in which we expect to drill at least 120 wells targeting the Eagle Ford Shale in Karnes
County, Texas. We currently have working interests in 21 wells in the Eagle Ford Shale, and Murphy has dedicated
two drilling rigs, a fracturing team, and a coil tubing unit to the area for the next two years.
We produced approximately 1,000 BOE per day (net to our interest) during September 2011.
Drilling costs are trending lower with additional personnel and equipment committed to the
area. Lease operating costs, which had been negatively impacted by the use of temporary
infrastructure and equipment, are also trending lower as these are upgraded to permanent
facilities.
Deep Bossier
Our Hilltop field continues to produce a significant portion of our gas sales, principally
from the Deep Bossier formation, at approximately 55 MMcf per day (net to our interest) for the third
quarter of 2011. We continue to drill and recomplete in this field, in which our principal
operating partner is EnCana Corporation, and to develop, test, and evaluate formations other than
the Deep Bossier, such as the Buda, Knowles, and Austin Chalk. We expect to spend a total in the
range of $40-45 million for development in this field in 2011. Capital expenditures for Deep Bossier-directed drilling will
be lower in 2012, due to a shift in capital spending to more liquids-rich opportunities.
East Texas
We have recently focused our efforts in the East Texas area on the Cold Springs field, with
several successful recompletions in previously untested Wilcox formation sands. There are
approximately 35 distinct pay zones at Cold Springs and our nearby Urbana field. These
recompletions are relatively inexpensive and typically produce a high rate of return, in part
reflecting the high liquids content in most zones. We have identified an extension of Cold
Springs, the West Cold Springs field, and have continued field development and expansion.
We also completed one new gas and condensate well in the Urbana field. We expect to continue
development of the Cold Springs, West Cold Springs, and Urbana fields in 2012.
Results of Operations: Three Months Ended September 30, 2011 v. Three Months Ended September 30,
2010
Three Months Ended September 30, | Increase | |||||||||||||||
2011 | 2010 | (Decrease) | % Change | |||||||||||||
($ in thousands, except average sales price and unit costs) | ||||||||||||||||
Summary Operating Information: |
||||||||||||||||
Net Production: |
||||||||||||||||
Natural gas (MMcf) |
8,156 | 6,265 | 1,891 | 30 | % | |||||||||||
Oil (MBbls) |
414 | 311 | 103 | 33 | % | |||||||||||
Natural gas liquids (MBbls) |
47 | 48 | (1 | ) | (2 | )% | ||||||||||
Total natural gas equivalent (MMcfe) |
10,921 | 8,419 | 2,502 | 30 | % | |||||||||||
Average daily gas production (MMcfe per day) |
118.7 | 91.5 | 27.2 | 30 | % | |||||||||||
Average Sales Price: |
||||||||||||||||
Natural gas (per Mcf) realized |
$ | 4.94 | $ | 5.45 | $ | (0.51 | ) | (9 | )% | |||||||
Natural gas (per Mcf) unhedged |
4.20 | 4.33 | (0.13 | ) | (3 | )% | ||||||||||
Oil (per Bbl) realized |
102.08 | 76.45 | 25.63 | 34 | % | |||||||||||
Oil (per Bbl) unhedged |
101.69 | 75.57 | 26.12 | 35 | % | |||||||||||
Natural gas liquids (per Bbl) realized (1) |
63.43 | 41.89 | 21.54 | 51 | % | |||||||||||
Combined (per Mcfe) realized |
7.83 | 7.12 | .71 | 10 | % | |||||||||||
Hedging Activities: |
||||||||||||||||
Realized natural gas revenue gain |
$ | 5,986 | $ | 7,003 | $ | (1,017 | ) | (15 | )% | |||||||
Realized oil revenue gain |
162 | 273 | (111 | ) | (41 | )% | ||||||||||
Summary Financial Information |
||||||||||||||||
Revenues |
||||||||||||||||
Natural gas |
$ | 40,250 | $ | 34,153 | $ | 6,097 | 18 | % | ||||||||
Oil |
42,213 | 23,794 | 18,419 | 77 | % | |||||||||||
Natural gas liquids |
3,000 | 2,001 | 999 | 50 | % | |||||||||||
Other revenues |
600 | 380 | 220 | 58 | % | |||||||||||
Unrealized gain oil and natural gas
derivative contracts |
