Alta Mesa 10Q 2017 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, 2017

FOR

☐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, a smaller reporting company or an emerging growth company. See definition of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one)



Large accelerated filer	☐	Accelerated filer	☐	Non-accelerated filer	☒	(Do not check if smaller reporting company)

Smaller reporting company	☐	Emerging growth company	☒

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.☐

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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	Page Number
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements (unaudited)
Condensed Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016	3
Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2017 and 2016	4
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2017 and 2016	5
Notes to Condensed Consolidated Financial Statements	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3. Quantitative and Qualitative Disclosures about Market Risk	35
Item 4. Controls and Procedures	35
PART II — OTHER INFORMATION
Item 1. Legal Proceedings	35
Item 1A. Risk Factors	36
Item 6. Exhibits	37
Signatures	38

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PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30,		December 31,
	2017		2016

	(in thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	3,740	$	7,185
Short-term restricted cash		1,173		433
Accounts receivable, net of allowance of $802 and $889, respectively		71,260		37,611
Other receivables		679		8,061
Receivables due from affiliate		839		8,883
Prepaid expenses and other current assets		2,215		3,986
Derivative financial instruments		6,952		83
Total current assets		86,858		66,242
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net		944,867		712,162
Other property and equipment, net		9,139		9,731
Total property and equipment, net		954,006		721,893
OTHER ASSETS
Investment in LLC — cost		9,000		9,000
Deferred financing costs, net		1,943		3,029
Notes receivable due from affiliate		12,121		9,987
Deposits and other long-term assets		14,686		2,977
Derivative financial instruments		5,282		723
Total other assets		43,032		25,716
TOTAL ASSETS	$	1,083,896	$	813,851
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	144,546	$	79,710
Advances from non-operators		3,872		4,058
Advances from related party		47,794		42,528
Asset retirement obligations		3,960		4,900
Derivative financial instruments		348		21,207
Total current liabilities		200,520		152,403
LONG-TERM LIABILITIES
Asset retirement obligations, net of current portion		65,152		61,128
Long-term debt, net		565,247		529,905
Notes payable to founder		27,861		26,957
Derivative financial instruments		—		4,482
Other long-term liabilities		7,613		6,870
Total long-term liabilities		665,873		629,342
TOTAL LIABILITIES		866,393		781,745
Commitments and Contingencies (Note 11)
PARTNERS' CAPITAL		217,503		32,106
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$	1,083,896	$	813,851

The accompanying notes are an integral part of these condensed consolidated financial statements.

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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2017		2016		2017		2016

	(in thousands)
OPERATING REVENUES AND OTHER
Oil	$	55,195	$	40,691	$	169,611	$	115,778
Natural gas		11,959		9,790		37,780		20,277
Natural gas liquids		8,119		3,994		22,814		10,109
Other revenues		72		57		274		358
Total operating revenues		75,345		54,532		230,479		146,522
Gain (loss) on sale of assets		—		(8)		—		3,723
Gain on acquisition of oil and gas properties		5,267		—		6,893		—
Gain (loss) on derivative contracts		(10,468)		3,508		38,024		(23,970)
Total operating revenues and other		70,144		58,032		275,396		126,275
OPERATING EXPENSES
Lease and plant operating expense		15,503		14,644		49,836		45,222
Marketing and transportation expense		8,666		5,254		21,566		8,140
Production and ad valorem taxes		2,705		2,895		8,812		8,021
Workover expense		1,714		727		5,112		3,242
Exploration expense		5,523		8,590		19,930		15,304
Depreciation, depletion, and amortization expense		28,784		22,433		80,082		66,857
Impairment expense		82		919		29,206		14,238
Accretion expense		395		540		1,447		1,615
General and administrative expense		17,458		10,650		35,534		32,909
Total operating expenses		80,830		66,652		251,525		195,548
INCOME (LOSS) FROM OPERATIONS		(10,686)		(8,620)		23,871		(69,273)
OTHER INCOME (EXPENSE)
Interest expense		(13,850)		(18,186)		(39,069)		(52,253)
Interest income		332		239		880		672
Total other income (expense)		(13,518)		(17,947)		(38,189)		(51,581)
LOSS BEFORE STATE INCOME TAXES		(24,204)		(26,567)		(14,318)		(120,854)
Provision for state income taxes		—		—		285		107
NET LOSS	$	(24,204)	$	(26,567)	$	(14,603)	$	(120,961)

The accompanying notes are an integral part of these condensed consolidated financial statements.

