Alta Mesa 10-Q 2013 Q3 Quarterly report

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)

xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended: September 30, 2013 

OR

¨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	20-3565150
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
15021 Katy Freeway, Suite 400, Houston, Texas	77094
(Address of principal executive offices)	(Zip Code)

Registrant’s 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  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.)    Yes  x    No   ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one)

Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	x  (Do not check if a smaller reporting company)	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  ¨    No  x

Table of Contents

	Page Number
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements	3
Consolidated Balance Sheets as of September 30, 2013 (unaudited) and December 31, 2012	3
Consolidated Statements of Operations  (unaudited) for the Three and Nine Months Ended September 30, 2013 and 2012	4
Consolidated Statements of Cash Flows (unaudited) for the Nine Months Ended September 30, 2013 and 2012	5
Notes to Consolidated Financial Statements (unaudited)	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
Item 3. Quantitative and Qualitative Disclosures about Market Risk	28
Item 4. Controls and Procedures	28
PART II — OTHER INFORMATION
Item 1. Legal Proceedings	28
Item 1A. Risk Factors	28
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	28
Item 3. Defaults Upon Senior Securities	28
Item 4. Mine Safety Disclosures	28
Item 5. Other Information	29
Item 6. Exhibits	30
Signatures	31

2

PART I — FINANCIAL INFORMATION

ITEM  1. Financial Statements

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)

	September 30,		December 31,
	2013		2012
	(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	6,865	$	5,786
Restricted cash		—		2,305
Accounts receivable, net		43,025		40,715
Other receivables		1,282		4,415
Prepaid expenses and other current assets		3,309		4,501
Derivative financial instruments		10,256		21,360
TOTAL CURRENT ASSETS		64,737		79,082
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net		746,454		639,466
Other property and equipment, net		8,724		16,031
TOTAL PROPERTY AND EQUIPMENT, NET		755,178		655,497
OTHER ASSETS
Investment in Partnership — cost		9,000		9,000
Deferred financing costs, net		11,661		13,685
Derivative financial instruments		6,915		14,066
Advances to operators		3,926		9,416
Deposits and other assets		1,804		1,686
TOTAL OTHER ASSETS		33,306		47,853
TOTAL ASSETS	$	853,221	$	782,432
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	101,663	$	112,684
Current portion, asset retirement obligations		2,519		64
Derivative financial instruments		2,241		91
TOTAL CURRENT LIABILITIES		106,423		112,839
LONG-TERM LIABILITIES
Asset retirement obligations, net of current portion		47,855		48,529
Long-term debt		703,741		601,858
Notes payable to founder		23,027		22,123
Other long-term liabilities		2,398		3,451
TOTAL LONG-TERM LIABILITIES		777,021		675,961
TOTAL LIABILITIES		883,444		788,800
COMMITMENTS AND CONTINGENCIES (NOTE 9)
PARTNERS’ CAPITAL (DEFICIT)		(30,223)		(6,368)
TOTAL LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)	$	853,221	$	782,432

See notes to consolidated financial statements.

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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(dollars in thousands)

(unaudited)

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013			2012
REVENUES
Oil	$	76,938	$	57,285	$	214,824	$		160,069
Natural gas		20,737		26,758		68,883			78,638
Natural gas liquids		2,664		2,877		7,723			10,414
Other revenue (loss)		(48)		2,568		1,110			3,952
		100,291		89,488		292,540			253,073
Unrealized loss — oil and natural gas derivative contracts		(21,455)		(37,855)		(20,405)			(19,944)
TOTAL REVENUES		78,836		51,633		272,135			233,129
EXPENSES
Lease and plant operating expense		18,031		17,719		51,681			50,833
Production and ad valorem taxes		8,130		7,232		21,326			19,315
Workover expense		3,428		4,318		12,013			8,254
Exploration expense		13,508		9,480		22,374			13,543
Depreciation, depletion, and amortization expense		30,667		27,147		83,547			76,161
Impairment expense		2,072		46,472		28,618			50,934
Accretion expense		460		458		1,352			1,339
Loss on sale of assets		1,077		—		2,267			—
General and administrative expense		13,378		9,812		32,139			30,195
TOTAL EXPENSES		90,751		122,638		255,317			250,574
INCOME (LOSS) FROM OPERATIONS		(11,915)		(71,005)		16,818			(17,445)
OTHER INCOME (EXPENSE)
Interest expense		(13,845)		(9,922)		(40,794)			(29,510)
Interest income		23		30		121			70
Litigation settlement		—		—		—			1,250
TOTAL OTHER INCOME (EXPENSE)		(13,822)		(9,892)		(40,673)			(28,190)
LOSS BEFORE STATE INCOME TAXES		(25,737)		(80,897)		(23,855)			(45,635)
PROVISION FOR STATE INCOME TAXES		—		—		—			—
NET LOSS	$	(25,737)	$	(80,897)	$	(23,855)		$	(45,635)

See notes to consolidated financial statements.

4

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)

(unaudited)

	Nine Months Ended September 30,
	2013		2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(23,855)	$	(45,635)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, and amortization expense		83,547		76,161
Impairment expense		28,618		50,934
Accretion expense		1,352		1,339
Amortization of loan costs		2,121		1,716
Amortization of debt discount		383		195
Dry hole expense		13,700		6,010
Expired leases		223		—
Unrealized loss on derivatives		20,405		18,644
Interest converted into debt		904		907
Loss on sale of assets		2,267		—
Changes in assets and liabilities:
Restricted cash		2,305		—
Accounts receivable		(2,310)		1,940
Other receivables		3,133		(1,350)
Prepaid expenses and other non-current assets		6,564		(3,987)
Settlement of asset retirement obligation		(1,358)		(2,737)
Accounts payable, accrued liabilities, and other long-term liabilities		9,231		13,714
NET CASH PROVIDED BY OPERATING ACTIVITIES		147,230		117,851
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property and equipment		(245,486)		(152,125)
Acquisitions		(9,469)		(20,216)
Proceeds from sale of property		7,401		—
NET CASH USED IN INVESTING ACTIVITIES		(247,554)		(172,341)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt		119,500		68,000
Repayments of long-term debt		(18,000)		(10,000)
Additions to deferred financing costs		(97)		(118)
NET CASH PROVIDED BY FINANCING ACTIVITIES		101,403		57,882
NET INCREASE IN CASH AND CASH EQUIVALENTS		1,079		3,392
CASH AND CASH EQUIVALENTS, beginning of period		5,786		2,630
CASH AND CASH EQUIVALENTS, end of period	$	6,865	$	6,022
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid during the period for interest	$	26,696	$	20,969
Cash paid during the period for state taxes	$	18	$	230
Change in asset retirement obligations	$	1,001	$	1,476
Asset retirement obligations assumed, purchased properties	$	169	$	532
Change in accruals or liabilities for capital expenditures	$	(20,686)	$	12,963

See notes to consolidated financial statements.

5

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

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, 2012,  which were filed with the Securities and Exchange Commission in our 2012 Annual Report on Form 10-K.