30,101 | 2,712 | 27,389 | 1,010 | % | |||||||||||
116,164 | 63,040 | 53,124 | 84 | % | ||||||||||||
Expenses |
||||||||||||||||
Lease and plant operating expense |
16,267 | 12,149 | 4,118 | 34 | % | |||||||||||
Production and ad valorem taxes |
5,728 | 4,015 | 1,713 | 43 | % | |||||||||||
Workover expense |
4,413 | 1,569 | 2,844 | 181 | % | |||||||||||
Exploration expense |
3,889 | 4,342 | (453 | ) | (10 | )% | ||||||||||
Depreciation, depletion, and amortization |
23,756 | 17,853 | 5,903 | 33 | % | |||||||||||
Impairment expense |
5,743 | 416 | 5,327 | 1,281 | % | |||||||||||
Accretion expense |
484 | 517 | (33 | ) | (6 | )% | ||||||||||
Loss on sale of assets |
| 87 | (87 | ) | NA | |||||||||||
General and administrative expenses |
9,659 | 6,020 | 3,639 | 60 | % | |||||||||||
Interest expense, net |
6,758 | 5,940 | 818 | 14 | % | |||||||||||
Provision for state income taxes |
75 | 2 | 73 | 3,650 | % | |||||||||||
Net income |
$ | 39,392 | $ | 10,130 | $ | 29,262 | 289 | % | ||||||||
Average Unit Costs per Mcfe: |
||||||||||||||||
Lease and plant operating expense |
$ | 1.49 | $ | 1.44 | $ | 0.05 | 3 | % | ||||||||
Production and ad valorem taxes |
0.52 | 0.48 | 0.04 | 8 | % | |||||||||||
Workover expense |
0.40 | 0.19 | 0.21 | 111 | % | |||||||||||
Exploration expense |
0.36 | 0.52 | (0.16 | ) | (31 | )% | ||||||||||
Depreciation, depletion and amortization |
2.18 | 2.12 | 0.06 | 3 | % | |||||||||||
General and administrative expenses |
0.88 | 0.72 | 0.16 | 22 | % |
(1) | We do not utilize hedges for natural gas liquids. |
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Revenues
Natural gas revenues for the three months ended September 30, 2011 were $40.3 million,
compared to $34.2 million for the same period in 2010, representing a $6.1 million or 18% increase.
The increase in revenue was attributable to increased production volumes partially offset by lower
realized prices during the three months ended September 30, 2011. The increase in production
volumes of 1.9 Bcf resulted in increased revenue of approximately $10.3 million primarily related
to new production in the Deep Bossier play (increased 2.5 Bcf) and production from the Sydson and TODD acquisitions made
in the second quarter of 2011 (0.1 Bcf). These increases were offset by decreases in other fields,
primarily South Louisiana properties, which decreased 0.4 Bcf. The decrease in realized prices
(including hedge activity) from $5.45 per Mcf in the third quarter of 2010 to $4.94 per Mcf in the
third quarter of 2011 resulted in decreased revenue of approximately $4.2 million. The price of natural gas
before hedging decreased from $4.33 per Mcf in the third quarter of 2010 to $4.20 per Mcf in the
third quarter of 2011.
Oil revenues for the three months ended September 30, 2011 increased $18.4 million, or 77%, to
$42.2 million from $23.8 million for the three months ended September 30, 2010. The increase in
revenue was due to higher production volumes and higher realized prices. Oil production for the
third quarter of 2011 increased to 414 MBbls from 311 MBbls for the same period in 2010, an
increase of 33%. The increase is primarily related to new production from our Eagle Ford Shale area
(71 MBbls) and to the Sydson and TODD acquisitions (19 MBbls, which excludes 9 MBbls included in the
Eagle Ford Shale total mentioned
above). During the three months ended September 30, 2011, our average realized oil price
(including hedge activity) increased from $76.45 per Bbl in the third quarter of 2010 to $102.08
per Bbl in the comparable period of 2011. The price of oil before hedging increased from $75.57 per
Bbl to $101.69 per Bbl for the comparative periods.
Natural gas liquids revenues increased during the third quarter of 2011 to $3.0 million from
$2.0 million for the third quarter of 2010. The increase was due to increased prices from $41.89 to
$63.43 for the three months ended September 30, 2010 and 2011, respectively.