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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended
	September 30,
	2017		2016

	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(14,603)	$	(120,961)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, and amortization expense		80,082		66,857
Impairment expense		29,206		14,238
Accretion expense		1,447		1,615
Amortization of deferred financing costs		2,205		3,004
Amortization of debt discount		—		382
Dry hole expense		2,447		423
Expired leases		8,394		6,689
(Gain) loss on derivative contracts		(38,024)		23,970
Settlements of derivative contracts		1,775		83,839
Premium paid on derivative contracts		(520)		—
Interest converted into debt		904		904
Interest on notes receivable due from affiliates		(619)		(574)
Gain on sale of assets		—		(3,723)
Gain on acquisition of oil and gas properties		(6,893)		—
Changes in assets and liabilities:
Restricted cash		(740)		(92,046)
Accounts receivable		(33,649)		(4,774)
Other receivables		7,382		14,436
Receivables due from affiliate		169		214
Prepaid expenses and other non-current assets		(9,938)		(1,898)
Advances from related party		5,266		13,425
Settlement of asset retirement obligation		(6,083)		(1,465)
Accounts payable, accrued liabilities, and other liabilities		27,308		2,918
NET CASH PROVIDED BY OPERATING ACTIVITIES		55,516		7,473
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property and equipment		(244,308)		(149,179)
Acquisitions		(55,236)		—
Proceeds from sale of property		—		1,405
Notes receivable due from affiliate		(1,515)		—
NET CASH USED IN INVESTING ACTIVITIES		(301,059)		(147,774)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt		286,065		141,935
Repayments of long-term debt		(251,622)		(1,500)
Additions to deferred financing costs		(220)		(799)
Capital contributions		207,875		—
NET CASH PROVIDED BY FINANCING ACTIVITIES		242,098		139,636
NET DECREASE IN CASH AND CASH EQUIVALENTS		(3,445)		(665)
CASH AND CASH EQUIVALENTS, beginning of period		7,185		8,869
CASH AND CASH EQUIVALENTS, end of period	$	3,740	$	8,204

The accompanying notes are an integral part of these condensed consolidated financial statements.

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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. DESCRIPTION OF BUSINESS

Alta Mesa Holdings, LP and its subsidiaries (“we,” “us,” “our,” the “Company,” and “Alta Mesa”) is an independent exploration and production company engaged primarily in the acquisition, exploration, development, and production of oil and natural gas properties. Our principal area of operation is in the eastern portion of the Anadarko Basin commonly referred to as the STACK. The STACK is an acronym describing both its location – Sooner Trend Anadarko Basin Canadian and Kingfisher County – and the multiple, stacked productive formations present in the area. Our operations also include other non-STACK oil and natural gas interests within the continental United States.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

We have provided a discussion of significant accounting policies in Note 2 in our Annual Report on Form 10-K for the year ended December 31, 2016 (the “2016 Annual Report”). As of September 30, 2017, our significant accounting policies are consistent with those discussed in Note 2 in the 2016 Annual Report.

Principles of Consolidation and Reporting

The condensed consolidated financial statements reflect our accounts after elimination of all significant intercompany transactions and balances. The condensed consolidated 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, 2016, which were filed with the Securities and Exchange Commission (the “SEC”) in our 2016 Annual Report.

The condensed consolidated financial statements included herein as of September 30, 2017, and for the three and nine months ended September 30, 2017 and 2016, 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 condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, the condensed consolidated financial statements do not include all of the information and footnotes required by GAAP for complete financial statements. Certain reclassifications of prior period condensed 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.

Use of Estimates

The preparation of condensed 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 condensed 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, state 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.

Accounts Receivable

Accounts receivable consists of the following:


	September 30,		December 31,
	2017		2016

	(in thousands)
Oil, natural gas and natural gas liquids sales	$	27,670	$	25,156
Joint interest billings		16,792		10,427
Pooling interest (1)		27,600		2,917
Allowance for doubtful accounts		(802)		(889)
Total accounts receivable, net	$	71,260	$	37,611

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(1)

Pooling interest relates to Oklahoma’s forced pooling process to ensure all working interest owners participate in drilling and spacing units for wells we propose to drill as operator on our STACK acreage. We expect full realization from our pooling efforts associated with the drilling activities in Oklahoma totaling approximately $27.6 million over the next 12 months.

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers concerning the recognition, measurement and disclosure of revenue from those contracts. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. ASU 2014-09 and related interpretive guidance will be effective for interim and annual periods beginning after December 15, 2017 and allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. We plan to adopt the standard on January 1, 2018 using the modified retrospective method with a cumulative adjustment to retained earnings as necessary.

