Alta Mesa 10-Q 2014 Q3 Quarterly report

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended: September 30, 2014 

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  ☐    No  ☒ 

(Explanatory Note: The registrant is a voluntary filer and is not subject to the filing requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934.   However, the registrant 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 would have been required to file such reports) as if it were subject to such filing requirements.)

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  ☒    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	☒  (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  ☒ 

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Table of Contents 

	Page Number
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements	3
Consolidated Balance Sheets as of September 30, 2014 (unaudited) and December 31, 2013	3
Consolidated Statements of Operations  (unaudited) for the Three and Nine Months Ended September 30, 2014 and 2013	4
Consolidated Statements of Cash  Flows (unaudited) for the Nine Months Ended September 30, 2014 and 2013	5
Notes to Consolidated Financial Statements (unaudited)	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3. Quantitative and Qualitative Disclosures about Market Risk	31
Item 4. Controls and Procedures	31
PART II — OTHER INFORMATION
Item 1. Legal Proceedings	32
Item 1A. Risk Factors	32
Item 6. Exhibits	32
Signatures	33

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,
	2014		2013
	(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	5,704	$	6,537
Short-term restricted cash		25,783		—
Accounts receivable, net		60,450		43,486
Other receivables		1,130		2,552
Prepaid expenses and other current assets		2,783		3,077
Derivative financial instruments		7,377		5,572
TOTAL CURRENT ASSETS		103,227		61,224
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net		694,685		691,770
Other property and equipment, net		10,474		9,100
TOTAL PROPERTY AND EQUIPMENT, NET		705,159		700,870
OTHER ASSETS
Long-term restricted cash		9,162		—
Investment in partnership — cost		9,000		9,000
Deferred financing costs, net		8,827		10,943
Derivative financial instruments		1,782		3,405
Advances to operators		1,073		6,863
Deposits and other assets		1,139		1,186
TOTAL OTHER ASSETS		30,983		31,397
TOTAL ASSETS	$	839,369	$	793,491
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	136,798	$	96,095
Current portion, asset retirement obligations		7,065		3,844
Derivative financial instruments		—		4,483
TOTAL CURRENT LIABILITIES		143,863		104,422
LONG-TERM LIABILITIES
Asset retirement obligations, net of current portion		51,925		52,179
Long-term debt		695,481		766,868
Notes payable to founder		24,235		23,331
Derivative financial instruments		763		4,486
Other long-term liabilities		5,802		2,312
TOTAL LONG-TERM LIABILITIES		778,206		849,176
TOTAL LIABILITIES		922,069		953,598
COMMITMENTS AND CONTINGENCIES (NOTE 10)
PARTNERS’ CAPITAL (DEFICIT)		(82,700)		(160,107)
TOTAL LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)	$	839,369	$	793,491

See notes to consolidated financial statements.

3

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(dollars in thousands)

(unaudited)

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2014		2013		2014		2013
REVENUES
Oil	$	104,196	$	81,088	$	276,524	$	221,198
Natural gas		16,165		15,470		52,705		46,652
Natural gas liquids		4,787		3,006		14,653		10,030
Other revenues (loss)		496		(48)		784		1,110
		125,644		99,516		344,666		278,990
Gain (loss) on sale of assets		18,556		(1,077)		87,107		(2,267)
Gain (loss) — oil and natural gas derivative contracts		39,911		(20,680)		4,483		(6,855)
TOTAL REVENUES		184,111		77,759		436,256		269,868
EXPENSES
Lease and plant operating expense		18,440		18,031		55,022		51,681
Production and ad valorem taxes		8,357		8,130		22,985		21,326
Workover expense		2,316		3,428		7,279		12,013
Exploration expense		15,779		13,508		44,015		22,374
Depreciation, depletion, and amortization expense		39,880		30,667		102,357		83,547
Impairment expense		8,706		2,072		27,908		28,618
Accretion expense		365		460		1,536		1,352
General and administrative expense		17,243		13,378		55,854		32,139
TOTAL EXPENSES		111,086		89,674		316,956		253,050
INCOME (LOSS) FROM OPERATIONS		73,025		(11,915)		119,300		16,818
OTHER INCOME (EXPENSE)
Interest expense		(13,701)		(13,845)		(41,621)		(40,794)
Interest income		2		23		11		121
TOTAL OTHER INCOME (EXPENSE)		(13,699)		(13,822)		(41,610)		(40,673)
INCOME (LOSS) BEFORE STATE INCOME TAXES		59,326		(25,737)		77,690		(23,855)
BENEFIT FROM (PROVISION FOR) STATE INCOME TAXES		—		—		(283)		—
NET INCOME (LOSS)	$	59,326	$	(25,737)	$	77,407	$	(23,855)

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,
	2014		2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	77,407	$	(23,855)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization expense		102,357		83,547
Impairment expense		27,908		28,618
Accretion expense		1,536		1,352
Amortization of loan costs		2,158		2,121
Amortization of debt discount		383		383
Dry hole expense		24,911		13,700
Expired leases		1,016		223
(Gain) loss — oil and natural gas derivative contracts		(4,483)		6,855
Settlements of derivative contracts		(3,905)		13,550
Interest converted into debt		904		904
(Gain) loss on sale of assets		(87,107)		2,267
Changes in assets and liabilities:
Restricted cash unrelated to property divestiture		(105)		2,305
Accounts receivable		(16,964)		(2,310)
Other receivables		1,422		3,133
Prepaid expenses and other non-current assets		6,131		6,564
Settlement of asset retirement obligation		(3,278)		(1,358)
Accounts payable, accrued liabilities, and other long-term liabilities		26,816		9,231
NET CASH PROVIDED BY OPERATING ACTIVITIES		157,107		147,230
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property and equipment		(269,827)		(254,955)
Proceeds from sale of property		218,539		7,401
Investment in restricted cash related to property divestiture		(34,840)		—
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(86,128)		(247,554)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt		97,500		119,500
Repayments of long-term debt		(169,270)		(18,000)
Additions to deferred financing costs		(42)		(97)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(71,812)		101,403
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(833)		1,079
CASH AND CASH EQUIVALENTS, beginning of period		6,537		5,786
CASH AND CASH EQUIVALENTS, end of period	$	5,704	$	6,865
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid during the period for interest	$	27,387	$	26,696
Cash paid (received) during the period for state taxes	$	(125)	$	18
Change in asset retirement obligations	$	1,760	$	1,001
Asset retirement obligations assumed, purchased properties	$	—	$	169
Change in accruals or liabilities for capital expenditures	$	20,056	$	(20,686)

See notes to consolidated financial statements.

5

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1.  OPERATIONS, CONSOLIDATION AND BASIS OF PRESENTATION 

Alta Mesa Holdings, LP and its subsidiaries (“we,” “us,” “our,” the “Company,” and “Alta Mesa”) is an independent energy company 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. 

The consolidated financial statements reflect our accounts 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, 2013,  which were filed with the Securities and Exchange Commission in our 2013 Annual Report on Form 10-K.

The consolidated financial statements included herein as of September  30, 2014, and for the three month and nine month periods ended September  30, 2014 and 2013, 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.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

As of September  30,  2014, our significant accounting policies are consistent with those discussed in Note 2 of the consolidated financial statements for the fiscal year ended December 31, 2013.  

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.

Reclassifications:   Certain amounts in the 2013 consolidated financial statements have been reclassified to conform to the 2014 presentation. The reclassifications had no impact on net income (loss) or partners’ capital (deficit).  

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.

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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 Accounting Standards Codification (“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. 

Restricted cash: The balance in restricted cash is invested in a money market fund held by a qualified intermediary in anticipation of property acquisitions designed to defer for our partners a potential taxable gain on the sale of our Hilltop field in the third quarter of 2014.  The funds are restricted until the earlier of expenditure or March 18, 2015.    Approximately $9.2 million was expended or committed from the restricted account for purchase of qualifying properties in October 2014.  We have classified this portion of the balance as non-current as of September 30, 2014. 

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 $1.2 million and $1.4 million at September  30,  2014 and December 31, 2013, 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,  2014 and 2013, amortization of deferred financing costs included in interest expense amounted to $0.7 million and $0.7 million, respectively. For the nine month periods ended September 30, 2014 and 2013, amortization of deferred financing costs included in interest expense amounted to $2.2 million and $2.1 million, respectively. Deferred financing costs are listed among our long-term assets, net of accumulated amortization of $14.9 million and $12.8 million at September  30,  2014 and December 31, 2013, 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 payable to our founder is not practicable to determine. We have estimated the fair value of our $450 million senior notes payable at $460.1 million at September  30,  2014. See Note 5 for further information on fair values of financial instruments. See Note 8 for information on long-term debt.