Other revenues were
$0.6 million during the three months ended September 30, 2011 as compared to
$0.4 million during the three months ended September 30, 2010. The increase is primarily the result of
an increase in income from rental of our drilling rig.
Unrealized gain
oil and natural gas derivative contracts was $30.1 million
during the three months ended September 30, 2011 as compared to $2.7 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.
In general, the majority of the gains were related to the decline in oil prices during the current
quarter, which increased the unrealized value of our open derivative contracts.
Expenses
Lease and plant operating expense increased $4.1 million in the third quarter of 2011 as
compared to the third quarter of 2010, due to increased gas marketing service fees ($0.8 million),
salt water disposal and transportation expenses ($0.7 million), and general operating expenditures
($2.2 million), primarily related to additional wells in production.
On a unit basis, lease and plant operating expense increased from $1.44 per Mcfe to $1.49 per Mcfe
for the three months ended September 30, 2010 and 2011, respectively.
Production and ad valorem taxes increased $1.7 million, or 43%, to $5.7 million for the third
quarter of 2011, as compared to $4.0 million for the third quarter of 2010. Ad valorem taxes
increased $0.4 million, due to increases in asset values. The remaining increase of $1.3 million
is attributable to production taxes, which increased 36%, following an increase in our revenue from
products of 43%. 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 and
Texas, where the majority of our oil and gas is produced. Oil as a percentage of product revenues
increased from 40% to 49% in the third quarter of 2011 as compared to the same period in 2010.
Workover expense increased from the third quarter of 2010 as compared to the third quarter of
2011, from $1.6 million to $4.4 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 decreased
slightly from $4.3 million for the third quarter of 2010 to $3.9 million for the third quarter of
2011.
Depreciation, depletion and amortization increased $5.9 million to $23.8 million for the third
quarter of 2011 as compared to an expense of $17.9 million for the third quarter of 2010. On a per
unit basis, this expense increased from $2.12 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 $0.4 million in the third quarter of 2010 to $5.7 million in
the third quarter of 2011. This expense varies with the results of drilling, as well as
with price declines and other factors 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 $0.5 million for the third quarter
of 2011 and 2010, respectively.
General and administrative expenses increased $3.7 million for the three months ended
September 30, 2011 to $9.7 million from $6.0 million for the three months ended September 30, 2010.
The increase in general and administrative expenses is principally the result of increased salary
and benefits expenses of $1.6 million, due to additional personnel; consulting services increased $1.4
million, primarily for fees associated with litigation, and other
consulting services, including risk management and public agency fees. In addition, office
expenditures increased $0.5 million, primarily due to a new office lease and annual information
system license renewals. On a per unit basis, general and administrative expenses increased from
$0.72 to $0.88 per Mcfe.
Interest expense, net increased $0.8 million for the three months ended September 30, 2011 to
$6.7 million from $5.9 million for the three months ended September 30, 2010, primarily due to $7.5
million in interest on our 9 5/8% senior notes issued in October 2010, and increased commitment
fees and other interest of $0.4 million. This increase is partially offset by increased interest
rate hedge gains of $3.8 million, due partially to a hedge gain of $0.9 million which resulted from
the termination of one interest rate swap contract, and to a decline in interest rates. Interest on bank debt decreased $3.0 million
due to a decrease in the amount outstanding under our credit facility, to the retirement of our $40
million subordinated debt in October 2010, and to a decline in the floating interest rate under the
credit facility. Amortization of deferred loan costs also decreased $0.3 million due to the
extension of the maturity date of our credit facility which was amended in May 2011.