The consolidated financial statements included herein as of September 30, 2013, and for the three month and nine  month periods ended September 30, 2013 and 2012, 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 (i) its wholly-owned subsidiaries: Alta Mesa Acquisition Sub, LLC, Alta Mesa Eagle, LLC, Alabama Energy Resources, LLC, Alta Mesa Drilling, LLC, Alta Mesa Energy, LLC, Alta Mesa Finance Services Corp., Alta Mesa GP, LLC, AM Idaho, LLC, AMH Energy New Mexico, LLC, Virginia Oil and Gas, LLC, Alabama Energy Resources LLC, and AM Michigan LLC; (ii) its direct and indirect wholly-owned subsidiaries: Alta Mesa Services, LP, Aransas Resources, LP (and its wholly-owned subsidiary ARI Development, LLC), Brayton Management GP II, LLC, Brayton Resources II, LP, Buckeye Production Company, LP, Cairn Energy USA, LLC, FBB Anadarko, LLC, Galveston Bay Resources, LP, Louisiana Exploration & Acquisitions, LP (and its wholly-owned subsidiary Louisiana Exploration & Acquisition Partnership, LLC), Louisiana Onshore Properties LLC, Navasota Resources, Ltd., LLP, New Exploration Technologies Company, LLC, Nueces Resources, LP, Oklahoma Energy Acquisitions, LP, Petro Acquisitions, LP, Petro Operating Company, LP, Sundance Acquisition, LLC, TE TMR, LLC, Texas Energy Acquisitions, LP, The Meridian Production LLC, The Meridian Resource & Exploration LLC, The Meridian Resource LLC, TMR Drilling, LLC, TMR Equipment, LLC; and (iii) its partially-owned subsidiaries: Brayton Management GP, LLC, Brayton Resources, LP, LEADS Resources, L.L.C., and Orion Operating Company, LP.

Nature of Operations: We are engaged primarily in the acquisition, exploration, development, and production of onshore oil and natural gas properties. Our core properties are located primarily in Texas, Louisiana, and Oklahoma.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

As of September 30, 2013, our significant accounting policies are consistent with those discussed in Note 2 of the consolidated financial statements for the fiscal year ended December 31, 2012.

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.

6

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. Unproved properties 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, gain or loss on settlement of asset retirement obligations 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 following the guidance provided in 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 operations.  

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 $1,208,000 and $784,000 at September 30, 2013 and December 31, 2012, 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 month periods ended September 30, 2013 and 2012, amortization of deferred financing costs included in interest expense amounted to $712,000 and $578,000, respectively. For the nine month periods ended September 30, 2013 and 2012, amortization of deferred financing costs included in interest expense amounted to $2.1 million and $1.7 million, respectively. Deferred financing costs are listed among our long-term assets, net of accumulated amortization of $12.0 million and $9.9 million at September 30, 2013 and December 31, 2012, respectively.

Fair Value of 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 notes

7

payable to our founder is not practicable to determine. We have estimated the fair value of our $450 million senior notes payable at $474.8 million at September 30, 2013. See Note 4 for further information on fair values of financial instruments. See Note 7 for information on long-term debt.

Recent Accounting Pronouncements

In January 2013 we adopted ASU No. 2011-11, which increases disclosures about offsetting assets and liabilities. New disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under GAAP and International Financial Reporting Standards (IFRS) related to the offsetting of financial instruments. The additional disclosures are included in Note 5.

In February 2013, the FASB issued ASU No. 2013-04. The guidance requires an entity that is joint and severally liable to measure the obligation as the sum of the amount the entity has agreed with co-obligors to pay and any additional amount it expects to pay on behalf of one or more co-obligors. Required disclosures include a description of the nature of the arrangement, how the liability arose, the relationship with co-obligors and the terms and conditions of the arrangement. ASU No. 2013-04 is effective for annual and interim reporting periods beginning after December 15, 2013. We do not expect the adoption of this pronouncement to have a material impact on our consolidated financial statements.

I

3. PROPERTY AND EQUIPMENT

Property and equipment consists of the following:

	September 30,		December 31,
	2013		2012
		(unaudited)
		(dollars in thousands)
OIL AND NATURAL GAS PROPERTIES
Unproved properties	$	52,636	$	52,501
Accumulated impairment		(2,664)		(6,040)
Unproved properties, net		49,972		46,461
Proved oil and natural gas properties		1,381,002		1,171,798
Accumulated depreciation, depletion, amortization and impairment		(684,520)		(578,793)
Proved oil and natural gas properties, net		696,482		593,005
TOTAL OIL AND NATURAL GAS PROPERTIES, net		746,454		639,466
LAND		1,418		1,185
DRILLING RIG		—		10,500
Accumulated depreciation		—		(1,837)
TOTAL DRILLING RIG, net		—		8,663
OTHER PROPERTY AND EQUIPMENT
Office furniture and equipment, vehicles		12,700		9,657
Accumulated depreciation		(5,394)		(3,474)
OTHER PROPERTY AND EQUIPMENT, net		7,306		6,183
TOTAL PROPERTY AND EQUIPMENT, net	$	755,178	$	655,497

4. 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 reliable. 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.

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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, which is a Level 1 determination.

Oil and natural gas properties are subject to impairment testing and potential impairment write down. Oil and gas properties with a carrying amount of $50.1 million were written down to their fair value of $21.5 million, resulting in an impairment charge of $28.6 million for the  nine months ended September 30, 2013. Oil and gas properties with a carrying amount of $198.4 million were written down to their fair value of $147.5 million, resulting in an impairment charge of $50.9 million for the  nine months ended September 30, 2012. For the three months ended September 30, 2013, oil and gas properties with a carrying amount of $3.6 million were written down to their fair value of $1.5 million, resulting in an impairment charge of $2.1 million, and for the three months ended September 30, 2012, oil and gas properties with a carrying amount of $186.0 million were written down to their fair value of $139.6 million, resulting in an impairment charge of $46.4 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.

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 that utilize company-specific information for such inputs as cost and timing of plugging and abandonment of wells and facilities. We recorded $1.8 million and $2.0 million in additions and revisions to asset retirement obligations measured at fair value during the  nine months ended September 30, 2013 and 2012, respectively.

The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2013 and December 31, 2012, 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, 2013 (unaudited):
Financial Assets:
Derivative contracts for oil and natural gas		—	$	49,562		—	$	49,562
Financial Liabilities:
Derivative contracts for oil and natural gas		—	$	34,632		—	$	34,632
At December 31, 2012:
Financial Assets:
Derivative contracts for oil and natural gas		—	$	76,157		—	$	76,157
Financial Liabilities:
Derivative contracts for oil and natural gas		—	$	40,822		—	$	40,822

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 5.  

5. 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 our lenders under the credit facility described in Note 7 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, or in the case of financial basis hedging contracts, based on a designated price differential between various benchmark prices. Cash settlement occurs monthly. 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.

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We entered into an interest rate swap agreement to mitigate the risk of loss due to changes in interest rates which expired in 2012. The interest rate swap was not designated as a cash flow hedge 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 swap contract are included in interest expense. 

The following table summarizes the fair value (see Note 4 for further discussion of fair value) and classification of our derivative instruments, none of which have been designated as hedging instruments under ASC 815.  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 third and sixth columns in the table below reflect the total value of derivative assets and liabilities that were offset against related balances with the same counterparty for presentation in our consolidated balance sheets.