7

Recent Accounting Pronouncements

In April 2014, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.  ASU 2014-08 narrows the definition of “discontinued operations” to dispositions that represent a strategic shift that has or will have a significant impact on the entity’s operations and financial results.  The ASU requires additional disclosures regarding assets and liabilities held for sale, and income and losses, including gain or loss on sale, and cash flows from discontinued operations.  In addition, the ASU requires disclosures for disposals of individually significant components of the business which do not qualify as discontinued operations, including general information about the disposition and disclosure of the pretax profit or loss from the component for the period of disposal and all comparable historic periods presented.  ASU 2014-08 is effective for all fiscal years beginning after December 15, 2014, and can be adopted early for certain asset dispositions and reclassifications of assets from “held and used” to “held for sale.”

In May 2014, the FASB issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606).  The update provides guidance concerning the recognition and measurement of revenue from contracts with customers.  Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues.  The update is effective for the Company beginning in calendar year 2017.  We are evaluating the impact this standard will have on our consolidated financial statements and related disclosures.

In August 2014, the FASB issued Accounting Standards Update 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.  The new standard requires management to assess the company’s ability to continue as a going concern.  Disclosures are required if there is substantial doubt as to the company’s continuation as a going concern within one year after the issue date of financial statements.  The standard provides guidance for making the assessment, including consideration of management’s plans which may alleviate doubt regarding the company’s ability to continue as a going concern. ASU 2014-15 is effective for years beginning after December 15, 2016.    We do not expect the adoption of this pronouncement to have a material impact on our consolidated financial statements.

NOTE 3 — SIGNIFICANT ACQUISITIONS AND DIVESTITURES

Eagleville Divestiture

On March 25, 2014 we closed the sale of certain of our properties located primarily in Karnes County, Texas to Memorial Production Operating LLC, comprising a portion of our Eagleville field (“Eagleville divestiture”).  The properties sold included a working interest in all of our producing wells as of the effective date of January 1, 2014.  We retained a net profits interest in these wells based on 50% of our original working interest in 2014, declining to 30% in 2015, 15% in 2016, and zero in 2017.  Also included in the sale was a 30% undivided interest in all our Eagleville mineral leases and interests, and 30% of our working interest in all our wells in progress on December 31, 2013 or drilled after January 1, 2014.  The initial cash purchase price was $173 million,  subsequently adjusted to approximately $168 million for settlement adjustments through September 30, 2014.  The purchase and sale agreement provides for customary adjustments to the purchase price for revenues and expenses incurred after the effective date.  As of January 1, 2014, estimated net proved reserves associated with the sold portion of these properties were approximately 7.7 MMBOE.  We recorded a preliminary gain on sale from the Eagleville divestiture of $69.3 million during the first nine months of 2014, based on a preliminary allocation of basis between the properties sold and properties retained.

The sold portion of Eagleville field contributed approximately $9.9 million and $26.3 million in net pre-tax profit for the three months and nine months ended September 30, 2013, respectively, and $6.6 million in the first quarter of 2014, prior to its sale.

Hilltop Divestiture

On October 2, 2013 we closed the sale of certain of our properties in East Texas, comprising a portion of our Hilltop field (“Hilltop divestiture”).  The properties sold were primarily producers of dry natural gas located in Leon County, Texas.  As of July 1, 2013, estimated net proved reserves associated with these properties were 11.2 BCFE. The net cash purchase price was approximately $19 million.  There was no material gain on the sale. 

On September 19, 2014, we sold our remaining interests in the Hilltop field for a cash payment of $41.6 million, which will be subject to customary settlement adjustments.  We recorded a preliminary gain on the sale of $18.3 million.  As of the date of sale, estimated proved reserves associated with these properties were 29.8 BCFE.

The Hilltop interests contributed approximately $0.5 million and $3.6 million in net pre-tax income during the three months and nine months ended September 30, 2013, respectively.  Both these periods were prior to the first sale, and include income from the wells sold in each of the two separate sales.

8

Weeks Island Acquisition

On October 1, 2013 we closed a transaction to purchase certain producing properties in South Louisiana from Stone Energy Offshore, L.L.C. (“Stone”) for cash consideration of approximately $42 million cash plus related abandonment costs. This purchase increased our working interest in our Weeks Island field. Total estimated net proved reserves associated with the acquisition were 1.8 MMBOE as of the effective date of July 1, 2013.

A summary of the consideration paid and the preliminary allocation of the purchase prices are as follows:

	October 1,
	2013
	(dollars in thousands)
	(unaudited)
Summary of Consideration
Cash	$	41,841
Fair value of asset retirement obligations assumed		5,311
Total	$	47,152
Summary of Purchase Price Allocation
Proved oil and natural gas properties	$	30,279
Unproved oil and natural gas properties		16,873
Total	$	47,152

The revenue and earnings related to the Weeks Island acquisition are included in our consolidated statement of operations for the year ended December 31, 2013 from date of acquisition. The revenue and earnings of the combined entity, had the acquisitions occurred at January 1, 2013, are provided below. This unaudited pro forma information has been derived from historical information and is for illustrative purposes only. The unaudited pro forma financial information does not attempt to predict or suggest future results. It also does not necessarily reflect what the historical results of the combined company would have been had the companies been combined during this period.

	Total		Income
	Revenue		(Loss)
	(dollars in thousands)
	(unaudited)
Pro forma results for the nine months ended September 30, 2013	$	289,691	$	(18,792)

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4. PROPERTY AND EQUIPMENT

Property and equipment consists of the following:

	September 30,		December 31,
	2014		2013
	(dollars in thousands)
	(unaudited)
OIL AND NATURAL GAS PROPERTIES
Unproved properties	$	81,711	$	86,721
Accumulated impairment		(3,995)		(7,356)
Unproved properties, net		77,716		79,365
Proved oil and natural gas properties		1,345,326		1,405,658
Accumulated depreciation, depletion, amortization and impairment		(728,357)		(793,253)
Proved oil and natural gas properties, net		616,969		612,405
TOTAL OIL AND NATURAL GAS PROPERTIES, net		694,685		691,770
LAND		2,166		1,418
OTHER PROPERTY AND EQUIPMENT
Office furniture and equipment, vehicles		16,192		13,802
Accumulated depreciation		(7,884)		(6,120)
OTHER PROPERTY AND EQUIPMENT, net		8,308		7,682
TOTAL PROPERTY AND EQUIPMENT, net	$	705,159	$	700,870

Capitalized exploratory well costs

Deferred exploratory well costs were $6.6 million and $18.4 million at September 30, 2014 and December 31, 2013, respectively.  The decrease in deferred costs during 2014 is primarily the result of the transfer of $13.5 million for the costs of a New Mexico exploratory well to dry hole expense.  As of September 30, 2014 deferred exploratory well costs include approximately $5.3 million capitalized for greater than one year.

5. FAIR VALUE DISCLOSURES

We follow the guidance of ASC 820, “Fair Value Measurements and Disclosures,” in the estimation of fair values. ASC 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to defined “levels,” which are based on the reliability of the evidence used to determine fair value, with Level 1 being the most reliable and Level 3 the least 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 and the Turnbull Wakeman option pricing models to estimate the fair values of oil and natural gas derivative contracts. Inputs to these models 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.

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 $74.1 million were written down to their fair value of $46.2 million, resulting in an impairment charge of $27.9 million for the nine months ended September 30,  2014. 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 $13.8 million were written down to their fair value of $5.1 million, resulting in an impairment charge of $8.7 million for the three months ended September 30, 2014.  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. 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.

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New additions to asset retirement obligations result from estimations for new properties, and fair values for them are categorized as Level 3. Such estimations are based on present value techniques that utilize company-specific information for such inputs as cost and timing of plugging and abandonment of wells and facilities. We  recorded $0.8 million and $0.8 million in additions to asset retirement obligations measured at fair value during the  nine months ended September  30, 2014 and 2013, respectively.

The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of September  30, 2014 and December 31, 2013, 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, 2014 (unaudited):
Financial Assets:
Derivative contracts for oil and natural gas		—	$	30,027		—	$	30,027
Financial Liabilities:
Derivative contracts for oil and natural gas		—	$	21,631		—	$	21,631
At December 31, 2013:
Financial Assets:
Derivative contracts for oil and natural gas		—	$	27,850		—	$	27,850
Financial Liabilities:
Derivative contracts for oil and natural gas		—	$	27,842		—	$	27,842

The amounts above are presented on a gross basis; presentation on our consolidated balance sheets utilizes netting of assets and liabilities with the same counterparty where master netting agreements are in place. For additional information on derivative contracts, see Note 6.  

6. DERIVATIVE FINANCIAL INSTRUMENTS

We account for our derivative contracts under the provisions of ASC 815, “Derivatives and Hedging.” We have entered into forward-swap contracts and collar contracts to reduce our exposure to price risk in the spot market for oil and natural gas. We also have utilized 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 8 below, and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the credit facility. The contracts settle monthly and are scheduled to coincide with either oil production equivalent to barrels (Bbl) per month or gas production equivalent to volumes in millions of British thermal units (MMbtu) per month. The contracts represent agreements between us and the counter-parties to exchange cash based on a designated price, or in the case of financial basis hedging contracts, based on a designated price differential between various benchmark prices. Cash settlement occurs monthly. No derivative contracts have been entered into for trading purposes. 