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Results of Operations: Nine Months Ended September 30, 2011 v. Nine Months Ended September 30, 2010
Nine Months Ended September 30, | Increase | |||||||||||||||
2011 | 2010 | (Decrease) | % Change | |||||||||||||
($ in thousands, except average sales price and unit costs) | ||||||||||||||||
Summary Operating Information: |
||||||||||||||||
Net Production: |
||||||||||||||||
Natural gas (MMcf) |
23,501 | 16,936 | 6,565 | 39 | % | |||||||||||
Oil (MBbls) |
1,138 | 646 | 492 | 76 | % | |||||||||||
Natural gas liquids (MBbls) |
155 | 87 | 68 | 78 | % | |||||||||||
Total natural gas equivalent (MMcfe) |
31,259 | 21,338 | 9,921 | 46 | % | |||||||||||
Average daily gas production (MMcfe per day) |
114.5 | 78.2 | 36.3 | 46 | % | |||||||||||
Average Sales Price: |
||||||||||||||||
Natural gas (per Mcf) realized |
$ | 4.87 | $ | 5.44 | $ | (0.57 | ) | (10 | )% | |||||||
Natural gas (per Mcf) unhedged |
4.15 | 4.48 | (0.33 | ) | (7 | )% | ||||||||||
Oil (per Bbl) realized |
99.93 | 76.71 | 23.22 | 30 | % | |||||||||||
Oil (per Bbl) unhedged |
103.23 | 75.87 | 27.36 | 36 | % | |||||||||||
Natural gas liquids (per Bbl) realized (1) |
57.38 | 45.24 | 12.14 | 27 | % | |||||||||||
Combined (per Mcfe) realized |
7.58 | 6.83 | 0.75 | 11 | % | |||||||||||
Hedging Activities: |
||||||||||||||||
Realized natural gas revenue gain |
$ | 16,897 | $ | 16,204 | $ | 693 | 4 | % | ||||||||
Realized oil revenue gain (loss) |
(3,756 | ) | 549 | (4,305 | ) | (784 | )% | |||||||||
Summary Financial Information |
||||||||||||||||
Revenues |
||||||||||||||||
Natural gas |
$ | 114,362 | $ | 92,088 | $ | 22,274 | 24 | % | ||||||||
Oil |
113,702 | 49,593 | 64,109 | 129 | % | |||||||||||
Natural gas liquids |
8,900 | 3,944 | 4,956 | 126 | % | |||||||||||
Other revenues |
1,366 | 787 | 579 | 74 | % | |||||||||||
Unrealized gain oil and natural gas
derivative contracts |
25,292 | 25,620 | (328 | ) | (1 | )% | ||||||||||
263,622 | 172,032 | 91,590 | 53 | % | ||||||||||||
Expenses |
||||||||||||||||
Lease and plant operating expense |
44,639 | 29,581 | 15,058 | 51 | % | |||||||||||
Production and ad valorem taxes |
15,198 | 8,413 | 6,785 | 81 | % | |||||||||||
Workover expense |
8,391 | 4,858 | 3,533 | 73 | % | |||||||||||
Exploration expense |
12,310 | 8,914 | 3,396 | 38 | % | |||||||||||
Depreciation, depletion, and amortization |
66,187 | 39,975 | 26,212 | 66 | % | |||||||||||
Impairment expense |
16,498 | 2,509 | 13,989 | 558 | % | |||||||||||
Accretion expense |
1,430 | 932 | 498 | 53 | % | |||||||||||
Loss on sale of assets |
| 87 | (87 | ) | NA | |||||||||||
General and administrative expenses |
24,251 | 12,922 | 11,329 | 88 | % | |||||||||||
Interest expense, net |
23,067 | 14,664 | 8,403 | 57 | % | |||||||||||
(Gain) on contract settlement |
(1,285 | ) | | (1,285 | ) | NA | ||||||||||
Provision for state income taxes |
150 | 2 | 148 | 7,400 | % | |||||||||||
Net income |
$ | 52,786 | $ | 49,175 | $ | 3,611 | 7 | % | ||||||||
Average Unit Costs per Mcfe: |
||||||||||||||||
Lease and plant operating expense |
$ | 1.43 | $ | 1.39 | $ | 0.04 | 3 | % | ||||||||
Production and ad valorem taxes |
0.49 | 0.39 | 0.10 | 26 | % | |||||||||||
Workover expense |
0.27 | 0.23 | 0.04 | 17 | % | |||||||||||
Exploration expense |
0.39 | 0.42 | (0.03 | ) | (7 | )% | ||||||||||
Depreciation, depletion and amortization |
2.12 | 1.87 | 0.25 | 13 | % | |||||||||||
General and administrative expenses |
0.78 | 0.61 | 0.17 | 28 | % |
(1) | We do not utilize hedges for natural gas liquids. |
25
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Revenues
Natural gas revenues for the nine months ended September 30, 2011 were $114.4 million,
compared to $92.1 million for the same period in 2010, representing a $22.3 million or 24%
increase. The increase in revenue was attributable to increased production volumes partially offset
by lower realized prices during the nine months ended September 30, 2011. The increase in
production volumes of 6.6 Bcf resulted in increased revenue of approximately $35.7 million
primarily related to new production in the Deep Bossier (5.4 Bcf increase) and to the full-year
effect of the Meridian acquisition in the second quarter of 2010 (1.9 Bcf increase). The decrease
in realized prices (including hedge activity) from $5.44 per Mcf in the first nine months of 2010
to $4.87 per Mcf in the first nine months of 2011 resulted in decreased revenue of approximately
$13.4 million. The price of gas before hedging decreased from $4.48 per Mcf in the first nine
months of 2010 to $4.15 per Mcf in the first nine months of 2011.