Fair Values of Derivative Contracts

Balance Sheet Location at

Balance Sheet Location at

September 30, 2013

September 30, 2013

Total

Total

liability

asset

Current

Long-term

portion of

Current

Long-term

portion of

asset

asset

Derivative

liability

liability

Derivative

portion of

portion of

financial

portion of

portion of

financial

Derivative

Derivative

instruments

Derivative

Derivative

instruments

financial

financial

offset against

financial

financial

offset against

instruments

instruments

assets

instruments

instruments

liabilities

(unaudited)

(dollars in thousands)

Fair value of oil and gas commodity contracts, assets

$

20,594

$

26,232

$

2,736

$

—

$

2,736

Fair value of oil and gas commodity contracts, (liabilities)

(10,338)

(19,317)

$

(29,655)

(4,977)

—

Total net assets, (liabilities) as presented on the balance sheet

$

10,256

$

6,915

$

(2,241)

$

—

Balance Sheet Location at

Balance Sheet Location at

December 31, 2012

December 31, 2012

Total

Total

liability

asset

Current

Long-term

portion of

Current

Long-term

portion of

asset

asset

Derivative

liability

liability

Derivative

portion of

portion of

financial

portion of

portion of

financial

Derivative

Derivative

instruments

Derivative

Derivative

instruments

financial

financial

offset against

financial

financial

offset against

instruments

instruments

assets

instruments

instruments

liabilities

(dollars in thousands)

Fair value of oil and gas commodity contracts, assets

$

43,074

$

33,083

$

—

$

—

$

—

Fair value of oil and gas commodity contracts, (liabilities)

(21,714)

(19,017)

$

(40,731)

(91)

—

Total net assets, (liabilities) as presented on the balance sheet

$

21,360

$

14,066

$

(91)

$

—

10

The following table summarizes the effect of our derivative instruments in the consolidated statements of operations:

Derivatives not			Three Months Ended				Nine Months Ended
designated as hedging	Location of	Classification of	September 30,				September 30,
instruments under ASC 815	Gain (Loss)	Gain (Loss)	2013		2012		2013		2012
			(unaudited)
			(dollars in thousands)
Natural gas commodity contracts	Natural gas revenues	Realized	$	4,925	$	13,501	$	19,924	$	33,130
Oil commodity contracts	Oil revenues	Realized		(4,150)		(168)		(6,374)		(958)
Interest rate contracts	Interest benefit (expense)	Realized		—		(211)		—		(1,337)
Total realized gains (losses) from
derivatives not designated as hedges			$	775	$	13,122	$	13,550	$	30,835
Natural gas commodity contracts	Unrealized gain (loss) —
	oil and natural gas
	derivative contracts	Unrealized	$	(2,707)	$	(17,865)	$	(16,091)	$	(23,746)
Oil commodity contracts	Unrealized gain (loss) —
	oil and natural gas
	derivative contracts	Unrealized		(18,748)		(19,990)		(4,314)		3,802
Total unrealized gains (losses) from oil and
natural gas commodity contracts				(21,455)		(37,855)		(20,405)		(19,944)
Interest rate contracts	Interest benefit (expense)	Unrealized		—		212		—		1,300
Total unrealized gains (losses) from
derivatives not designated as hedges			$	(21,455)	$	(37,643)	$	(20,405)	$	(18,644)

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.

11

We had the following open derivative contracts for natural gas at September 30, 2013 (unaudited):  

NATURAL GAS DERIVATIVE CONTRACTS

	Volume in	Weighted		Range
Period and Type of Contract	MMbtu	Average		High		Low
2013
Price Swap Contracts	4,219,500	$	4.31	$	7.02	$	3.30
Collar Contracts
Short Call Options	943,600		4.33		4.90		4.00
Long Put Options	300,000		6.08		6.15		6.00
Long Call Options	1,651,200		5.86		7.92		3.60
Short Put Options	3,989,600		3.17		5.00		3.00
2014
Price Swap Contracts	9,512,500		4.84		7.50		4.01
Collar Contracts
Short Call Options	4,395,000		5.63		7.92		4.75
Long Put Options	2,570,000		5.84		7.00		4.25
Short Put Options	3,543,500		3.98		5.50		3.00
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

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We had the following open derivative contracts for crude oil at September 30, 2013 (unaudited):  

OIL DERIVATIVE CONTRACTS

	Volume	Weighted		Range
Period and Type of Contract	in Bbls	Average		High		Low
2013
Price Swap Contracts	625,600	$	102.43	$	112.39	$	77.00
Collar Contracts
Short Call Options	162,564		114.49		123.90		100.00
Long Put Options	147,200		106.03		113.25		85.00
Long Call Options	28,980		105.00		127.00		92.35
Short Put Options	377,200		81.89		90.00		65.00
2014
Price Swap Contracts	1,514,925		95.00		105.48		81.00
Collar Contracts
Short Call Options	547,500		111.10		114.00		107.50
Long Put Options	762,200		92.39		95.00		85.00
Short Put Options	1,051,280		74.75		80.00		65.00
2015
Price Swap Contracts	766,500		97.60		99.30		95.73
Collar Contracts
Short Call Options	428,850		120.81		135.98		115.00
Long Put Options	1,231,850		87.15		95.00		85.00
Short Put Options	1,414,350		68.00		75.00		60.00
2016
Price Swap Contracts	292,800		94.95		95.00		94.90
Collar Contracts
Short Call Options	859,700		108.07		130.00		104.00
Long Put Options	859,700		85.98		95.00		80.00
Short Put Options	859,700		65.98		75.00		60.00
2017
Collar Contracts
Short Call Options	744,950		108.14		114.00		104.25
Long Put Options	744,950		83.26		90.00		80.00
Short Put Options	744,950		63.26		70.00		60.00
2018
Collar Contracts
Short Call Options	307,400		104.49		104.75		104.25
Long Put Options	307,400		80.00		80.00		80.00
Short Put Options	307,400		60.00		60.00		60.00

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 natural gas at September 30, 2013 (unaudited):  

				Spread
Volume in MMbtu	Reference Price 1 (1)	Reference Price 2 (1)	Period	($ per MMbtu)
920,000	NYMEX Henry Hub	Houston Ship  Channel	Oct ’13 — Dec  ’13	$	0.0625

 (1)The spread in these trades limits the differential of the settlement quotation prices for NYMEX Henry Hub over the Houston Ship Channel index published in Inside FERC.  

13

We had the following open financial basis swap contracts for crude oil at September 30, 2013 (unaudited):  

				Weighted
				Average Spread
Volume in Bbl	Reference Price 1  (2)	Reference Price 2  (2)	Period	($ per Bbl)
322,000	Brent IPE	Argus Louisiana Light Sweet	Oct ’13 — Dec  ’13	$	3.09
181,000	Brent IPE	Argus Louisiana Light Sweet	Jan ’14 — Jun  ’14	$	(0.20)

 (2)The spread in the 2013 trades limits the differential of the settlement quotation prices for Brent IPE over Argus Louisiana Light Sweet crude (“LLS”); in 2014 the spread limits the differential of LLS over Brent IPE.

6. 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, 2012	$	48,593
Liabilities incurred		606
Liabilities assumed with acquired producing properties		169
Liabilities settled		(1,358)
Revisions to estimates		1,012
Accretion expense		1,352
Balance, September 30, 2013		50,374
Less: Current portion		2,519
Long term portion	$	47,855

The total revisions include $395,000 related to additions to property, plant and equipment.

7. LONG-TERM DEBT AND NOTES PAYABLE TO FOUNDER

Long-term debt and notes payable to founder consists of the following:

	September 30, 2013		December 31, 2012
	(unaudited)
	(dollars in thousands)
Credit Facility	$	256,290	$	154,790
Senior Notes		447,451		447,068
Total long-term debt	$	703,741	$	601,858
Notes payable to founder	$	23,027	$	22,123

Credit Facility. On May 13, 2010, we entered into a Sixth Amended and Restated Credit Agreement (as amended, the “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, 2013, the borrowing base under the facility was $330 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 2.75% as of September 30, 2013 and 2.33% as of December 31, 2012.