We have not designated any of our derivative contracts as fair value or cash flow hedges; accordingly we use mark-to-market accounting, recognizing changes in the fair value of derivative contracts in the consolidated statement of operations at each reporting date.

Derivative contracts are subject to master netting arrangements and are presented on a net basis in the consolidated balance sheets. This netting can cause derivative assets to be ultimately presented in a (liability) account on the consolidated balance sheets. Likewise, derivative (liabilities) could be presented in an asset account.    

The following table summarizes the fair value (see Note 5 for further discussion of fair value) and classification of our derivative instruments, none of which have been designated as hedging instruments under ASC 815. 

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Fair Values of Derivative Contracts

					Net Fair
	Gross		Gross amounts		Value of Assets
September 30, 2014	Fair Value		offset against assets		presented in
Balance sheet location	of Assets		in the Balance Sheet		the Balance Sheet
	(dollars in thousands)
	(unaudited)
Derivative financial instruments, current assets	$	13,580	$	(6,203)	$	7,377
Derivative financial instruments, long-term assets		16,447		(14,665)		1,782
Total	$	30,027	$	(20,868)	$	9,159

					��
						Net Fair
	Gross		Gross amounts			Value of Liabilities
September 30, 2014	Fair Value		offset against liabilities			presented in
Balance sheet location	of Liabilities		in the Balance Sheet			the Balance Sheet
	(dollars in thousands)
	(unaudited)
Derivative financial instruments, current liabilities	$	6,203	$	(6,203)		$	—
Derivative financial instruments, long-term liabilities		15,428		(14,665)			763
Total	$	21,631	$	(20,868)		$	763

					Net Fair
	Gross		Gross amounts		Value of Assets
December 31, 2013	Fair Value		offset against assets		presented in
Balance sheet location	of Assets		in the Balance Sheet		the Balance Sheet
	(dollars in thousands)
Derivative financial instruments, current assets	$	13,218	$	(7,646)	$	5,572
Derivative financial instruments, long-term assets		14,632		(11,227)		3,405
Total	$	27,850	$	(18,873)	$	8,977

					Net Fair
	Gross		Gross amounts		Value of Liabilities
December 31, 2013	Fair Value		offset against liabilities		presented in
Balance sheet location	of Liabilities		in the Balance Sheet		the Balance Sheet
	(dollars in thousands)
Derivative financial instruments, current liabilities	$	12,129	$	(7,646)	$	4,483
Derivative financial instruments, long-term liabilities		15,713		(11,227)		4,486
Total	$	27,842	$	(18,873)	$	8,969

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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	September 30,				September 30,
instruments under ASC 815	Gain (Loss)	2014		2013		2014		2013
		(dollars in thousands)
		(unaudited)
Oil commodity contracts	Gain (loss) —
	oil and natural gas
	derivative contracts	$	33,035	$	(22,898)	$	4,525	$	(10,688)
Natural gas commodity contracts	Gain (loss) —
	oil and natural gas
	derivative contracts		6,876		2,218		(42)		3,833
Total gains (losses) from
derivatives not designated as hedges		$	39,911	$	(20,680)	$	4,483	$	(6,855)

Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow us, so long as we are not a defaulting party, after a default or the occurrence of a termination event, to set-off an unpaid hedging agreement receivable against the interest of the counterparty in any outstanding balance under the credit facility.

If a counterparty were to default in payment of an obligation under the master derivative agreements, we could be exposed to commodity price fluctuations, and the protection intended by the hedge could be lost. The value of our derivative financial instruments would be impacted.

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We had the following open derivative contracts for natural gas at September  30, 2014 (unaudited):  

NATURAL GAS DERIVATIVE CONTRACTS

	Volume in	Weighted		Range
Period and Type of Contract	MMBtu	Average		High		Low
2014
Price Swap Contracts	1,765,000	$	4.50	$	5.60	$	4.01
Collar Contracts
Short Call Options	2,739,000		5.41		7.92		4.75
Long Put Options	760,000		4.74		5.50		4.25
Long Call Options	1,569,871		5.63		7.92		4.50
Short Put Options	2,268,800		3.52		4.00		3.00
2015
Price Swap Contracts	3,832,500		5.07		5.91		4.31
Collar Contracts
Short Call Options	7,750,000		4.59		5.75		4.51
Long Put Options	8,113,500		4.01		5.00		3.50
Long Call Options	495,000		4.31		4.31		4.31
Short Put Options	9,116,000		3.34		4.45		3.25
2016
Price Swap Contracts	8,418,000		4.22		4.23		4.22
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	1,681,100		3.64		4.00		3.50
2017
Collar Contracts
Short Call Options	6,570,000		5.00		5.00		4.98
Long Put Options	6,570,000		4.50		4.50		4.50
Short Put Options	6,570,000		4.00		4.00		4.00
2018
Collar Contracts
Short Call Options	5,475,000		5.50		5.53		5.48
Long Put Options	5,475,000		4.50		4.50		4.50
Short Put Options	5,475,000		4.00		4.00		4.00

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We had the following open derivative contracts for crude oil at September  30, 2014 (unaudited):  

OIL DERIVATIVE CONTRACTS

	Volume	Weighted		Range
Period and Type of Contract	in Bbls	Average		High		Low
2014
Price Swap Contracts	430,100	$	95.80	$	105.48	$	87.50
Collar Contracts
Short Call Options	255,760		104.00		111.30		97.00
Long Put Options	259,900		91.59		95.00		70.00
Long Call Options	310,960		101.83		110.00		90.00
Short Put Options	286,764		74.39		80.00		65.00
2015
Price Swap Contracts	1,587,000		94.44		99.30		86.45
Collar Contracts
Short Call Options	392,350		114.10		135.98		95.50
Long Put Options	1,049,350		85.78		90.00		85.00
Short Put Options	2,363,350		70.81		75.00		60.00
2016
Price Swap Contracts	366,000		93.00		94.92		85.35
Collar Contracts
Short Call Options	859,700		107.97		130.00		103.87
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		107.99		113.83		104.15
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		104.39		104.65		104.15
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, and counterparty, but opposite as to direction (long and short), the volumes and average prices have been netted in the two tables above. Prices stated in the table above for oil may settle against either the NYMEX or Brent ICE indices or may reflect a mix of positions settling on these two indices. 

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7. ASSET RETIREMENT OBLIGATIONS

A summary of the changes in asset retirement obligations is included in the table below (unaudited, dollars in thousands):

Balance, beginning of year	$	56,023
Liabilities incurred		760
Liabilities settled		(3,278)
Liabilities transferred in sales of properties		(1,868)
Revisions to estimates		5,817
Accretion expense		1,536
Balance, September 30, 2014		58,990
Less: Current portion		7,065
Long term portion	$	51,925

The total revisions include $3.1 million related to additions to oil and natural gas properties.

8. LONG-TERM DEBT AND NOTES PAYABLE TO FOUNDER

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

	September 30,		December 31,
	2014		2013
	(dollars in thousands)
	(unaudited)
Credit Facility	$	247,520	$	319,290
Senior Notes , net of discount		447,961		447,578
Total long-term debt	$	695,481	$	766,868
Notes payable to founder	$	24,235	$	23,331

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, 2014, the borrowing base under the facility was $350 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 weighted average rate on outstanding borrowings was 2.50% as of September  30, 2014 and 2.75% as of December 31, 2013. 

The credit facility contains customary covenants including, among others, defined financial covenants, including minimum working capital levels (the ratio of current assets plus the unused borrowing base, to current liabilities, excluding assets and liabilities related to derivative contracts) of 1.0 to 1.0, minimum coverage of interest expenses of 3.0 to 1.0, and maximum leverage of 4.00 to 1.00.  The interest coverage and leverage ratios refer to the ratio of earnings before interest, taxes, depreciation, depletion, amortization, and exploration expense (“EBITDAX”, as defined more specifically in the credit agreement) to interest expense and to total debt (as defined), respectively. Financial ratios are calculated quarterly using EBITDAX for the most recent twelve months.   As of September  30, 2014, we were in compliance with all covenants.

Senior Notes. We have $450 million in outstanding registered senior notes due October 15, 2018 that carry a stated interest rate of 9.625% and an effective rate of 9.783%.  Interest is payable semi-annually each April 15th and October 15th.  The senior notes are unsecured and are general obligations of the Company, 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 $2.0 million and $2.4 million at September  30, 2014 and December 31, 2013, respectively.

The senior notes contain an optional redemption provision that began on October 15, 2014 allowing us to retire the principal outstanding, in whole or in part, at 104.813%.   Additional optional redemption provisions allow for retirement at 102.406% and 100.0% beginning on each of October 15, 2015 and 2016, respectively.  