Oil revenues for the nine months ended September 30, 2011 increased $64.1 million, or 129%, to
$113.7 million from $49.6 million for the nine months ended September 30, 2010. The increase in
revenue was due to higher production volumes and higher realized prices. Oil production for the
first nine months of 2011 increased to 1,138 MBbls from 646 MBbls for the same period in 2010, an
increase of 76%. The increase is primarily related to the full-year effect of production from the
Meridian acquisition in May 2010 (435 MBbls higher than the first nine months of 2010) and to the
Sydson and TODD acquisitions in the second quarter of 2011, which increased oil production 46
MBbls. Of these increases, approximately 140 MBbls were attributable to new production in the
Eagle Ford Shale area. Our average realized oil price (including hedge activity) increased from
$76.71 per Bbl in the first nine months of 2010 to $99.93 per Bbl in the first nine months of 2011.
The price of oil before hedging increased from $75.87 per Bbl to $103.23 per Bbl for the same
comparative periods.
Natural gas liquids revenues increased during the first nine months of 2011 to $8.9 million
from $3.9 million for the first nine months of 2010. The increase was due to an increase in volume
sold, from 87 MBbls to 155 MBbls, and increased prices, from $45.24 to $57.38 per Bbl for the nine
months ended September 30, 2010 and 2011, respectively. The increased production is primarily
related to the full-year effect of our Meridian acquisition in May 2010.
Other revenues were $1.4 million during the nine months ended September 30, 2011 as compared
to $0.8 million during the nine months ended September 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 oil and natural gas derivative contracts was $25.3 million
during the nine months ended September 30, 2011 as compared to $25.6 million during the
same period in 2010. Fluctuations from period to period are 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 $15.1 million in the first nine months of 2011 as
compared to the first nine months of 2010. There were increases in gas marketing service fees
($3.7 million), salt water disposal and transportation expense ($1.1 million), labor and contract
services ($1.4 million), compression ($0.8 million), fuel, power and water ($0.8 million), and
general operating expenditures ($7.3 million), primarily related to the full year effect of the
Meridian acquisition in May 2010, as well as new wells coming online in 2011. On a unit basis,
lease and plant operating expense increased from $1.39 per Mcfe to $1.43 per Mcfe for the nine
months ended September 30, 2010 and 2011, respectively.
Production and ad valorem taxes increased $6.8 million, or 81%, to $15.2 million for the first
nine months of 2011, as compared to $8.4 million for the first nine months 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 $5.5 million is attributable to production
taxes, which increased 75%, following an increase in our revenue from products of 63%. 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 and Texas, where the majority
of our oil is produced. Oil as a percentage of product revenues increased from 34% to 48% in the
first nine months of 2011 as compared to 2010.
Workover expense increased from the first nine months of 2010 as compared to the first nine
months of 2011, from $4.9 million to $8.4 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 $3.4
million for the first nine months of 2011 to $12.3 million from $8.9 million
26
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for the first nine months of 2010. The increase is primarily due to an increase in dry hole
expense of $5.9 million, offset by a decrease in geological expense of $3.7 million. Dry hole
costs in the first nine months of 2011 included four wells with costs ranging from $1 million to $2
million each. Geological expenses decreased in the first nine months of 2011 as compared to the
same period in 2010 due to the timing of purchases of seismic data.
Depreciation, depletion and amortization increased $26.2 million to $66.2 million for the
first nine months of 2011 as compared to an expense of $40.0 million for the first nine months of
2010. On a per unit basis, this expense increased from $1.87 to $2.12 per Mcfe. The rate is a
function of capitalized costs of proved properties, reserves and production by field.