Senior Notes. On October 13, 2010, we issued senior notes due October 15, 2018 (“initial senior notes”) with a face value of $300 million, at a discount of $2.1 million. The senior notes carry a face interest rate of 9.625%, with an effective rate of 9.75%; interest is payable semi-annually each April 15th and October 15th. On October 15, 2012 we issued an additional $150 million of senior notes (“additional senior notes”) governed by the same indenture as the original issue of senior notes and carrying the same face interest rate, maturity and interest payment dates. The additional senior notes were issued at a discount of $1.5 million, and proceeds were used to reduce outstanding borrowings under the credit facility. Both the initial senior notes and the additional senior notes (together, “senior notes”) are unsecured 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 $2.5 million and $2.9 million at September 30, 2013 and December 31, 2012, respectively.

14

The senior notes contain an optional redemption provision available prior to October 15, 2013 allowing us to retire up to 35% of the principal outstanding under the senior notes at 109.625% with the proceeds of an equity offering. 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.

All of the senior notes, which were initially issued in private placements, have been exchanged for substantially identical registered senior notes. The credit facility and senior notes include covenants requiring that we maintain certain financial covenants including a current ratio, leverage ratio, and interest coverage ratio. At September 30, 2013, we were in compliance with the covenants. The terms of the credit facility also restrict our ability to make distributions and investments. 

Notes Payable to Founder. We also have notes payable to our founder that bear simple interest at 10% with a balance of $23.0 million and $22.1 million at September 30, 2013 and December 31, 2012, respectively. The notes mature December 31, 2018. Interest and principal are payable at maturity. These founder notes are subordinate to all debt. Interest on the notes payable to our founder amounted to $904,000 and $907,000 for the nine months ended September 30, 2013 and 2012, respectively, and $305,000 and $304,000 for the three months ended September 30, 2013 and 2012, respectively. Such amounts have been added to the balance of the founder notes.

8. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

The following provides the detail of accounts payable and accrued liabilities:

	September 30,			December 31,
	2013			2012
		(unaudited)
	(dollars in thousands)
Capital expenditures	$	14,091	$	37,738
Revenues and royalties payable		10,358		10,788
Operating expenses/taxes		16,046		14,842
Interest		19,936		9,045
Compensation		13,227		5,978
Other		4,315		6,223
Total accrued liabilities		77,973		84,614
Accounts payable		23,690		28,070
Accounts payable and accrued liabilities	$	101,663	$	112,684

9. COMMITMENTS AND CONTINGENCIES

Contingencies

Environmental claims: Management has established a liability for soil contamination in Florida of $1.1 million and $1.0 million at September 30, 2013 and December 31, 2012, respectively, 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 our wholly owned subsidiary The Meridian Resource Corporation and its subsidiaries (“Meridian”), which we acquired in 2010, 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 Meridian’s 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, 2013.

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 for which 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.

15

We have a contingent commitment to pay an amount up to a maximum of approximately $2.5 million for properties acquired in 2008. The additional purchase consideration will be paid if certain product price conditions are met.

10. 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 5.  

11. PARTNERS’ CAPITAL (DEFICIT)

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 our capital partner, Alta Mesa Investment Holdings, Inc. (“AMIH”), was admitted to the partnership as the sole Class B limited partner (“Class B Partner”).  AMIH is an affiliate of Denham Commodity Partners Fund IV LP (“DCPF IV”). DCPF IV is advised by Denham Capital Management LP, a private equity firm focused on energy and commodities.

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 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.

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 the indenture that governs 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, 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.

12. 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.

16

ITEM 2. Management’s 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 Annual Report on Form 10-K for the year ended December 31, 2012 (“2012 Form 10-K”). 

Overview

We have been engaged in onshore oil and natural gas acquisition, exploitation, exploration and production since 1987.   We operate in one industry segment, oil and natural gas exploration and development, within one geographical segment, the United States.  Currently, we are focusing our drilling efforts in our Eagle Ford shale play in Karnes County, Texas, our Weeks Island field in South Louisiana and the Sooner Trend area of the Anadarko Basin in Oklahoma.  Our operations also include natural gas interests in East Texas which produce principally from the Wilcox formation, and our Hilltop field with reserves in the Deep Bossier and Knowles Lime formations.

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.

Outlook

Natural gas prices declined significantly during 2011 and 2012, reaching a low point in the first half of 2012 as reflected in the May 2012 NYMEX Henry Hub contract closing at $2.04 per MMbtu. Since then, prices have generally increased,  as indicated by the October 2013 NYMEX Henry Hub closing at $3.50 per MMbtu.

The decrease in natural gas prices resulted in a significant non-cash write-down of several of our oil and gas properties in the third and fourth quarters of 2012. Total impairment expense for the year 2012 was $96.2 million. Impairment expense for the first nine months of 2013 was $28.6 million. A significant portion of the total in 2012 was for our Hilltop field in East Texas, which produces dry gas, and is vulnerable to low prices for natural gas.  The write-down in 2013 was attributable to several different fields, the most significant of which was in our South Hayes field in South Louisiana due to development and recompletion results that indicated reserves were less than forecast.    

NYMEX West Texas Intermediate crude oil reflected a monthly average of $106.24 for September 2013. We expect oil prices to remain volatile in the future. Factors affecting the price of oil include worldwide economic conditions, including the European credit crisis, geopolitical activities, including developments in the Middle East, worldwide supply disruptions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets. Additionally, the price of oil is increasingly important to our revenues due to our current focus on development of oil reserves and exploration for oil. 

The unrealized values of our derivative contracts are reported at fair value on our consolidated balance sheets and are highly sensitive to changes in the price of oil and natural gas. Changes in these derivative assets and liabilities are reported in our consolidated statement of operations as unrealized hedging gain or loss, which is a non-cash item. In the third quarter of 2013, we recognized an unrealized loss on our derivative contracts of $21.5  million. Realized cash-based gains from our hedging program were $0.8 million during the quarter. The objective of our hedging program is that, over time, the combination of realized hedging gains and losses with ordinary oil and natural gas revenues will produce relative revenue stability. However, in the short term, both realized and unrealized hedging gains and losses can be significant to our results of operations, and we expect these gains and losses to continue to reflect changes in oil and natural gas prices.

We have hedged approximately 70% of our forecasted production from proved developed properties over the next five years at average annual prices ranging from $4.38 per MMbtu to $5.91 per MMbtu for natural gas and $80.00 per Bbl to $103.11 per Bbl for oil. If low natural gas prices continue for an extended period of time, we may be unable to replace expiring hedge contracts or enter new contracts for additional natural gas production at favorable prices.

17

Sustained low oil or natural gas prices may require us to further write down the value of our oil and natural gas properties and/or revise our development plans, which may cause certain of our undeveloped well locations to no longer be deemed proved. This could cause a reduction in the borrowing base under our credit facility. Low prices may also reduce our cash available for distribution and for servicing our indebtedness.