Notes Payable to Founder. We have notes payable to our founder that bear simple interest at 10% with a balance of $24.2 million and $23.3 million at September  30, 2014 and December 31, 2013, respectively.  The maturity date was extended from December 31, 2018

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to December 31, 2021 on March 25, 2014.  Interest and principal are payable at maturity. The notes are convertible into shares of our Class B partner, Alta Mesa Investment Holdings, Inc., common stock upon certain conditions in the event of an initial public offering. 

These founder notes are unsecured and subordinate to all debt. In connection with the March 25, 2014 recapitalization of our Class B partner described in Note 12, the founder notes were amended and restated to subordinate them to the paid in kind (“PIK”) notes of our Class B partner.  The founder notes were also subordinated to the rights of the holders of Class B units to receive distributions under our amended partnership agreement and subordinated to the rights of the holders of Series B Preferred Stock to receive payments. 

Interest on the notes payable to our founder amounted to $0.9 million and $0.9 million for the nine months ended September  30, 2014 and 2013, respectively, and $0.3 million and $0.3 million for the three months ended September 30, 2014 and 2013, respectively. Such amounts have been added to the balance of the founder notes.

9. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

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

	September 30,		December 31,
	2014		2013
	(dollars in thousands)
	(unaudited)
Capital expenditures	$	37,474	$	18,629
Revenues and royalties payable		8,463		9,699
Operating expenses/taxes		28,500		17,071
Interest		19,936		9,146
Compensation		8,058		8,862
Other		1,914		2,711
Total accrued liabilities		104,345		66,118
Accounts payable		32,453		29,977
Accounts payable and accrued liabilities	$	136,798	$	96,095

10. COMMITMENTS AND CONTINGENCIES

Contingencies

Board of Commissioners of the Southeast Louisiana Flood Protection Authority – East:   On July 24, 2013, the Board of Commissioners of the Southeast Louisiana Flood Protection Authority – East sued us and approximately 100 other energy companies for long-term damage to the wetlands in southeast Louisiana.  Case No. 2013-6911 was filed in state court and subsequently remanded to federal court.  The plaintiff seeks damages and injunctive relief in the form of abatement and restoration of wetlands, alleging that the activities of the oil and gas industry over the past century have contributed significantly to the degradation of the wetlands that protect the populated areas in and around New Orleans from storm surge and other extreme weather effects.  The plaintiff alleges damages from increased costs of providing man-made storm protection structures, and emphasizes the destructive effect of canals built by the oil and gas industry.  Legal arguments include breach of the restoration and maintenance clauses of contracts with the State of Louisiana for drilling, dredging, and right-of-way agreements for pipelines.  Other legal arguments include negligence, strict liability, natural servitude of drain, public nuisance and private nuisance.   Our wholly-owned subsidiary The Meridian Resource & Exploration LLC is named as a defendant with 32 wells, two dredging permits and four right of way agreements in the relevant area.  Almost all of these wells are inactive. In June 2014, Act 544 of the Louisiana Legislature was enacted, stating that the plaintiff does not have the authority to bring this suit.  However, the constitutionality of Act 544 may be litigated, and this development does not end the litigation to which we are a party.

The overall exposure related to this lawsuit is not currently determinable.  While an adverse judgment against us might be possible, we intend to vigorously defend the case.  We have not provided any amount for this matter in our consolidated financial statements at September  30, 2014.

Environmental claims: Various landowners have sued the Company and/or our wholly owned subsidiaries, in lawsuits concerning several fields in which we have or historically had operations in Louisiana.  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

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the plaintiffs’ lands from alleged contamination and otherwise from our 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 material amounts for these claims in our consolidated financial statements at September  30, 2014.

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.  Management has established a liability for soil contamination in Florida of $1.1 million and $1.1 million at September  30,  2014 and December 31, 2013, respectively, based on our undiscounted engineering estimates. The obligations are included in other long-term liabilities in the accompanying consolidated balance sheets.  

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 and/or other forms of settlement, such as cash, once a final resolution to the title dispute is made.

Performance appreciation rights:  In the third quarter of 2014 we adopted the Alta Mesa Holdings, LP Amended and Restated Performance Appreciation Rights Plan (the “Plan”), effective September 24, 2014. The Plan is intended to provide incentive compensation to key employees and consultants who make significant contributions to the Company.  Under the Plan, participants are granted Performance Appreciation Rights (“PARs”) with a stipulated initial value.  The PARs vest over time (as specified in each grant, typically five years) and entitle the owner to receive a cash amount equal to the increase, if any, between the initial stipulated value and the designated value of the PAR on the payment valuation date.  The payment valuation date is the earlier of a liquidity event (as defined in the Plan, but generally intended to be either a recapitalization or an initial public offering of Company equity) or as selected by the participant, but no earlier than five years from the end of the year of the grant.  Both the initial designated value and the designated payment value of the PAR are determined by the Plan’s administrative committee,  composed of members of our board of directors.  In the case of a liquidity event, the designated value of all PARs is to be based on the net sale proceeds (as defined in the Plan) from the liquidity event.  After any payment valuation date, regardless of payment or none, vested PARs expire. During the third quarter of 2014 we granted 261,500 PARs at a weighted average initial value of $32.93.  We are unable to express an opinion with respect to the likelihood of a qualifying liquidity event which would result in any payment under the Plan or to estimate any amount which may become payable under the Plan.  We consider the possibility of payment at a fixed determination date absent a positive liquidity event to be remote.  Therefore, we have not provided any amount for this contingent liability in our consolidated financial statements at September 30, 2014.

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.

11. SIGNIFICANT RISKS AND UNCERTAINTIES

Our business makes us vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future. By definition, proved reserves are based on analysis of current oil and natural gas prices. Price declines reduce the estimated value of proved reserves and may increase annual amortization expense (which is based on proved reserves).  Price declines may also result in impairments, or non-cash write-downs, of the value of our oil and natural gas properties. We mitigate a portion of this vulnerability by entering into oil and natural gas price derivative contracts. See Note 6.  

12. PARTNERS’ CAPITAL (DEFICIT)

Our business and affairs are managed by Alta Mesa Holdings GP, LLC, our general partner (“General Partner”) as provided in the Alta Mesa Holdings, LP partnership agreement.  Our partnership agreement provides for two classes of limited partners.  Class A partners include our founder and other parties.  Our Class B  partner is Alta Mesa Investment Holdings, Inc. (“AMIH”).  Prior to March 25, 2014, AMIH was an affiliate of Denham Capital Management LP, a private equity firm focused on energy and commodities.

On March 25, 2014, AMIH completed a $350 million recapitalization with an investment from Highbridge Principal Strategies LLC (“Highbridge”).  Proceeds from the investment were used in part to purchase the investment of Denham Capital Management LP in AMIH. Highbridge received convertible PIK preferred stock in AMIH and senior PIK notes from AMIH.  We expanded our Board of Directors to include one member nominated by Highbridge and one new employee member, our Chief Financial Officer, Michael A. McCabe.  AMIH has subsequently changed its name to High Mesa, Inc.  High Mesa, Inc. is our sole Class B partner.

In connection with the recapitalization, our partnership agreement was amended and restated to provide, among other things, that all distributions under the partnership agreement shall first be made to holders of Class B Units, until all principal and interest has been extinguished under the senior PIK notes issued to Highbridge.  After such extinguishment of the senior PIK notes, distributions shall

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then be made to holders of Class A and Class B Units pursuant to the distribution formulas set forth in the amended partnership agreement. 

13. SUBSIDIARY GUARANTORS

All of our material wholly-owned subsidiaries are guarantors under the terms of both our senior notes and our credit facility. Our consolidated financial statements reflect the combined financial position of these subsidiary guarantors. Our parent company, Alta Mesa Holdings, LP, has no independent operations, assets, or liabilities. The guarantees are full and unconditional and joint and several. Those subsidiaries which are not wholly owned and are not guarantors are minor. There are no restrictions on dividends, distributions, loans, or other transfers of funds from the subsidiary guarantors to our parent company.

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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, 2013 (“2013 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 on the Sooner Trend area of the Anadarko Basin in Oklahoma, our Weeks Island field in South Louisiana, and our Eagle Ford Shale play in Karnes County, Texas.  Our operations also include other oil and natural gas interests in Texas and Louisiana.

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 low oil and natural gas prices 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

The price of oil is important to our revenues due to our current focus on development of oil reserves and exploration for oil.  Crude oil prices are subject to significant changes. Factors affecting the price of oil include worldwide economic conditions, including the European credit crisis, geopolitical activities, including developments in the Middle East, Ukraine, and South America, 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.  Crude oil prices for next month futures contracts for West Texas Intermediate traded on the NYMEX (“NYMEX WTI”) averaged approximately $98 in 2013 and $100 for the first nine months of 2014.  During September 2014 NYMEX WTI prices averaged approximately $93, further declining to an average of approximately $84 for October 2014. 