We are in the process of assessing our contracts and evaluating the impact on the condensed consolidated financial statements. We are continuing to evaluate the provisions of ASU 2014-09 as it relates to certain sales contracts, and in particular, as it relates to disclosure requirements. In addition, we are evaluating the impact, if any, on the presentation of our future revenues and expenses under the new gross-versus-net presentation guidance. We continue to evaluate the impact of these and other provisions of ASU 2014-09 on our accounting policies, changes to relevant business practices, internal controls, and consolidated financial statements. We will complete our evaluation during the fourth quarter of 2017.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842)(“ASU 2016-02”), which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 “Leases.” The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (i) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents a lessee's right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. ASU 2016-02 also requires disclosures designed to provide information on the amount, timing, and uncertainty of cash flows arising from leases. The standard will be effective for interim and annual periods beginning after December 15, 2018, with earlier adoption permitted. In the normal course of business, we enter into operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, well equipment, compressors, office space and other assets.

At this time, we cannot reasonably estimate the financial impact ASU 2016-02 will have on our financial statements; however, the adoption and impletion of ASU 2016-02 is expected to have a material impact on our condensed consolidated balance sheets resulting in an increase in both the assets and liabilities relating to our operating lease activities greater than twelve months As part of our assessment to date, we have formed an implementation work team and will complete our evaluation in 2018. As we continue to evaluate and implement the standard, we will provide additional information about the expected financial impact at a future date. We plan to adopt ASU 2016-02 on January 1, 2019.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statements of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact our financial position or results of operations but could result in presentation changes on our condensed consolidated statements of cash flows.

In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows: Restricted Cash (“ASU 2016-18”), which requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statements of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. ASU 2016-18 is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. The adoption of this guidance will not impact our financial position or results of operations but could result in presentation changes on our consolidated statements of cash flows.

In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business (“ASU 2017-01”), which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a

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business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 is effective for interim and annual periods after December 15, 2017, and should be applied prospectively. We are currently evaluating the effect that adopting this guidance will have on our financial position, cash flows and results of operations.

3. SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow disclosures and non-cash investing and financing activities are presented below:


	Nine Months Ended September 30,
	2017		2016

	(in thousands)
Supplemental cash flow information:
Cash paid for interest	$	25,675	$	37,006
Cash paid for state income taxes		—		422
Non-cash investing and financing activities:
Change in asset retirement obligations		3,778		1,032
Asset retirement obligations assumed, purchased properties		705		—
Change in accruals or liabilities for capital expenditures		41,322		11,524

4. ACQUISITIONS

2017 Acquisitions

In July 2017, we closed on our acquisition to acquire certain oil and natural gas properties in Oklahoma with an unaffiliated third party for a purchase price of approximately $45.4 million, net of customary post-closing adjustments. The acquired oil and natural gas properties were primarily unproved leasehold. We accounted for this transaction as an asset acquisition with substantially all of the purchase price allocated to unproved property within oil and natural gas properties, successful efforts method, net. We funded the acquisition with borrowings under our senior secured revolving credit facility.

In September 2017, we acquired approximately $4.6 million of unproved leasehold in Oklahoma. We funded the transaction with cash on hand and accounted for this transaction as an asset acquisition.

In September 2017, we completed a transaction to acquire certain proved oil and natural gas properties from Brown & Borelli, et al (the “B&B Acquisition”) for a purchase price of approximately $3.5 million, net of customary post-closing purchase price adjustments. We funded the acquisition with cash on hand. The acquisition was accounted for using the acquisition method under ASC 805, “Business Combinations,” which requires acquired assets and liabilities to be recorded at fair value as of the acquisition date. The difference between the historical results of operations and the unaudited pro forma results of operations for the three and nine months ended September 30, 2017 and 2016 was determined to be de minimus and therefore pro forma information has not been provided.

A summary of the consideration paid and the allocation of the total purchase price to the assets acquired and the liabilities assumed in the B&B Acquisition based on the preliminary fair value at the acquisition date, is as follows:


	(in thousands)
Summary of Consideration
Cash	$	3,469
Total consideration paid		3,469

Summary of Purchase Price Allocation
Plus: fair value of liabilities assumed
Asset retirement obligations assumed		370
Total fair value liabilities assumed		370
Less: fair value of assets acquired
Proved oil and natural gas properties		9,106
Total fair value assets acquired		9,106

Bargain purchase gain	$	(5,267)

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The fair value of the net assets acquired was approximately $9.1 million. As the fair value of the net assets acquired exceeded the total consideration paid, we recorded a bargain purchase gain of approximately $5.3 million. The acquisition resulted in a bargain purchase gain primarily as a result of timing from the execution of the purchase and sale agreement to the closing date of the acquisition at which time the value of the underlying properties increased substantially due to increased proved reserves. The bargain purchase gain is reflected in gain on acquisition of oil and natural gas properties on our condensed consolidated statements of operations.

In April 2017, we completed an acquisition of certain non-STACK proved oil and natural gas properties from Setanta Energy, LLC (the “Setanta” Acquisition) for a purchase price of approximately $0.9 million, net of customary post-closing purchase price adjustments. We funded the acquisition with borrowings under our senior secured revolving credit facility. This purchase increases our working interest in various wells in which we already hold an interest. The acquisition was accounted for using the acquisition method under ASC 805.