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, enhanced completions and well recompletions, and other enhanced recovery methods. 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

Eagleville field.  We completed 14 wells with working interests ranging from approximately 1% to 21%  in the Eagle Ford Shale formation in our Eagleville field during the third quarter of 2013. An additional 23 wells with working interests ranging from approximately 1% to 21% were in progress at the end of the quarter, with seven of those subsequently completed as producers through mid-November 2013.  As of September 30, 2013, we had 100 producing wells in this field, which are primarily operated by Murphy Oil Corporation (“Murphy”). Our average working interest in these wells is 15%. 

During the second quarter of 2013 Murphy drilled six wells from a single drilling pad on 26 acre spacing.  Previously developed Eagleville wells have been developed primarily on 80 acre spacing.  All six wells were completed as producers in the third quarter of 2013, with a combined production rate of approximately 2,200 BOE per day for the month of September 2013 (approximately 450 BOE per day net to our interest). 

For the third quarter of 2013, production from the Eagleville field was approximately 3,400 BOE per day net to our interest, as compared to 2,200 BOE per day in the third quarter of 2012.   Murphy is currently operating two drilling rigs on our acreage.

Weeks Island. We are targeting updip oil reserves and undrained fault blocks in this large oil field. We completed four wells in the third quarter of 2013, with one additional well in progress at the end of the quarter, and one developmental dry hole.  Our plans are to utilize one rig continuously through the end of 2013. We also have two workover rigs operating in this field, primarily for completing new wells and recompleting older wells to new producing zones.

Production from Weeks Island net to our interest was approximately 3,300 BOE per day, 89% oil, for the third quarter of 2013, as compared to 2,400 BOE per day, 97% oil, for the third quarter of 2012.

On October 1, 2013, we increased our ownership in Weeks Island with an acquisition from Stone Energy Offshore, L.L.C. (“Stone Energy”) of interests in wells primarily operated by us, representing an estimated 1.8 million BOE in proved reserves.  Total consideration was approximately $45 million cash plus related abandonment obligations.  This purchase increases our working interest in numerous wells in our Weeks Island field as well as increases our acreage in that area by approximately 600 gross acres for properties in which we previously had no working interest.

Sooner Trend.Development and production activity in our Sooner Trend group of properties in Oklahoma focuses on legacy water floods in the Manning, Big Lime, and Oswego formations, and horizontal drilling in the Mississippian Lime and Oswego formations.  In the third quarter of 2013, we completed two horizontal Mississippian Lime wells in  Sooner Trend and spud an additional three wells that will be completed in the fourth quarter.   Although our primary focus is horizontal activity in the units where we own over 84% of the working interest and maintain operational control, we also participate in non-operated drilling in the area.  Development activity during the third quarter of 2013 included three horizontal wells targeting the Mississippian Lime and Oswego formations and one successful vertical recompletion to the Mississippian Lime.  As of the end of the third quarter of 2013, we had four horizontal Mississippian Lime wells on production under our operational control, and four non-operated horizontal wells on production, one producing from the Mississippian Lime, two from the Oswego, and one from the Hunton Lime.

We plan to expand our horizontal drilling program targeting primarily the Mississippian Lime in the Lincoln North, Lincoln Southeast, and East Hennessey Units, by increasing to three operated rigs and one non-operated rig during the fourth quarter of 2013.

Production from our Sooner Trend properties net to our interest was approximately 1,400 BOE per day for the third quarter of 2013, as compared to approximately 1,000 BOE per day for the third quarter of 2012.

18

Hilltop divestiture.  On October 2, 2013, we sold a portion of our properties in Hilltop field comprising an estimated 11.2 Bcfe of proved reserves for approximately $19 million.  These wells were primarily producers of dry natural gas and were operated either by Gastar Exploration Ltd. or by us.    

19

Results of Operations: Three Months Ended September 30, 2013 v. Three Months Ended September 30, 2012 

	Three Months Ended September 30,				Increase
	2013		2012		(Decrease)		% Change
	(dollars in thousands, except average sales prices and
	unit costs)
Summary Operating Information:
Net Production:
Oil (MBbls)		749		568		181	32%
Natural gas (MMcf)		4,191		4,515		(324)	(7)%
Natural gas liquids (MBbls)		62		79		(17)	(22)%
Total oil equivalent (MBOE)		1,509		1,400		109	8%
Average daily oil production (MBOE per day)		16.4		15.2		1.2	8%
Average Sales Price:
Oil (per Bbl) realized	$	102.73	$	100.79	$	1.94	2%
Oil (per Bbl) unhedged		108.27		101.08		7.19	7%
Natural gas (per Mcf) realized		4.95		5.93		(0.98)	(17)%
Natural gas (per Mcf) unhedged		3.77		2.94		0.83	28%
Natural gas liquids (per Bbl) realized (1)		43.08		36.50		6.58	18%
Combined (per MBOE) realized		66.48		62.10		4.38	7%
Hedging Activities:
Realized oil revenue (loss)	$	(4,150)	$	(168)	$	(3,982)	(2370)%
Realized natural gas revenue gain		4,925		13,501		(8,576)	(64)%
Summary Financial Information
Revenues
Oil	$	76,938	$	57,285	$	19,653	34%
Natural gas		20,737		26,758		(6,021)	(23)%
Natural gas liquids		2,664		2,877		(213)	(7)%
Other revenues (loss)		(48)		2,568		(2,616)	(102)%
Unrealized loss — oil and natural gas derivative contracts		(21,455)		(37,855)		16,400	43%
		78,836		51,633		27,203	53%
Expenses
Lease and plant operating expense		18,031		17,719		312	2%
Production and ad valorem taxes		8,130		7,232		898	12%
Workover expense		3,428		4,318		(890)	(21)%
Exploration expense		13,508		9,480		4,028	42%
Depreciation, depletion, and amortization expense		30,667		27,147		3,520	13%
Impairment expense		2,072		46,472		(44,400)	(96)%
Accretion expense		460		458		2	0%
Loss on sale of assets		1,077		—		1,077	NA
General and administrative expense		13,378		9,812		3,566	36%
Interest expense, net		13,822		9,892		3,930	40%
Provision for state income taxes		—		—		—	NA
Net loss	$	(25,737)	$	(80,897)	$	55,160	68%
Average Unit Costs per BOE:
Lease and plant operating expense	$	11.95	$	12.66	$	(0.71)	(6)%
Production and ad valorem tax expense		5.39		5.17		0.22	4%
Workover expense		2.27		3.08		(0.81)	(26)%
Exploration expense		8.95		6.77		2.18	32%
Depreciation, depletion and amortization expense		20.32		19.39		0.93	5%
General and administrative expense		8.87		7.01		1.86	27%

(1)We do not utilize hedges for natural gas liquids.

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Revenues

Oil revenues for the three months ended September 30, 2013 increased $19.7 million, or 34%, to $76.9 million from $57.3 million for the corresponding period in 2012. The increase in revenue was attributable to increased production volumes augmented by a slightly higher average realized price. Approximately $18.2 million of the increase was due to an increase in production of 181 MBbls, or 32%. This increase is primarily due to production from our Eagleville field, which increased 101 MBbls, from 166 MBbls in the third quarter of 2012 to 267 MBbls for the third quarter of 2013.  Weeks Island field also increased production by 56 MBbls, from 216 MBbls in the third quarter of 2012 to 272 MBbls in the corresponding period of 2013.    The average price of oil exclusive of hedging increased 7% in the third quarter of 2013; the overall realized price (including hedging gains and losses) increased 2% from $100.79 per Bbl in the third quarter of 2012 to $102.73 per Bbl in the third quarter of 2013, resulting in an increase in oil revenues of approximately $1.5 million.