Natural gas prices are also subject to significant changes.  Declining prices in the last several years reached a low point in the first half of 2012 as reflected in the May 2012 NYMEX Henry Hub futures contract closing at $2.04 per MMbtu. Since then, prices have generally increased,  as indicated by the September 2014 NYMEX Henry Hub futures contract closing at $3.96 per MMbtu.  We received an average price of $4.18 per Mcf for natural gas in the third quarter of 2014 before the effects of hedging.  

The relatively low level of natural gas prices prompted our shift in emphasis to oil and liquids over the past several years.  Low natural gas prices have impacted our earnings by necessitating impairment write-downs in some of our natural gas properties, either directly by decreasing the market values of the properties, or indirectly, by lowering rates of return on natural gas development projects and increasing the chance of impairment write-downs.  We recorded non-cash impairment expenses of $143 million and $96 million during the years ended December 31, 2013 and 2012, respectively.  For the third quarter of 2014 natural gas prices have been relatively stable.  Impairment expense was $27.9 million for the nine months ended September  30, 2014.  It is possible that further declines in oil and/or natural gas prices may result in additional impairments.

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 gain / loss from derivative contracts, which includes both the non-cash increase or decrease in the fair value of derivative contracts, as well as the effect of cash settlements of derivative contracts during the period. In the first nine months of 2014, we recognized a net gain on our derivative contracts of $4.5 million, which includes $3.9 million in cash settlements expended for derivative contracts. The objective of our hedging program is that, over time, the combination of settlement gains and losses from derivative contracts with ordinary oil and natural gas revenues will produce relative revenue stability. However, in the short term, both settlements and fair value changes in our derivative contracts can significantly impact our results of operations, and we expect these gains and losses to continue to reflect changes in oil and natural gas prices.

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We have hedged approximately 90%  of our forecasted production of proved developed producing reserves over the next five years at weighted average annual floor prices ranging from $4.29 per MMbtu to $4.57 per MMbtu for natural gas and $80.00 per Bbl to $94.21 per Bbl for oil.  If natural gas and/or oil prices decline for an extended period of time, we may be unable to replace expiring hedge contracts or enter new contracts for additional oil and natural gas production at favorable prices.

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 effectiveness and efficiency of our production operations, the success of our drilling program and our inventory of drilling prospects. In addition, we face the challenge of natural production declines. We attempt to overcome this natural decline primarily through development of 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.

Developments in 2014

On March 25, 2014, we sold a portion of our proved oil reserves, approximately 7.7 MMBOE, in our Eagleville field in South Texas. The initial cash purchase price was $173 million, subsequently adjusted to approximately $168 million for settlement adjustments through September 30, 2014.  Proceeds were used to reduce the outstanding borrowings under our revolving credit facility.  The sale was structured to provide us with continuing net revenues from the sold properties through 2016, and we will continue to develop additional Eagleville wells at 70% of our original working interest.  Total reserves we retained are estimated as 7.3 MMBOE, of which 91% is considered proved undeveloped based on classifications from our reserve report as of December 31, 2013.  This partial sale provided us cash for investment in new areas without relinquishing our position in the Eagle Ford Shale.

Throughout this report, revenue and operating data include the portion of our Eagleville assets that were sold in the first quarter of 2014 through the transaction closing date of March 25, 2014.  The Eagleville field contributed approximately $22.5 million in revenues (93% of which was from oil),  $1.5 million in total operating expenses and production taxes, and $7.2 million in depreciation, depletion, and amortization for the third quarter of 2014.   Production from Eagleville for the third quarter of 2014 was 277 MBOE (79% of which was from oil). For the third quarter of 2013, the Eagleville field produced 309 MBOE (87% from oil) and $29.9 million in revenues (95% from oil), $3.6 million in total operating expenses and production taxes, and $6.5 million in depreciation, depletion, and amortization.

 On September 19, 2014, we sold our remaining interests in the Hilltop field for a cash payment of $41.6 million, subject to customary settlement adjustments.  As of the date of sale, estimated proved reserves associated with these properties were 29.8 BCFE.  This East Texas field produced primarily dry gas.  On August 7, 2014, we sold our interests in the Anne Parsons field for a cash payment of $8.6 million, subject to customary settlement adjustments.  As of the date of sale, estimated proved reserves associated with these properties were 4.8 BCFE.  This East Texas field produced primarily natural gas and natural gas liquids.

On March 25, 2014, our Class B partner, Alta Mesa Investment Holdings, Inc. (“AMIH”), completed a $350 million recapitalization with an investment from Highbridge Principal Strategies, LLC (“Highbridge”).  Proceeds from the investment were used in part to purchase the investment of Denham Capital Management, L.P. in AMIH.  Highbridge received convertible paid in kind (“PIK”) preferred stock in AMIH and senior PIK notes from AMIH.  We expanded our Board of Directors to include one member nominated by Highbridge and one new management member, our Chief Financial Officer, Michael A. McCabe.  AMIH remains our sole Class B partner.  AMIH has subsequently changed its name to High Mesa, Inc.

Operations Update

Sooner Trend.Our assets in the Sooner Trend in Oklahoma are large, contiguous acreage blocks with multiple productive zones at depths generally between 4,000 feet and 8,000 feet.  Our focus is the continued implementation of a multi-year, multi-rig program to develop several pay zones with horizontal drilling and multi-stage hydraulic fracturing.  In the third quarter of 2014, we completed ten horizontal wells in the Meramec formation inSooner Trend as well as three horizontal wells in the Oswego formation and one in the Cleveland formation. We had 13 horizontal wells in progress as of the end of the third quarter of 2014, primarily targeting the Meramec formation, three of which have subsequently been completed.  Five of our completed wells and six of the wells in progress for the third quarter of 2014 were non-operated.

As of September 30, 2014, we had two drilling rigs operating in Sooner Trend for horizontal development, which we plan to increase to three rigs during the remainder of 2014, targeting the Meramec section of the Mississippian Lime , the Oswego Lime, the

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Hunton Lime, and the Woodford Shale.  We expect to continue to participate in other horizontal wells as a non-operator, primarily targeting the Oswego Lime, Meramec and Hunton Lime. 

Production from our Sooner Trend properties in the third quarter of 2014 was approximately 5,300 BOE/Day net to our interest, 80% oil and natural gas liquids, as compared to approximately 1,400 BOE/Day, 66% oil and natural gas liquids, for the third quarter of 2013.

Weeks Island. We are targeting updip oil reserves and undrained fault blocks in this large oil field surrounding a salt dome in South Louisiana.  We completed four wells during the third quarter of 2014, one of which we chose to dually complete and is producing from two drill-strings, with two wells in progress as of the end of the quarter.  In addition, we drilled one dry hole during the quarter.  Our plans are to utilize at least one drilling rig continuously through the end of 2014.  Additionally, we expect to have at least one workover rig continuously operating in this field, primarily for completing new wells and recompleting older wells to new producing zones. 

Production from Weeks Island in the third quarter of 2014 was approximately 6,000 BOE/Day, net to our interest, 82% oil, as compared to 3,300 BOE/Day, 89% oil, for the third quarter of 2013.  Production at Weeks Island has remained above 4,000 BOE/Day, net to our interest, since November 2013.  

Eagleville field.    During the third quarter of 2014, we completed 22 wells (3 net wells) in the Eagle Ford Shale formation in our Eagleville field.  An additional 16 wells (1.5 net wells) were in progress at the end of the quarter, with 13 of those subsequently completed as producers through mid-November 2014.  As of September 30, 2014, we had working interests in 157 producing wells in this field, which are primarily operated by Murphy Oil Corporation (“Murphy”). Our average working interest in these wells is approximately 8.5%.  All working interests mentioned here reflect ownership after the sale of a portion of our Eagleville interests, as described earlier.

For the third quarter of 2014, production from the Eagleville field was approximately 3,000 BOE/Day net to our interest, as compared to 3,400 BOE/Day in the third quarter of 2013.   The decrease in production reflects the decrease in our working interest due to the partial sale of Eagleville during the first quarter of 2014.   Murphy historically has operated two to three drilling rigs on our acreage.