A summary of the consideration paid and the allocation of the total purchase price to the assets acquired and the liabilities assumed in the Setanta Acquisition based on the preliminary fair value at the acquisition date, is as follows:


	(in thousands)
Summary of Consideration
Cash	$	890
Total consideration paid		890

Summary of Purchase Price Allocation
Plus: fair value of liabilities assumed
Asset retirement obligations assumed		89
Total fair value liabilities assumed		89
Less: fair value of assets acquired
Proved oil and natural gas properties		2,605
Unproved oil and natural gas properties		—
Total fair value assets acquired		2,605

Bargain purchase gain	$	(1,626)

The fair value of the net assets acquired was approximately $2.6 million. As the fair value of the net assets acquired exceeded the total consideration paid, we recorded a bargain purchase gain of approximately $1.6 million. The acquisition resulted in a bargain purchase gain primarily as a result of the seller’s financial distress and needing to dispose of the underlying properties for cash in an expedited manner which resulted in a below market purchase price. The bargain purchase gain is reflected in gain on acquisition of oil and natural gas properties on our condensed consolidated statements of operations.

In accordance with ASC 805, the following unaudited pro forma results of operations for the nine months ended September 30, 2017 and 2016 have been prepared to give effect to the Setanta acquisition on our condensed consolidated results of operations as if it had occurred on January 1, 2016. Therefore, the bargain purchase gain on acquisition of $1.6 million has been included in pro forma income (loss) for the nine months ended September 30, 2016. The difference between the historical results of operations and the unaudited pro forma results of operations for the three months ended September 30, 2017 and 2016 was determined to be de minimus and therefore not provided.



	Total Operating		Income
	Revenues		(Loss)

	(in thousands)

Pro forma results of operations for the nine months ended September 30, 2017	$	230,819	$	(16,188)
Pro forma results of operations for the nine months ended September 30, 2016	$	146,664	$	(119,455)

2016 Acquisition

On December 31, 2016, High Mesa, Inc. (“High Mesa”) purchased from BCE-STACK Development LLC (“BCE”) and contributed interests in 24 producing wells (the “Contributed Wells”) drilled under the joint development agreement to us. We accounted for the Contributed Wells as a business combination in the prior year and the results of operations from the acquisition is reflected in the

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consolidated statement of operations for the three and nine months ended September 30, 2016 as presented below as if it had occurred on January 1, 2016.


	Total Operating		Income
	Revenues		(Loss)

	(in thousands)

Pro forma results of operations for the three months ended September 30, 2016	$	64,370	$	(19,143)
Pro forma results of operations for the nine months ended September 30, 2016	$	157,898	$	(112,822)

The unaudited pro forma information has been derived from historical information and are 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.

The fair value of the oil and natural gas properties are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties were measured using valuation techniques that convert future cash flows into a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include, but are not limited to recoverable reserves, production rates, future operating and development costs, future commodity price and estimates by management at the time of the valuation are the most sensitive and may be subject to change.

5. PROPERTY AND EQUIPMENT

Property and equipment consists of the following:



	September 30,		December 31,
	2017		2016

	(in thousands)
OIL AND NATURAL GAS PROPERTIES
Unproved properties	$	136,410	$	116,311
Accumulated impairment of unproved properties		(18,974)		(65)
Unproved properties, net		117,436		116,246
Proved oil and natural gas properties		1,931,207		1,611,249
Accumulated depreciation, depletion, amortization and impairment		(1,103,776)		(1,015,333)
Proved oil and natural gas properties, net		827,431		595,916
TOTAL OIL AND NATURAL GAS PROPERTIES, net		944,867		712,162
OTHER PROPERTY AND EQUIPMENT
Land		5,339		4,730
Office furniture and equipment, vehicles		20,170		19,446
Accumulated depreciation		(16,370)		(14,445)
OTHER PROPERTY AND EQUIPMENT, net		9,139		9,731
TOTAL PROPERTY AND EQUIPMENT, net	$	954,006	$	721,893

6. FAIR VALUE DISCLOSURES

We follow ASC 820, “Fair Value Measurements and Disclosures” (“ASC 802”). 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.

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 because the transactions cannot be assumed to have been consummated at arm’s length, the terms are not deemed to be market terms, there are no quoted values available for this instrument, and an independent valuation would not be practicable due to the lack of data regarding similar instruments, if any, and the associated potential costs.

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Our senior notes are carried at historical cost, and we estimate the fair value of the senior notes for disclosure purposes. We have estimated the fair value of our $500 million senior notes payable to be $545.0 million at September 30, 2017. This estimation is based on the most recent trading values of the senior notes at or near the reporting dates, which is a Level 1 determination. See Note 9 for information on long-term debt.