Natural gas revenues for the three months ended September 30, 2013 decreased $6.0 million, or 23%, to $20.7 million from $26.7 million for the same period in 2012. The decrease in natural gas revenue was attributable to decreased production during the third quarter of 2013 as well as a decrease in average realized price.  Approximately $1.9 million of the decrease in revenues from natural gas was due to a decrease in production of 0.3 Bcf, or 7%. This decline is primarily due to an emphasis on liquids-rich assets in our capital spending.  Hilltop field, our largest natural gas field, produced 1.5 Bcf in the third quarter of 2013, compared to 1.9 Bcf in the third quarter of 2012.  The average price of natural gas exclusive of hedging increased 28% in the third quarter of 2013; the overall realized price (including realized hedging gains and losses) decreased 17% from $5.93 per Mcf in the third quarter of 2012 to $4.95 per Mcf in the third quarter of 2013, resulting in a decrease in natural gas revenues of approximately $4.1 million.

Natural gas liquids revenues decreased  $0.2 million, or 7%, during the third quarter of 2013 compared to the same period in 2012.  The decrease in natural gas liquids revenue was attributable to decreased production volumes partially offset by a higher average realized price during the third quarter of 2013.  A  22% decrease in volumes from 79 MBbls to 62 MBbls was partially offset by an increase in our average price of 18%, from $36.50 per Bbl to $43.08 per Bbl.  The decline in volume is primarily due to production declines in certain natural gas fields which also produce natural gas liquids.

Other revenues decreased $2.6 million during the three months ended September 30, 2013 as compared to the three months ended September 30, 2012. The decrease is partially the result of a decrease in rental income from our drilling rig, which we sold during the third quarter of 2013.   In addition, the third quarter of 2012 reflects $2.0 million in sales of prospects.

Unrealized loss — oil and natural gas derivative contracts was a loss of $21.5 million during the three months ended September 30, 2013 as compared to a loss of $37.9 million during the same period in 2012. The fluctuation from period to period is due to the volatility of oil and natural gas prices and changes in our outstanding hedging contracts during these periods.

Expenses

Lease and plant operating expense increased $0.3 million in the third quarter of 2013 as compared to the third quarter of 2012, from $17.7 million to $18.0 million, primarily due to an increase in chemical usage, field services and rental equipment of $1.5 million.  This is primarily due to higher costs incurred on liquids-rich assets.  This increase was partially offset by a decrease in marketing and gathering fees of $0.8 million and a decrease in repairs and maintenance of $0.4 million.   The decrease in marketing and gathering expense is primarily due to lower production of natural gas in our Hilltop field.

Production and ad valorem taxes increased $0.9 million, or 12%, to $8.1 million for the third quarter of 2013, as compared to $7.2 million for the third quarter of 2012. Production taxes increased $1.3 million following increased revenues exclusive of hedging gains.  Production tax as a percentage of product revenues before realized hedging gains and losses was approximately 7% for the quarter ended September 30, 2013 and 8% for the corresponding period in 2012.   Ad valorem taxes decreased $0.4 million due to changes in estimates for 2013 based on final property tax assessments for 2012.

Workover expense decreased from the third quarter of 2012 to the third quarter of 2013, from $4.3 million to $3.4 million, respectively. This expense varies depending on activities in the field and is attributable to many different properties.  

Exploration expense includes the costs of our geology department, costs of geological and geophysical data, lease rentals, expired leases, and dry holes. Exploration expense increased from $9.5 million for the third quarter of 2012 to $13.5 million for the third quarter of 2013,  primarily due to $8.6 million in dry hole expense for a well in our South Hayes field in South Louisiana.

Depreciation, depletion and amortization increased $3.5 million to $30.6 million for the third quarter of 2013 as compared to an expense of $27.1 million for the third quarter of 2012. On a per unit basis, this expense increased from $19.39 to $20.32 per BOE. The rate is a function of capitalized costs of proved properties, reserves and production by field.

Impairment expense decreased from $46.4 million in the third quarter of 2012 to $2.1 million in the third quarter of 2013. This expense varies with the results of drilling, as well as with price declines and other factors which may render some fields uneconomic, 

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resulting in impairment. The significant expense in the third quarter of 2012 included write-downs in several large natural gas fields based primarily on the decline in market prices for natural gas.  A much smaller write-down in the third quarter of 2013 was the result of a decline in the value of a portion of our natural gas properties in West Virginia.

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 for the third quarter of 2013 and 2012, respectively.

Loss on sale of assets was $1.1 million in the third quarter of 2013. The loss was related to the sale of our drilling rig. 

General and administrative expense increased $3.6 million, or 36%, for the third quarter of 2013 to $13.4 million from $9.8 million for the third quarter of 2012.  The increase is principally due to an increase of $3.1 million in estimated bonus expenses, based on increased headcount and final determination of bonuses for 2012.  On a per unit basis, general and administrative expenses increased from $7.01 per BOE to $8.87 per BOE.

Interest expense, net increased $3.9 million for the third quarter of 2013 to $13.8 million from $9.9 million for the third quarter of 2012, primarily due to higher interest of $3.6 million on our senior notes.   In October 2012, we issued an additional $150 million of the senior notes.  Interest on our credit facility increased $0.3 million in the third quarter of 2013 as compared to the same period in 2012 due to higher outstanding balances. 

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Results of Operations: Nine Months Ended September 30, 2013 v. Nine Months Ended September 30, 2012 

	Nine Months Ended September 30,				Increase
	2013		2012		(Decrease)		% Change
	(dollars in thousands, except average sales prices and
	unit costs)
Summary Operating Information:
Net Production:
Oil (MBbls)		2,094		1,534		560	37%
Natural gas (MMcf)		12,823		17,144		(4,321)	(25)%
Natural gas liquids (MBbls)		204		228		(24)	(11)%
Total oil equivalent (MBOE)		4,435		4,619		(184)	(4)%
Average daily oil production (MBOE per day)		16.2		16.9		(0.7)	(4)%
Average Sales Price:
Oil (per Bbl) realized	$	102.60	$	104.38	$	(1.78)	(2)%
Oil (per Bbl) unhedged		105.65		105.00		0.65	1%
Natural gas (per Mcf) realized		5.37		4.59		0.78	17%
Natural gas (per Mcf) unhedged		3.82		2.65		1.17	44%
Natural gas liquids (per Bbl) realized (1)		37.86		45.74		(7.88)	(17)%
Combined (per BOE) realized		65.71		53.94		11.77	22%
Hedging Activities:
Realized oil revenue (loss)	$	(6,374)	$	(958)	$	(5,416)	(565)%
Realized natural gas revenue gain		19,924		33,130		(13,206)	(40)%
Summary Financial Information
Revenues
Oil	$	214,824	$	160,069	$	54,755	34%
Natural gas		68,883		78,638		(9,755)	(12)%
Natural gas liquids		7,723		10,414		(2,691)	(26)%
Other revenues		1,110		3,952		(2,842)	(72)%
Unrealized loss — oil and natural gas derivative contracts		(20,405)		(19,944)		(461)	(2)%
		272,135		233,129		39,006	17%
Expenses
Lease and plant operating expense		51,681		50,833		848	2%
Production and ad valorem taxes		21,326		19,315		2,011	10%
Workover expense		12,013		8,254		3,759	46%
Exploration expense		22,374		13,543		8,831	65%
Depreciation, depletion, and amortization expense		83,547		76,161		7,386	10%
Impairment expense		28,618		50,934		(22,316)	(44)%
Accretion expense		1,352		1,339		13	1%
Loss on sale of assets		2,267		—		2,267	NA
General and administrative expense		32,139		30,195		1,944	6%
Interest expense, net		40,673		29,440		11,233	38%
Litigation settlement		—		(1,250)		1,250	NA
Provision for state income taxes		—		—		—	NA
Net loss	$	(23,855)	$	(45,635)	$	21,780	48%
Average Unit Costs per BOE:
Lease and plant operating expense	$	11.65	$	11.01	$	0.64	6%
Production and ad valorem tax expense		4.81		4.18		0.63	15%
Workover expense		2.71		1.79		0.92	51%
Exploration expense		5.04		2.93		2.11	72%
Depreciation, depletion and amortization expense		18.84		16.49		2.35	14%
General and administrative expense		7.25		6.54		0.71	11%

(1)We do not utilize hedges for natural gas liquids.