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Results of Operations: Three Months Ended September  30, 2014 v. Three Months Ended September  30, 2013

	Three Months Ended September 30,				Increase
	2014		2013		(Decrease)		% Change
	(dollars in thousands, except average sales prices and
	unit costs)
Summary Operating Information:
Net Production:
Oil (MBbls)		1,063		749		314	42%
Natural gas (MMcf)		3,872		4,156		(284)	(7)%
Natural gas liquids (MBbls)		142		70		72	103%
Total oil equivalent (MBOE)		1,850		1,512		338	22%
Average daily oil production (MBOE/Day)		20.1		16.4		3.7	22%
Average Sales Price:
Oil (per Bbl) including settlements of derivative contracts	$	96.99	$	102.73	$	(5.74)	(6)%
Oil (per Bbl) excluding settlements of derivative contracts		98.00		108.27		(10.27)	(9)%
Natural gas (per Mcf) including settlements of derivative contracts		4.62		4.91		(0.29)	(6)%
Natural gas (per Mcf) excluding settlements of derivative contracts		4.18		3.72		0.46	12%
Natural gas liquids (per Bbl) (1)		33.78		42.82		(9.04)	(21)%
Combined (per BOE) including settlements of derivative contracts		67.99		66.37		1.62	2%
Hedging Activities:
Settlements of derivatives received (paid), oil	$	(1,068)	$	(4,150)	$	3,082	74%
Settlements of derivatives received, natural gas		1,724		4,925		(3,201)	(65)%
Summary Financial Information
Revenues
Oil	$	104,196	$	81,088	$	23,108	28%
Natural gas		16,165		15,470		695	4%
Natural gas liquids		4,787		3,006		1,781	59%
Other revenues (loss)		496		(48)		544	1133%
Gain (loss) on sale of assets		18,556		(1,077)		19,633	1823%
Gain (loss) — oil and natural gas derivative contracts		39,911		(20,680)		60,591	293%
		184,111		77,759		106,352	137%
Expenses
Lease and plant operating expense		18,440		18,031		409	2%
Production and ad valorem taxes		8,357		8,130		227	3%
Workover expense		2,316		3,428		(1,112)	(32)%
Exploration expense		15,779		13,508		2,271	17%
Depreciation, depletion, and amortization expense		39,880		30,667		9,213	30%
Impairment expense		8,706		2,072		6,634	320%
Accretion expense		365		460		(95)	(21)%
General and administrative expense		17,243		13,378		3,865	29%
Interest expense, net		13,699		13,822		(123)	(1)%
Provision (benefit) for state income taxes		—		—		—	NA
Net income (loss)	$	59,326	$	(25,737)	$	85,063	331%
Average Unit Costs per BOE:
Lease and plant operating expense	$	9.97	$	11.93	$	(1.96)	(16)%
Production and ad valorem tax expense		4.52		5.38		(0.86)	(16)%
Workover expense		1.25		2.27		(1.02)	(45)%
Exploration expense		8.53		8.93		(0.40)	(4)%
Depreciation, depletion and amortization expense		21.56		20.28		1.28	6%
General and administrative expense		9.32		8.85		0.47	5%

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

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Revenues

Oil revenues for the three months ended September  30, 2014 increased $23.1 million, or 28%, to $104.2 million from $81.1 million for the corresponding period in 2013. The increase in revenue was attributable to increased production volumes partially offset by a decrease in the average price. Approximately $34.0 million of the increase was due to an increase in production of 314 MBbls, or 42%. This increase is primarily due to production from Sooner Trend and Weeks Island fields.  The Sooner Trend production increased by 227 MBbls, from 75 MBbls in the third quarter of 2013 to 302 MBbls in the corresponding period of 2014. Weeks Island increased 181 MBbls, from 272 MBbls in the third quarter of 2013 to 453 MBbls for the third quarter of 2014.  As described above, we sold a portion of our interest in the Eagleville field on March 25, 2014.  Our Eagleville field produced 267 MBbls and 219 MBbls in the third quarter of 2013 and 2014, respectively.  The average price of oil exclusive of settlements of derivative contracts decreased 9%  in the third quarter of 2014, resulting in a decrease in oil revenues of approximately $10.9 million. The overall price including settlements of hedging contracts decreased 6% from $102.73 per Bbl in the third quarter of 2013 to  $96.99 per Bbl in the third quarter of 2014.

Natural gas revenues for the three months ended September  30, 2014 increased $0.7 million, or 4%, to $16.2 million from $15.5 million for the same period in 2013. The increase in natural gas revenue was attributable to an increase in average price partially offset by decreased production during the third quarter of 2014.    The average price of natural gas exclusive of settlements of derivative contracts increased 12% in the third quarter of 2014, resulting in an increase in natural gas revenues of approximately $1.8 million.  The overall price including settlements of derivative contracts decreased  6% from $4.91 per Mcf in the third quarter of 2013 to $4.62 per Mcf in the third quarter of 2014.  An approximate  $1.1 million 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 portfolio of assets.  Hilltop field, our largest natural gas field, produced 0.9 BCF in the third quarter of 2014, compared to 1.5 BCF in the third quarter of 2013.  In the fourth quarter of 2013, we sold a portion of our interest in this field.  At the end of the third quarter of 2014, we sold our remaining interest in the field.

Natural gas liquids revenues increased $1.8 million, or 59%, during the third quarter of 2014 to $4.8 million from $3.0 million in the same period in 2013. The increase in natural gas liquids revenue was attributable to increased production volumes partially offset by a lower average price during the third quarter of 2014.  A  103%  increase in volumes from 70 MBbls to 142 MBbls was partially offset by a decrease in our average price of 21%, from $42.82 per Bbl to $33.78 per Bbl.  The increase in volume is primarily due to an increase in production of 77 MBbls in our Sooner Trend field in Oklahoma.  Eagleville field also impacted sales of natural gas liquids, increasing from 22 MBbls in the third quarter of 2013 to 31 MBbls in the third quarter of 2014.  Partially offsetting these increases, several East Texas fields reflected decreased production in the third quarter of 2014 as compared to the corresponding period of 2013.

Other revenues (loss) increased $0.5 million during the three months ended September  30, 2014 as compared to the three months ended September  30, 2013. The increase is primarily the result of income from our investment in a drilling company recorded in the third quarter of 2014, not present in 2013.  In addition, the third quarter of 2013 reflected a small loss in net rental income from our drilling rig, which we sold during that quarter.  

Gain (loss) on sale of assets was a  gain of $18.6 million in the third quarter of 2014, due primarily to the sale of the remainder of our interest in Hilltop field.  We sold a portion of this field in the fourth quarter of 2013, and the remainder in the third quarter of 2014.  The loss of $1.1 million in the third quarter of 2013 was related to the sale of our drilling rig. 

Gain ( loss)— oil and natural gas derivative contracts was a gain of $39.9 million during the three months ended September  30, 2014 as compared to a loss of $20.7 million during the same period in 2013. 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. Generally, the decrease in oil prices in the third quarter of 2014 positively impacted the value of our derivative contracts for oil. Gas contracts were also positively impacted by a decrease in the price of gas.

Expenses

Lease and plant operating expense increased $0.4 million or 2% in the third quarter of 2014 as compared to the third quarter of 2013, to $18.4 million from $18.0 million, primarily due to an increase in chemicals, marketing and gathering, salt water disposal and compression of $1.7 million partially offset by a decrease in repairs and maintenance and field services of $1.4 million.  The increases are primarily due to new well additions in liquids-rich assets, primarily from Weeks Island and Sooner Trend.  On a per unit basis, lease and plant operating expenses were $9.97 per BOE and $11.93 per BOE for the third quarter of 2014 and 2013, respectively.    

Production and ad valorem taxes increased $0.3 million, or 3%, to $8.4 million for the third quarter of 2014, as compared to $8.1 million for the third quarter of 2013.  Production taxes increased approximately $0.8 million during the third quarter of 2014, to $7.4 million, from $6.6 million for the corresponding period in 2013, following revenues.  Ad valorem taxes decreased approximately

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$0.5 million for the third quarter of 2014 from the corresponding period of 2013.  The decrease is primarily due to the sale of a portion of our Eagleville field in the first quarter of 2014, and to the sale of a portion of our Hilltop field in the fourth quarter of 2013.

Workover expense decreased from the third quarter of 2013 to the third quarter of 2014, from $3.4 million to $2.3 million, respectively. This expense varies depending on activities in the field and is attributable to many different properties.

Exploration expense includes dry hole costs and the costs of our geology department, costs of geological and geophysical data, expired leases, recognition of settlements of asset retirement obligations, and lease rentals. Exploration expense increased from $13.5 million for the third quarter of 2013 to $15.8 million for the third quarter of 2014, primarily due to increases of $3.3 million in seismic and geological expenses, $2.2 million in abandonment costs, and $1.6 million in leasehold expense, offset by a decrease in dry hole expense of $4.8 million.    Seismic and geological costs reflect increased purchases of new seismic data in the third quarter of 2014.  Dry hole expense recorded in the third quarter of 2014 is primarily due to a single well in Weeks Island. 

Depreciation, depletion and amortization increased $9.2 million to $39.9 million for the third quarter of 2014 as compared to an expense of $30.7 million for the third quarter of 2013. On a per unit basis, this expense increased from $20.28 per BOE in the third quarter of 2013 to $21.56 per BOE in the third quarter of 2014. The rate is a function of capitalized costs of proved properties, proved reserves and production by field.

Impairment expense increased from $2.1 million in the third quarter of 2013 to $8.7 million in the third quarter of 2014. 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.  Impairment expense in the third quarter of 2014 consisted primarily of a write-down of our Bayou Biloxi field, a natural gas field in South Louisiana.

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 $0.4 million for the third quarter of 2014 and $0.5 million for the corresponding period in 2013.