We utilize the modified Black-Scholes and the Turnbull Wakeman option pricing models to estimate the fair values of oil, natural gas and natural gas liquids 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, natural gas and natural gas liquids prices. We have classified the fair values of all our oil, natural gas and natural gas liquids derivative contracts as Level 2.

Oil and natural gas properties are subject to impairment testing and potential impairment write down. Oil and natural gas properties with a carrying amount of $36.2 million were written down to their fair value of $7.0 million, resulting in an impairment charge of $29.2 million for the nine months ended September 30, 2017. For the nine months ended September 30, 2016, oil and natural gas properties with a carrying amount of $28.7 million were written down to their fair value of $14.5 million, resulting in an impairment charge of $14.2 million. Oil and natural gas properties with a carrying amount of $0.1 million were written down to their fair value of zero, resulting in an impairment charge of $0.1 million for the three months ended September 30, 2017. For the three months ended September 30, 2016, oil and natural gas properties with a carrying amount of $1.2 million were written down to their fair value of $0.3 million, resulting in an impairment charge of $0.9 million. Significant Level 3 assumptions used in the calculation of estimated discounted cash flows in the impairment analysis included our estimate of future oil and natural gas prices, production costs, development expenditures, estimated timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.

New additions to asset retirement obligations result from estimations for new properties, and fair values for them are categorized as Level 3. Such estimations are based on present value techniques that utilize company-specific information for such inputs as cost and timing of plugging and abandonment of wells and facilities. We recorded $1.2 million and $1.0 million in additions to asset retirement obligations measured at fair value during the nine months ended September 30, 2017 and 2016.

The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2017 and December 31, 2016, and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value:



	Level 1		Level 2		Level 3		Total

	(in thousands)
At September 30, 2017:
Financial Assets:
Commodity derivative contracts		—	$	24,558		—	$	24,558
Financial Liabilities:
Commodity derivative contracts		—	$	12,672		—	$	12,672
At December 31, 2016:
Financial Assets:
Commodity derivative contracts		—	$	15,773		—	$	15,773
Financial Liabilities:
Commodity derivative contracts		—	$	40,656		—	$	40,656

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 7.

7. DERIVATIVE FINANCIAL INSTRUMENTS

We account for our derivative contracts under the provisions of ASC 815, “Derivatives and Hedging” (“ASC 815”). We have entered into forward-swap contracts and collar contracts to reduce our exposure to price risk in the spot market for oil, natural gas and natural gas liquids. From time to time, we also utilize financial basis swap contracts, which address the price differential between market-wide benchmark prices and other benchmark pricing referenced in certain of our oil, natural gas and natural gas liquids sales contracts. Substantially all of our hedging agreements are executed by affiliates of our lenders under the senior secured revolving credit facility described in Note 9, and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the senior secured revolving credit facility. The contracts settle monthly and are scheduled to coincide with oil production equivalent to barrels (Bbl) per month, natural gas production equivalent to volumes in millions of British thermal units (MMBtu) per month, and natural gas liquids production to volumes in gallons (Gal) per month. The contracts represent agreements between us and the counterparties to exchange cash based on a designated price, or in the case of financial basis hedging contracts, based on a designated

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price differential between various benchmark prices. Cash settlement occurs monthly. No derivative contracts have been entered into for trading or speculative purposes.

From time to time, we enter into interest rate swap agreements with financial institutions to mitigate the risk of loss due to changes in interest rates.

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 condensed consolidated statements of operations at each reporting date.

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

The following table summarizes the fair value and classification of our derivative instruments, none of which have been designated as hedging instruments under ASC 815:

Fair Values of Derivative Contracts:



	September 30, 2017
					Net Fair
	Gross		Gross amounts		Value of Assets
	Fair Value		offset against assets		presented in
Balance sheet location	of Assets		in the Balance Sheet		the Balance Sheet

	(in thousands)
Derivative financial instruments, current assets	$	13,904	$	(6,952)	$	6,952
Derivative financial instruments, long-term assets		10,654		(5,372)		5,282
Total	$	24,558	$	(12,324)	$	12,234



					Net Fair
	Gross		Gross amounts		Value of Liabilities
	Fair Value		offset against liabilities		presented in
Balance sheet location	of Liabilities		in the Balance Sheet		the Balance Sheet

	(in thousands)
Derivative financial instruments, current liabilities	$	7,300	$	(6,952)	$	348
Derivative financial instruments, long-term liabilities		5,372		(5,372)		—
Total	$	12,672	$	(12,324)	$	348



	December 31, 2016
					Net Fair
	Gross		Gross amounts		Value of Assets
	Fair Value		offset against assets		presented in
Balance sheet location	of Assets		in the Balance Sheet		the Balance Sheet