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Revenues

Oil revenues for the nine months ended September 30, 2013 increased $54.8 million, or 34%, to $214.8 million from $160.0 million for the same period in 2012. The increase in revenue was attributable to increased production volumes partially offset by a decrease in the average realized price.  Approximately $58.5 million of the increase was due to an increase in production of 560 MBbls, or 37%. This increase is primarily due to production from our Eagleville field, which increased 344 MBbls, from 421 MBbls for the first nine months of 2012 to 765 MBbls for the corresponding period of 2013. Our Weeks Island field also increased production by 185 MBbls, from 533 MBbls in the first nine months of 2012 to 718 MBbls in the corresponding period in 2013.  The increase in production was partially offset by a decrease in pricing.  The average price of oil exclusive of hedging increased 1% in the first nine months of 2013; however, the overall realized price (including realized hedging gains and losses) decreased 2% from $104.38 per Bbl in the first nine months of 2012 to $102.60 per Bbl in the corresponding period of 2013, resulting in a decrease in oil revenues of approximately $3.7 million.

Natural gas revenues for the nine months ended September 30, 2013 decreased $9.7 million, or 12%, to $68.9 million from $78.6 million for the same period in 2012. The decrease in natural gas revenue was attributable to decreased production volumes during the first nine months of 2013, partially offset by an increase in the average realized price.  Natural gas revenues declined approximately $19.8 million due to a decrease in production of 4.3 Bcf, or 25%. This decline is primarily due to an emphasis on liquids-rich assets in our capital spending.  Hilltop field, our largest natural gas field, produced 4.6 Bcf in the first nine months of 2013, compared to 7.9 Bcf in the corresponding period of 2012. The average price of natural gas exclusive of hedging increased 44% in the first nine months of 2013; the overall realized price (including realized hedging gains and losses) increased 17% from $4.59 per Mcf in the first nine months of 2012 to $5.37 per Mcf in the corresponding period of 2013, resulting in an increase in natural gas revenues of approximately $10.1 million. 

Natural gas liquids revenues decreased  $2.7 million, or 26%, to $7.7 million during the first nine months of 2013 compared to $10.4 million for the same period in 2012.  The decrease in natural gas liquids revenue is attributable to decreased production volumes and lower average realized price.  A decrease in volumes of 11% from 228 MBbls to 204 MBbls was augmented by a decrease in our average price of 17%, from $45.74 per Bbl to $37.86 per Bbl. The decrease in volume is primarily due to an upward volume adjustment in 2012 which did not recur in 2013. The decline in prices is primarily due to oversupply of natural gas liquids from increased drilling.

Other revenues were $1.1 million during the nine months ended September 30, 2013 as compared to $4.0 million during the nine months ended September 30, 2012. The decrease is partially the result of a decrease in rental income from our drilling rig, which we sold during the third quarter of 2013. In addition, the third quarter of 2012 reflects $2.0 million in sales of prospects.

Unrealized loss — oil and natural gas derivative contracts was $20.4 million during the nine months ended September 30, 2013 as compared to $19.9 million during the same period in 2012. The fluctuation from period to period is due to the volatility of oil and natural gas prices and changes in our outstanding hedging contracts during these periods.

Expenses

Lease and plant operating expense increased $0.9 million in the first nine months in 2013 as compared to the corresponding period in 2012, from $50.8 million to $51.7 million, primarily due to an increase is chemical usage, field services, rental equipment and repairs and maintenance totaling $6.3 million.   This is primarily due to higher costs incurred on liquids-rich assets.  This increase was partially offset by a decrease in marketing and gathering fees of $3.3 million, lower overhead and insurance costs of $1.7 million, and a decrease in compression and salt water disposal costs totaling $0.6 million.  The marketing and gathering decrease is primarily due to lower production in our Hilltop field.  On a unit basis, lease and plant operating expense increased from $11.01 per BOE to $11.65 per BOE for the nine months ended September 30, 2012 and 2013, respectively.

Production and ad valorem taxes increased $2.0 million, or 10%, to $21.3 million for the first nine months of 2013, as compared to $19.3 million for the corresponding period of 2012.   Production taxes increased $3.1 million. Production tax as a percentage of product revenues before realized hedging gains and losses was approximately 7% for the nine months ended September 30, 2013 and 7% for the corresponding period in 2012.  Ad valorem taxes decreased $1.1 million primarily due to adjustments based on final property tax assessments for 2012.

Workover expense increased  $3.7 million from the first nine months of 2012 to the first nine months of 2013, from $8.3 million to $12.0 million, respectively. This expense varies depending on activities in the field and is attributable to many different properties.  

Exploration expense includes the costs of our geology department, costs of geological and geophysical data, lease rentals, expired leases, and dry holes. Exploration expense increased $8.9 million from $13.5 million for the first nine months of 2012 to $22.4 

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million for the first nine months of 2013.  The majority of the increase was due to an increase of $7.7 million in dry hole costs, primarily due to a dry hole in South Louisiana in the third quarter of 2013 and to an increase in lease rental expense of $1.0 million.

Depreciation, depletion and amortization increased $7.4 million to $83.5 million for the first nine months of 2013 as compared to $76.1 million for the corresponding period of 2012. On a per unit basis, this expense increased from $16.49 per BOE to $18.84 per BOE. The rate is a function of capitalized costs of proved properties, reserves and production by field.

Impairment expense decreased $22.3 million, from $50.9 million in the first nine months of 2012 to $28.6 million in the corresponding period of 2013. This expense varies with the results of drilling, as well as with price declines and other factors which may render some fields uneconomic, resulting in impairment.  The significant impairment in the first nine months of 2012 included write-downs in several large natural gas fields based primarily on the decline in market prices for natural gas.  The expense in the first nine months of 2013 included $17.8 million from a reduction in the economic value of our South Hayes field in South Louisiana.  Other impairments included $4.2 million recorded in the first nine months of 2013 in our Indian Point field in South Texas.

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 $1.3 million for each of the nine month periods ending September 30, 2013 and 2012, respectively.  

Loss on sale of assets was $2.3 million in the first nine months of 2013. The loss in 2013 was primarily related to the sale of a well in South Texas and to the sale of our drilling rig. 