General and administrative expense increased $3.8 million for the third quarter of 2014 to $17.2 million from $13.4 million for the third quarter of 2013. The increase is principally due to litigation settlement expenses of approximately $1.0 million and an increase in salaries and benefits of $2.9 million, primarily related to increased expenses for bonus accruals and for executive deferred compensation.

Interest expense, net slightly decreased from $13.8 million to $13.7 million for the third quarters of 2013 and 2014, respectively.  Interest on our credit facility was slightly decreased in the third quarter of 2014 as compared to the third quarter of 2013 due to a lower average balance and slightly lower average interest rate.

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Results of Operations: Nine Months Ended September 30, 2014 v. Nine Months Ended September 30, 2013

	Nine Months Ended September 30,				Increase
	2014		2013		(Decrease)		% Change
	(dollars in thousands, except average sales prices and
	unit costs)
Summary Operating Information:
Net Production:
Oil (MBbls)		2,767		2,094		673	32%
Natural gas (MMcf)		11,441		12,592		(1,151)	(9)%
Natural gas liquids (MBbls)		400		272		128	47%
Total oil equivalent (MBOE)		5,074		4,464		610	14%
Average daily oil production (MBOE/Day)		18.6		16.4		2.2	14%
Average Sales Price:
Oil (per Bbl) including settlements of derivative contracts	$	97.10	$	102.60	$	(5.50)	(5)%
Oil (per Bbl) excluding settlements of derivative contracts		99.93		105.65		(5.72)	(5)%
Natural gas (per Mcf) including settlements of derivative contracts		4.95		5.29		(0.34)	(6)%
Natural gas (per Mcf) excluding settlements of derivative contracts		4.61		3.70		0.91	25%
Natural gas liquids (per Bbl) (1)		36.67		36.93		(0.26)	(1)%
Combined (per BOE) including settlements of derivative contracts		67.01		65.29		1.72	3%
Hedging Activities:
Settlements of derivatives (paid), oil	$	(7,826)	$	(6,374)	$	(1,452)	(23)%
Settlements of derivatives received, natural gas		3,921		19,924		(16,003)	(80)%
Summary Financial Information
Revenues
Oil	$	276,524	$	221,198	$	55,326	25%
Natural gas		52,705		46,652		6,053	13%
Natural gas liquids		14,653		10,030		4,623	46%
Other revenues		784		1,110		(326)	(29)%
Gain (loss) on sale of assets		87,107		(2,267)		89,374	3942%
Gain (loss) — oil and natural gas derivative contracts		4,483		(6,855)		11,338	165%
		436,256		269,868		166,388	62%
Expenses
Lease and plant operating expense		55,022		51,681		3,341	6%
Production and ad valorem taxes		22,985		21,326		1,659	8%
Workover expense		7,279		12,013		(4,734)	(39)%
Exploration expense		44,015		22,374		21,641	97%
Depreciation, depletion, and amortization expense		102,357		83,547		18,810	23%
Impairment expense		27,908		28,618		(710)	(2)%
Accretion expense		1,536		1,352		184	14%
General and administrative expense		55,854		32,139		23,715	74%
Interest expense, net		41,610		40,673		937	2%
Provision (benefit) for state income taxes		283		—		283	NA
Net income (loss)	$	77,407	$	(23,855)	$	101,262	424%
Average Unit Costs per BOE:
Lease and plant operating expense	$	10.84	$	11.58	$	(0.74)	(6)%
Production and ad valorem tax expense		4.53		4.78		(0.25)	(5)%
Workover expense		1.43		2.69		(1.26)	(47)%
Exploration expense		8.67		5.01		3.66	73%
Depreciation, depletion and amortization expense		20.17		18.72		1.45	8%
General and administrative expense		11.01		7.20		3.81	53%

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

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Revenues

Oil revenues for the nine months ended September  30, 2014 increased $55.3 million, or 25%, to $276.5 million from $221.2 million for the corresponding period in 2013. The increase in revenue was attributable to increased production volumes partially offset by a lower average price. Approximately $71.1 million of the increase was due to an increase in production of 673 MBbls, or 32%. This increase is primarily due to production from the Sooner Trend and Weeks Island fields.  The Sooner Trend increased production by 516 MBbls, from 206 MBbls in the first nine months of 2013 to 722 MBbls in the corresponding period of 2014.  Weeks Island increased 437 MBbls, from 718 MBbls in the first nine months of 2013 to 1,155 MBbls for the first nine months of 2014.  As described above, we sold a portion of our interest in the Eagleville field on March 25, 2014.  Our Eagleville field produced 764 MBbls and 588 MBbls in the first nine months of 2013 and 2014, respectively.  The average price of oil exclusive of settlements of derivative contracts decreased 5% in the first nine months of 2014, resulting in a decrease in oil revenues of approximately $15.8 million.  The overall price, including settlements of derivative contracts, decreased 5% from $102.60 per Bbl in the first nine months of 2013 to $97.10 per Bbl in the first nine months of 2014.

Natural gas revenues for the nine months ended September  30, 2014 increased $6.0 million, or 13%, to $52.7 million from $46.7 million for the same period in 2013. The increase in natural gas revenue was attributable to an increase in average price, partially offset by decreased production during the first nine months of 2014.    The average price of natural gas exclusive of settlements of derivative contracts increased 25% in the first nine months of 2014, resulting in an increase in natural gas revenues of approximately $10.3 million.  The overall price, including settlements of derivative contracts, decreased  6% from $5.29 per Mcf in the first nine months of 2013 to $4.95 per Mcf in the first nine months of 2014.  An approximate  $4.3 million decrease in revenues from natural gas was due to a decrease in production of 1.2 BCF, or 9%. This decline is primarily due to an emphasis on liquids-rich assets in our portfolio of assets.  Our Hilltop field, our largest natural gas field, produced 2.9 BCF in the first nine months of 2014, compared to 4.6 BCF in the first nine months of 2013.  In the fourth quarter of 2013, we sold a portion of our interest in this field. At the end of the third quarter of 2014, we sold our remaining interests in the field. 

Natural gas liquids revenues increased $4.6 million, or 46%, during the first nine months of 2014 to $14.7 million from $10.0 million in the same period in 2013. The increase in natural gas liquids revenue was attributable to increased production volumes during the first nine months of 2014.  A  47%  increase in volumes from 272 MBbls to 400 MBbls was slightly offset by a decrease in our average price of 1%, from $36.93 per Bbl to $36.67 per Bbl.  The increase in volume is primarily due to increased production in our Sooner Trend field in Oklahoma.  The partial sale of our interest in the Eagleville field impacted sales of natural gas liquids somewhat.  Eagleville produced 76 MBbls and 83 MBbls of natural gas liquids in the first nine months of 2014 and 2013, respectively.    

Other revenues decreased $0.3 million during the nine months ended September  30, 2014 as compared to the nine months ended September  30, 2013. The decrease is primarily the result of a decrease in rental income from our drilling rig, which we sold during the third quarter of 2013.

Gain (loss) on sale of assets was a gain of $87.1 million in the first nine months of 2014, due to the sale of a portion of our interests in our Eagleville field in the first quarter of 2014, and to the sale of the remainder of our interest in Hilltop field in the third quarter of 2014.  The Eagleville divestiture resulted in a gain of $69.3 million.  The Hilltop sale resulted in a preliminary gain of $18.3 million.  In the fourth quarter of 2013, we sold a portion of our interest in Hilltop field, with a gain on sale of approximately zero.  The Hilltop sale in 2014 completes our exit from this field, which produces dry gas.  The $2.3 million loss in 2013 was related to the sale of a single well and to the sale of our drilling rig. 

Gain (loss) — oil and natural gas derivative contracts was a gain of $4.5 million during the nine months ended September  30, 2014 as compared to a loss of $6.9 million during the same period in 2013. 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 $3.3 million, or 6% in the first nine months of 2014 as compared to the first nine months of 2013, from $51.7 million to $55.0 million, primarily due to an increase in chemicals, compression, marketing and gathering, salt water disposal and overhead expenses totaling $6.2 million, partially offset by a decrease in repairs and maintenance and field services of $2.9 million.  The increases are primarily due to costs incurred on liquids-rich assets, primarily in fields such as Weeks Island and Sooner Trend.  On a per unit basis, lease and plant operating expenses were $10.84 per BOE and $11.58 per BOE for the first nine months of 2014 and 2013, respectively.    

Production and ad valorem taxes increased $1.7 million, or 8%, to $23.0 million for the first nine months of 2014, as compared to $21.3 million for the first nine months of 2013.  Production taxes increased $2.3 million for the first nine months of 2014 as compared to the corresponding period of 2013, following revenues from product sales, partially offset by a refund received in the second quarter of 2014.  Production taxes are impacted by our mix of sales between oil and natural gas, as well as by varying rates and

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exemption opportunities in different states.  Ad valorem taxes decreased $0.6 million, primarily due to the sale of a portion of our Eagleville field in the first quarter of 2014, and to the sale of a portion of our Hilltop field in the fourth quarter of 2013.