	(in thousands)
Derivative financial instruments, current assets	$	3,296	$	(3,213)	$	83
Derivative financial instruments, long-term assets		12,477		(11,754)		723
Total	$	15,773	$	(14,967)	$	806



					Net Fair
	Gross		Gross amounts		Value of Liabilities
	Fair Value		offset against liabilities		presented in
Balance sheet location	of Liabilities		in the Balance Sheet		the Balance Sheet

	(in thousands)
Derivative financial instruments, current liabilities	$	24,420	$	(3,213)	$	21,207
Derivative financial instruments, long-term liabilities		16,236		(11,754)		4,482
Total	$	40,656	$	(14,967)	$	25,689

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



Derivatives not	Three Months Ended				Nine Months Ended
designated as hedging	September 30,				September 30,
instruments under ASC 815	2017		2016		2017		2016

	(in thousands)
Gain (loss) on derivative contracts
Oil commodity contracts	$	(10,873)	$	577	$	31,665	$	(22,794)

Natural gas commodity contracts		1,035		3,265		6,763		(506)

Natural gas liquids commodity contracts		(630)		(334)		(404)		(670)
Total gain (loss) on derivative contracts	$	(10,468)	$	3,508	$	38,024	$	(23,970)

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 senior secured revolving 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.

We had the following open derivative contracts for crude oil at September 30, 2017:

OIL DERIVATIVE CONTRACTS



	Volume	Weighted		Range
Period and Type of Contract	in Bbls	Average		High		Low
2017
Price Swap Contracts	643,500	$	51.16	$	57.25	$	46.00
Collar Contracts
Long Call Options	46,000		85.00		85.00		85.00
Short Call Options	437,000		60.51		85.00		54.40
Long Put Options	391,000		48.24		50.00		47.00
Short Put Options	299,000		36.38		37.00		35.00
2018
Price Swap Contracts	1,825,000		52.74		57.25		50.27
Collar Contracts
Long Call Options	365,000		54.00		54.00		54.00
Short Call Options	2,190,000		60.87		62.00		60.50
Long Put Options	1,825,000		50.00		50.00		50.00
Short Put Options	2,190,000		40.26		42.00		40.00
2019
Collar Contracts
Short Call Options	1,606,000		61.44		63.00		56.50
Long Put Options	1,606,000		50.00		50.00		50.00
Short Put Options	1,606,000		38.07		40.00		37.50

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We had the following open derivative contracts for natural gas at September 30, 2017:

NATURAL GAS DERIVATIVE CONTRACTS



	Volume in	Weighted		Range
Period and Type of Contract	MMBtu	Average		High		Low
2017
Price Swap Contracts	232,500	$	3.40	$	3.40	$	3.39
Collar Contracts
Short Call Options	3,036,000		3.69		4.11		3.25
Long Put Options	2,728,500		3.17		3.60		3.00
Long Call Options	155,000		2.95		2.95		2.95
Short Put Options	2,883,500		2.60		3.00		2.50
2018
Collar Contracts
Short Call Options	6,582,000		5.26		5.53		4.00
Long Put Options	5,925,000		4.43		4.50		3.60
Short Put Options	5,925,000		3.92		4.00		3.00

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 various combinations of these benchmarks.

We had the following open derivative contracts for natural gas liquids at September 30, 2017:

NATURAL GAS LIQUIDS DERIVATIVE CONTRACTS


	Volume	Weighted		Range
Period and Type of Contract	in Gal	Average		High		Low
2017
Price Swap Contracts
Short Price Swaps	1,545,600	$	0.47	$	0.47	$	0.47

We had the following open financial basis swaps at September 30, 2017:

BASIS SWAP DERIVATIVE CONTRACTS



						Weighted
						Average Spread
Volume in MMBtu (1)	Reference Price 1	Reference Price 2	Period			($ per MMBtu)
2,915,000	TEX/OKL Mainline (PEPL)	NYMEX Henry Hub	Oct'17	—	Dec '17	$	(0.21)
6,980,000	TEX/OKL Mainline (PEPL)	NYMEX Henry Hub	Jan '18	—	Dec '18		(0.30)
152,500	WAHA	NYMEX Henry Hub	Nov '18	—	Dec '18		(0.46)
225,000	WAHA	NYMEX Henry Hub	Jan '19	—	Mar '19		(0.46)

(1)

Represents short swaps that fix the basis differentials between Tex/OKL Panhandle Eastern Pipeline (“PEPL”) Inside FERC (“IFERC”) and NYMEX Henry Hub and WAHA and NYMEX Henry Hub.