General and administrative expense increased  $1.9 million, or 6%, for the first nine months of 2013 to $32.1 million from $30.2 million for the corresponding period of 2012.  The increase is principally due to increases in salary and benefits due to increased headcount totaling $4.0 million and to increased consulting expenses of $1.2 million.  These increases were partially offset by decreased legal and engineering services expenses totaling $3.2 million.  Legal expenses were higher in 2012 due to litigation resolved in the second quarter of that year.  On a per unit basis, general and administrative expenses increased from $6.54 per BOE to $7.25 per BOE.  

Interest expense, net increased $11.2 million for the first nine months of 2013 to $40.7 million from $29.4 million for the first nine months of 2012, primarily due to higher interest of $11.0 million on our senior notes.  In October 2012, we issued an additional $150 million of the senior notes.  Interest on our credit facility increased $0.2 million in the first nine months of 2013 as compared to the same period in 2012 due to higher outstanding balances. 

Litigation settlement is related to the settlement of our litigation with Gastar, under which Gastar paid us $1.25 million in damages in the second quarter of 2012.

Liquidity and Capital Resources

Our principal requirements for capital are to fund our day-to-day operations, exploration and 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 2013 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 $310 million during 2013, of which approximately $227 million has been expended or accrued through September 30, 2013. In addition, as described above, we expended $45 million on the acquisition of Stone Energy’s interests at Weeks Island and received $19 million in the Hilltop divestiture, for a net additional $26 million outlay in the fourth quarter of 2013 for acquisitions and divestitures.  Approximately 64% of our 2013 capital budget (exclusive of the Stone and Hilltop transactions) is allocated to our properties in the Eagle Ford shale, Sooner Trend, 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 2013 capital budget predominantly with cash flows from operations, supplemented by borrowings under our credit facility. If necessary, we may also access capital through proceeds from potential asset dispositions and the future issuances 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.

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Senior Notes

In October 2010, we issued $300 million of 9.625% senior notes due 2018 at a discount of $2.1 million, with a yield to maturity of 9.75%.  On October 15, 2012, we issued an additional $150 million of senior notes under the same indenture with the same interest rate, date of maturity, and other terms, at a discount of $1.5 million and with a yield to maturity of 9.85%.  The senior notes were issued in private placements but were exchanged for substantially identical registered notes.

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.

Credit Facility

We have a senior secured revolving credit facility (“credit facility”) with Wells Fargo Bank, N.A. as the administrative agent, which matures May 23, 2016.  Our restricted subsidiaries are guarantors of the credit facility. 

The borrowing base is redetermined each May 1 and November 1. The borrowing base was $330 million as of September 30, 2013, and was subsequently increased to $385 million on October 1, 2013. The next redetermination will be May 1, 2014. As of November 13, 2013, outstanding borrowing under the credit facility was $319.3 million, and the available unused portion of the borrowing base was $65.6 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, 2013 under the credit facility was 2.75%, which was based primarily on the Eurodollar option.

The credit facility and the indenture governing the senior notes include covenants requiring us to maintain certain financial covenants including a current ratio, leverage ratio, and interest coverage ratio.  At September 30, 2013, 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 $147.2 million during the nine months ended September 30, 2013 as compared to $117.9 million during the comparable period in 2012. The $29.3 million increase was attributable to an increase in the cash-based portions of our earnings in operating cash flows augmented by 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, increased approximately $19.3 million, resulting in a positive impact on cash flow.  Changes in our working capital accounts provided $17.5 million of cash flows as compared to  $7.5 million of cash flows provided in 2012. The changes in  working capital resulted in an increase of $10.0 million in cash flow.

Cash flow used in investing activities

Investing activities used cash of $247.6 million during the nine months ended September 30, 2013 as compared to cash used in investing of $172.3 million during the comparable period of 2012.  Investment in property and equipment increased by $93.4 million, due primarily to increased drilling and development. A decrease in cash used in acquisition activities of $10.7 million was primarily due to $6.3 million expended for a group of leasehold properties in South Texas in the first nine months of 2012, whereas in the first nine months of 2013 there were no individually significant property acquisitions. Sale of properties, primarily our drilling rig, provided cash flow of $7.4 million in the first nine months of 2013.  On an accrual basis, capital spending was also increased, primarily for expenditures in our Eagle Ford Shale play, South Louisiana (Weeks Island), Sooner Trend, and South Texas. 

Cash flow provided by financing activities

Financing activities provided cash of $101.4 million during the  nine months ended September 30, 2013 as compared to cash provided by financing of $57.9 million during the comparable period in 2012. Both periods reflected the effect of drawdowns from our credit facility.

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

26

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 Annual Report on Form 10-K for the year ended December 31, 2012 (“2012 Form 10-K”) and Part II, Item 1A of this report. These forward-looking statements are based on management’s 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 quantities and the present value of our reserves;  

· financial strategy, liquidity and capital required for our development program;

· future realized oil and natural gas prices;

· timing and amount of future production of oil and natural gas;

· hedging strategy and results;

· future drilling plans;

· marketing of oil and natural gas;

· leasehold or business acquisitions;

· costs of developing our properties;

· liquidity and access to capital;

· 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, commodity price volatility, low prices for oil and/or natural gas, global economic conditions, inflation, increased operating costs, 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, reductions in cash flow and lack of access to capital, and the other risks described under “Item 1A. Risk Factors” in our 2012 Form 10-K.

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.

Should one or more of the risks or uncertainties described in the 2012 Form 10-K 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.

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ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

For information regarding our exposure to certain market risks, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risk Management Activities—Commodity Derivative Instruments” and “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in our 2012 Form 10-K. There have been no material changes to the disclosure regarding market risks other than as noted below. See Part I, Item 1, Note 5 to our consolidated financial statements for a description of our outstanding derivative contracts at the most recent reporting date.

The fair value of our oil and natural gas derivative contracts and basis swaps at September 30, 2013 was a net asset of $14.9 million. A 10% increase or decrease in oil and natural gas prices with all other factors held constant would result in an unrealized loss or gain, respectively, in the estimated fair value (generally correlated to our estimated future net cash flows from such instruments) of our oil and natural gas commodity contracts of approximately $56.5 million (net unrealized loss) or $55.2 million (net unrealized gain), respectively, as of September 30, 2013.

We are subject to interest rate risk on our variable interest rate borrowings. Although in the past we have used interest rate swaps to mitigate the effect of fluctuating interest rates on interest expense, we currently have no open interest rate derivative contracts.  A 1% increase in interest rates would increase annual interest expense on our variable rate debt by approximately $2.6 million, based on the balance outstanding as of September 30, 2013.

ITEM 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Rules 13a-15 and 15d-15 under the Securities Exchange Act of 1934, as amended (“Exchange Act”), 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, 2013 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 Commission’s 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, 2013 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 9 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 “Item 1A. Risk Factors” in the 2012 Form 10-K. There have been no material changes with respect to the risk factors disclosed in the 2012 Form 10-K during the quarter ended September 30, 2013.  

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

ITEM  3. Defaults Upon Senior Securities

None.

ITEM  4. Mine Safety Disclosures

Not applicable.

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ITEM 5. Other Information

None.

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ITEM  6. Exhibits

31.1	Certification of the Company’s 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 Company’s 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 Company’s 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 Company’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
101	Interactive Data Files.

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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
November 13, 2013		general partner
	By:	/s/ Harlan H. Chappelle
		Harlan H. Chappelle
November 13, 2013		President and Chief Executive Officer
	By:	/s/ Michael A. McCabe
		Michael A. McCabe
		Vice President and Chief Financial Officer

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