Workover expense decreased from the first nine months of 2013 to the first nine months of 2014, from $12.0 million to $7.3 million, respectively. This expense varies depending on activities in the field and is attributable to many different properties.

Exploration expense includes dry hole costs and the costs of our geology department, costs of geological and geophysical data, expired leases, recognition of settlements of asset retirement obligations, and lease rentals. Exploration expense increased $21.6 million, from $22.4 million for the first nine months of 2013 to $44.0 million for the first nine months of 2014, primarily due to an increase of $11.2 million in dry hole expense, increases in seismic and geological expenses of $6.7 million,  an increase in abandonment costs of $2.7 million, and an increase in lease expenses of $1.0 million. Dry hole expense for the first nine months of 2014 included approximately $18.6 million for two wells drilled in New Mexico and $4.7 million for a well in Weeks Island.  Seismic and geological costs reflect increased purchases of new seismic data in the first nine months of 2014.

Depreciation, depletion and amortization increased $18.8 million to $102.3 million for the first nine months of 2014 as compared to an expense of $83.5 million for the first nine months of 2013. On a per unit basis, this expense increased from $18.72 per BOE for the first nine months of 2013 to $20.17 per BOE for the first nine months of 2014. The rate is a function of capitalized costs of proved properties, proved reserves and production by field.

Impairment expense decreased from $28.6 million in the first nine months of 2013 to $27.9 million in the first nine months of 2014. 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.  Impairment expense in the first nine months of 2013 included write-downs in several large natural gas fields based primarily on the decline in market prices for natural gas.  The write-down in the first nine months of 2014 was related to several lower-margin fields in Texas and Louisiana.

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 $1.5 million for the first nine months of 2014 and $1.4 million for the corresponding period in 2013.

General and administrative expense increased $23.8 million for the first nine months of 2014 to $55.9 million from $32.1 million for the first nine months of 2013. The increase is partially due to the recapitalization described above and in Note 12 of our consolidated financial statements, which contributed approximately $13.9 million in additional general and administrative expenses. In addition, the first nine months of 2014 reflects litigaton settlement expenses of $3.7 million, and an increase in salaries and benefits of $6.3 million, primarily related to increased expenses for bonus accruals and for executive deferred compensation, in addition to increased headcount as compared to the first nine months of 2013. 

Interest expense, net increased $0.9 million for the first nine months of 2014 to $41.6 million from $40.7 million for the first nine months of 2013.  Interest on our credit facility increased $0.9 million in the first nine months of 2014 as compared to the same period in 2013 due to higher average outstanding balances.

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 2014 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 $360 million during 2014 for exploration and development, of which approximately $290 million has been expended or accrued through September 30, 2014.  Approximately 80% of our 2014 capital budget is allocated to our properties in Eagle Ford Shale, Sooner Trend, and Weeks Island.  In addition, we have set aside approximately $35 million in a restricted account for acquisition expenditures during the fourth quarter of 2014 and the first quarter of 2015.  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 decreased risk of losing significant acreage.

We expect to fund the remainder of our 2014 capital expenditures for exploration, development, and acquisition of producing properties predominantly with cash on hand and cash flows from operations, supplemented by borrowings under our credit facility. If

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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.

Senior Notes

We have $450 million in outstanding registered senior notes due October 15, 2018 that carry a stated interest rate of 9.625% and an effective interest rate of 9.783%. Interest is payable semi-annually each April 15th and October 15th. The senior notes are unsecured and are general obligations of the Company, 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 senior notes contain an optional redemption provision allowing us to retire the principal outstanding, in whole or in part, at 104.813%. Additional optional redemption provisions allow for retirement at 102.406% and 100.0% beginning on each of October 15, 2015 and 2016, respectively.

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.  During the first quarter of 2014, the borrowing base was reduced from $385 million to $285 million as a result of the sale of a portion of our Eagleville properties, and the cash proceeds from the sale were used to pay down the outstanding balance under the credit facility.  The borrowing base was increased to $350 million as of August 5, 2014.  The next redetermination will be as of November 1, 2014.  As of November 12, 2014, outstanding borrowing under the credit facility was $290.0 million, letters of credit totaling $0.9 million were outstanding, and the available unused portion of the borrowing base was $59.1 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, 2014 under the credit facility was 2.50%, which was based on the Eurodollar option.

The credit facility contains customary covenants including, among others, defined financial covenants, including minimum working capital levels (the ratio of current assets plus the unused borrowing base, to current liabilities) of 1.0 to 1.0, minimum coverage of interest expenses of 3.0 to 1.0, and maximum leverage of 4.00 to 1.00.  The interest coverage and leverage ratios refer to the ratio of earnings before interest, taxes, depreciation, depletion, amortization, and exploration expense (“EBITDAX”, as defined more specifically in the credit agreement) to interest expense and to total debt (as defined), respectively. Financial ratios are calculated quarterly.

At September  30, 2014, 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 $157.1 million during the nine months ended September 30, 2014 as compared to $147.2 million during the comparable period in 2013, an increase of $9.9 million. Increased revenues from higher oil production and higher prices received for natural gas totaling $65.7 million were offset by increased expenses.  The most significant increases in expenses were in general and administrative expense ($23.8 million higher), seismic, geological and abandonment expenses (a total increase of $10.4 million),  and settlements of derivative contracts (which provided funds in the first nine months of 2013 but used funds in the corresponding period of 2014, resulting in a total negative variance of $17.5 million).  The net effect of these and other variances in cash-based revenues and expenses was to increase cash flow from operations by approximately $13.4 million for the first nine months of 2014 as compared to the same period in 2013.  Changes in working capital and other assets and liabilities provided $3.5 million less in the first nine months of 2014 than in the corresponding period in 2013.

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Cash flow used in investing activities

Investing activities used cash of $86.1 million during the nine months ended September  30, 2014 as compared to cash used in investing activities of $247.6 million during the comparable period of 2013.  Investment in property and equipment increased by $14.8 million.  Sales of properties provided proceeds of $218.5 million, an increase of $211.1 million over the same period in 2013. In 2014, the sale of a portion of our interest in our Eagleville field provided net proceeds of approximately $168.0 million; the sale of our remaining interests in the Hilltop field provided net proceeds of approximately $41.6 million; and the sale of our interest in the Anne Parsons field in East Texas provided proceeds of approximately $8.6 million.  In the third quarter of 2014 we placed the net proceeds from our sale of Hilltop field into a restricted cash account with a qualified intermediary available for use in a like-kind exchange under Section 1031 of the U.S. Internal Revenue Code.  As of September 30, 2014, the investment of funds in this restricted cash account, net of expenditures for qualifying property during the period, resulted in a use of cash of $34.8 million.  There is no comparable investment in restricted cash in the third quarter of 2013.

Cash flow provided by or used in financing activities

Financing activities used cash of $71.8 million during the nine months ended September  30, 2014 as compared to cash provided by financing of $101.4 million during the comparable period in 2013.  In the first nine months of 2014 we used the proceeds from the Eagleville divestiture to reduce the outstanding balance under our credit facility by $169.3 million, although we also drew down $97.5 million in that period.  During the first nine months of 2013 we increased borrowings under the credit facility $119.5 million and repaid $18.0 million.  

Cautionary Statement Regarding Forward-Looking Statements

The information in this report includes “forward-looking statements.” All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could”, “should”, “will”, “play”, “believe”, “anticipate”, “intend”, “estimate”, “expect”, “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in our 2013 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

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economic conditions, inflation, increased operating costs, lack of availability of drilling and production equipment and services, environmental risks, weather 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, access to capital, and the other risks described under “Item 1A. Risk Factors” in our 2013 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 2013 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.

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 2013 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 6 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 at September  30, 2014 was a net asset of $8.4 million. A 10% increase or decrease in oil and natural gas prices with all other factors held constant would result in a decrease or increase, 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 $45 million (decrease in value) or $44 million (increase in value), respectively, as of September  30, 2014.

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 $2.5 million, based on the balance outstanding as of September  30, 2014.

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, 2014 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, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings

See Part I, Item 1, Note 10 to our consolidated financial statements entitled “Commitments and Contingencies,” which is incorporated in this item by reference.

ITEM  1A. Risk Factors 

We are subject to certain risks and hazards due to the nature of the business activities we conduct. For a discussion of these risks, see “Item 1A. Risk Factors” in the 2013 Form 10-K. There have been no material changes with respect to the risk factors disclosed in the 2013 Form 10-K during the quarter ended September  30, 2014.

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.
* filed herewith.

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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 12, 2014		general partner
	By:	/s/ Harlan H. Chappelle
		Harlan H. Chappelle
November 12, 2014		President and Chief Executive Officer
	By:	/s/ Michael A. McCabe
		Michael A. McCabe
		Vice President and Chief Financial Officer

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