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8. ASSET RETIREMENT OBLIGATIONS

A summary of the changes in asset retirement obligations is included in the table below:


	Nine
	Months Ended
	September 30, 2017
	(in thousands)
Balance, beginning of year	$	66,028
Liabilities incurred		1,202
Liabilities assumed with acquired producing properties		705
Liabilities settled		(6,083)
Liabilities transferred in disposition of properties		(47)
Revisions to estimates		5,860
Accretion expense		1,447
Balance, September 30, 2017		69,112
Less: Current portion		3,960
Long-term portion	$	65,152

The total revisions to estimates include approximately $2.6 million related to additions to oil and natural gas properties with the remaining revisions related to the difference between our beginning asset retirement obligation and the actual settlement amounts for the nine months ended September 30, 2017.

9. LONG-TERM DEBT, NET AND NOTES PAYABLE TO FOUNDER

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



	September 30,		December 31,
	2017		2016

	(in thousands)
Senior secured revolving credit facility	$	75,065	$	40,622
7.875% senior unsecured notes due 2024		500,000		500,000
Unamortized deferred financing costs		(9,818)		(10,717)
Total long-term debt, net	$	565,247	$	529,905
Notes payable to founder	$	27,861	$	26,957

Senior Secured Revolving Credit Facility. In November 2016, we entered into the Seventh Amended and Restated Credit Agreement (as amended, the “credit facility”) with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of banks. On June 13, 2017, we entered into an Agreement and Amendment No. 2 (the “Second Amendment”) to the credit facility which, among other things: (i) increased our borrowing base from $287.5 million to $315.0 million until the next scheduled redetermination and (ii) permits us to make a one-time cash distribution of no more than $1.0 million to a limited partner. As of September 30, 2017, we had $75.1 million outstanding with $234.6 million of available borrowing capacity under the credit facility. The letters of credit outstanding as of September 30, 2017 and December 31, 2016 were approximately $5.3 million and $7.6 million, respectively. The borrowing base is currently $315.0 million and is redetermined semi-annually in May and November of each year. The principal amount is payable on the maturity date of November 10, 2020.

The credit facility is secured by substantially all of our oil and natural gas properties and is based on our proved reserves and the value attributed to those reserves. We have a choice of borrowing in Eurodollars or at the “Reference Rate,” which is based on the prime rate of Wells Fargo Bank, National Association. The credit facility bears interest at the London Interbank Offered Rate (“LIBOR”) plus applicable margins ranging from 2.75% and 3.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing based utilized, and ranging from 3.00% to 4.00% if our leverage ratio exceeds 3.25 to 1.00. The Reference Rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s Reference Rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 1%, plus a margin ranging from 1.75% to 2.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing base utilized, and ranging from 2.00% to 3.00% if our leverage ratio exceeds 3.25 to 1.00. The weighted average and effective interest rate on outstanding borrowings was 4.75% as of September 30, 2017 and 4.00% as of December 31, 2016.

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The credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, guaranty or make loans to others, make investments, enter into mergers, make certain payments and distributions, enter into or be party to hedge agreements, amend our organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. The credit facility permits us to make distributions in any fiscal quarter so long as (i) the amount of distributions made in such fiscal quarter does not exceed our excess cash flow from the immediately preceding fiscal quarter, (ii) no event of default exists, before and after giving effect to such distribution, (iii) our pro forma leverage ratio is less than 3.00 to 1.00 and (iv) before and after giving effect to such distribution the unused commitment amounts available under the credit facility are at least 20% of the commitments in effect.

The credit facility also requires us to maintain a current ratio (as defined in the credit facility), of consolidated current assets (including unused borrowing base committed capacity and with exclusions as described in the credit facility) to consolidated current liabilities of no less than 1.0 to 1.0 as of the last day of any fiscal quarter and leverage ratio of our consolidated debt (other than obligations under hedge agreements and founder notes) as of the end of such fiscal quarter to our consolidated earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (“EBITDAX”) over the four quarter period then ended of not greater than 4.0 to 1.0.

As of September 30, 2017, we were in compliance with all financial covenants of the credit facility.

Senior Unsecured Notes. We have $500 million in aggregate principal amount of 7.875% senior unsecured notes (the “senior notes”) due December 15, 2024 which were issued at par by us and our wholly owned subsidiary Alta Mesa Finance Services Corp. (collectively, the “Issuers”) during the fourth quarter of 2016. Interest is payable semi-annually on June 15 and December 15 of each year, beginning June 15, 2017. At any time prior to December 15, 2019, we may, from time to time, redeem up to 35% of the aggregate principal amount of the senior notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 107.875% of the principal amount, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the senior notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. At any time prior to December 15, 2019, we may, on any one or more occasions, redeem all or part of the senior notes for cash at a redemption price equal to 100% of their principal amount of the senior notes redeemed plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of redemption. Upon the occurrence of certain kinds of change of control, each holder of the senior notes may require us to repurchase all or a portion of the senior notes for cash at a price equal to 101% of the aggregate principal amount of the senior notes, plus accrued and unpaid interest, if any, to the date of repurchase. On and after December 15, 2019, we may redeem the senior notes, in whole or in part, at redemption prices (expressed as percentages of principal amount) equal to 105.906% for the twelve-month period beginning on December 15, 2019, 103.938% for the twelve-month period beginning on December 15, 2020, 101.969% for the twelve-month period beginning on December 15, 2021 and 100.000% beginning on December 15, 2022, plus accrued and unpaid interest, if any, to the date of redemption.