Impairment expense increased from $2.5 million in the first nine months of 2010 to $16.5
million in the first nine months of 2011. This expense varies with the results of
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 $1.4 million and $0.9 million for the first nine
months of 2011 and 2010, respectively. The increase was due to the acquisition of Meridian.
General and administrative expenses increased $11.4 million for the nine months ended
September 30, 2011 to $24.3 million from $12.9 million for the nine months ended September 30,
2010. The increase in general and administrative expenses is principally the result of increased
salary and benefits expenses of $5.6 million, due to additional personnel; consulting services increased
$4.1 million, primarily for fees associated with litigation, and other
consulting services, including risk management services. In addition, office expenditures increased
$1.5 primarily due to the assumption of the Meridian office space and a new office lease and annual
information system license renewals. On a unit basis, general and administrative expense increased
from $0.61 to $0.78 per Mcfe.
Interest expense, net increased $8.4 million for the nine months ended September 30, 2011 to
$23.1 million from $14.7 million for the nine months ended September 30, 2010, primarily due to $22
million in interest on our 9 5/8% senior notes issued in October 2010, increased amortization of
deferred loan costs of $0.7 million, and an increase of $0.7 million in commitment fees and other
interest. These increases are partially offset by increased interest rate hedge gains of $7.9
million, primarily due to hedge gains of $3.7 million recorded in the first nine months of 2011
related to interest hedge contract modifications and termination of one interest rate swap
contract. In addition, interest on bank debt decreased $7.1 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 we 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.
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 $133 million has been expended or accrued through September
30, 2011. Approximately 83% of our 2011 capital budget is allocated to our properties in Deep
Bossier, East Texas, the Eagle Ford Shale, 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 the remainder of 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
27
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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 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. 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 September 30, 2011, the credit facility was subject to a
$260 million borrowing base limit, and we had $173.8 million outstanding under the credit facility.
Our restricted subsidiaries are guarantors of the credit facility.
In November 2011, the borrowing base was increased to $325 million. The borrowing base is
redetermined each May 1 and November 1. As of November 14, 2011, the
available unused portion of the borrowing base is $136.2 million.
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 September 30, 2011 under the credit facility was 2.615%, 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
September 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 $115.4 million during the nine months ended September
30, 2011 as compared to $37.2 million during the comparable period in 2010. The $78.2 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 $48 million in earnings and a related positive impact on cash flow. Augmenting
this were changes in our working capital accounts, which used $0.7 million of cash flows as
compared to having used $30.9 million of cash in 2010. This reversal resulted in a total increase
of $30.2 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 $214.6 million during the nine months ended September 30,
2011 as compared to cash used in investing of $167.7 million during the comparable period of 2010.
A decrease in cash used in acquisition activities of $34.8 million was due to the $101.4 million
invested in the Meridian acquisition in the second quarter of 2010. Acquisitions in the first nine
months of 2011 were $66.6 million, primarily for the additional interests 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 $81.7
million as compared to the prior year period, primarily related to development activities in our
Deep Bossier, Eagle Ford Shale, South Louisiana, and East Texas area properties.
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Table of Contents
Cash flow provided by financing activities
Financing activities provided cash of $98.9 million during the nine months ended September 30,
2011 as compared to cash provided by financing of $136.3 million during the nine months ended
September 30, 2010. The decrease is due primarily to the capital infusion of $50 million in the
first half of 2010 provided by our private equity partner, which partially funded the Meridian
acquisition. Cash from financing activities in the first nine months of 2011 included drawdowns on
our credit facility of $101 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 September 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 September 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 September 30, 2011.
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
ITEM 3. Defaults Upon Senior Securities
None.
ITEM 4. (Removed and Reserved)
ITEM 5. Other Information
None.
29
Table of Contents
ITEM 6. Exhibits
10.1 | Amendment
No. 4 to Sixth Amended and Restated Credit Agreement by and among Alta
Mesa Holdings, LP, Wells Fargo Bank, N.A., as administrative agent,
and the lenders party thereto from time to time, dated as of November 7,
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. |
30
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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 | ||||||
November 14, 2011
|
By: | /s/ Harlan H. Chappelle
|
||||
Harlan H. Chappelle | ||||||
President and Chief Executive Officer | ||||||
November 14, 2011
|
By: | /s/ Michael A. McCabe
|
||||
Michael A. McCabe | ||||||
Vice President and Chief Financial Officer |
31