The senior notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries, subject to certain customary release provisions. Accordingly, they will rank equal in right of payment to all of our existing and future senior indebtedness; senior in right of payment to all of our existing and future indebtedness that is expressly subordinated to the senior notes or the respective guarantees; effectively subordinated to all of our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including amounts outstanding under our credit facility; and structurally subordinated to all existing and future indebtedness and obligations of any of our subsidiaries that do not guarantee the senior notes.

The senior notes contain certain covenants limiting the Issuers’ ability and the ability of the Restricted Subsidiaries (as defined in the indenture governing the senior notes (the “indenture”)) to, under certain circumstances, prepay subordinated indebtedness, pay distributions, redeem stock or make certain restricted investments; incur indebtedness; create liens on the Issuers’ assets to secure debt; restrict dividends, distributions or other payments; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries; sell or otherwise transfer or dispose of assets, including equity interests of restricted subsidiaries; effect a consolidation or merger; and change our line of business.

Under the terms of the indenture for the senior notes, if we experience certain specific change of control events, unless the Issuers have previously or concurrently exercised their right to redeem all of the senior notes under the optional redemption provision, such holder has the right to require us to purchase such holder’s senior notes at 101% of the principal amount plus accrued and unpaid interest to the date of purchase.

As of September 30, 2017, we were in compliance with the indentures governing the senior notes.

Notes Payable to Founder. We have notes payable to our founder (“Founder Notes”) that bear simple interest at 10% with a balance of $27.9 million and $27.0 million at September 30, 2017 and December 31, 2016, respectively. The maturity date was extended on March 25, 2014 from December 31, 2018 to December 31, 2021. Interest and principal are payable at maturity.

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These Founder Notes are subordinate to the paid-in-kind notes of High Mesa. The Founder Notes are also subordinated to the rights of High Mesa Holdings, LP (“HMH”) and Riverstone VI Alta Mesa Holdings, L.P. (“Riverstone”) to receive distributions under our Amended Partnership Agreement and subordinated to the rights of the holders of Series B preferred stock of High Mesa to receive payments. Our founder shall convert the Founder Notes into equity interests in HMH immediately prior to the closing of the business combination with Silver Run Acquisition Corporation II. See Note 13 for further details.

Interest on the Founder Notes amounted to $0.9 million for each of the nine months ended September 30, 2017 and 2016 and $0.3 million for each of the three months ended September 30, 2017 and 2016. Such amounts have been added to the balance of the Founder Notes.

Deferred financing costs. As of September 30, 2017, we had $11.8 million of deferred financing costs related to the credit facility and senior notes, which are being amortized over the respective terms of the related debt instrument. Deferred financing costs of $9.8 million related to the senior notes are netted with long-term debt on the condensed consolidated balance sheet as of September 30, 2017. Deferred financing costs of $1.9 million related to the credit facility are included in deferred financing costs, net on the condensed consolidated balance sheets as of September 30, 2017. Amortization of deferred financing costs for the nine months ended September 30, 2017 and 2016 was $2.2 million and $3.0 million, respectively. Amortization of deferred financing costs recorded for each of the three months ended September 30, 2017 and 2016 was $0.8 million and $1.0 million, respectively. The amortization of these costs are included in interest expense on the condensed consolidated statements of operations.

The credit facility and the senior notes contain customary events of default. If an event of default occurs and is continuing, the holders of such indebtedness may elect to declare all the funds borrowed to be immediately due and payable with accrued and unpaid interest. Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable.

10. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

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



	September 30,		December 31,
	2017		2016

	(in thousands)
Capital expenditures	$	42,621	$	15,155
Revenues and royalties payable		23,010		12,187
Operating expenses/taxes		18,485		12,975
Interest		12,903		2,627
Compensation		3,296		5,302
Derivative settlement payable		665		1,126
Other		721		1,164
Total accrued liabilities		101,701		50,536
Accounts payable		42,845		29,174
Accounts payable and accrued liabilities	$	144,546	$	79,710

11. COMMITMENTS AND CONTINGENCIES

Contingencies

Environmental claims: Various landowners have sued us in lawsuits concerning several fields in which we have or historically had operations. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from 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 condensed consolidated financial statements at September 30, 2017.

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.

Litigation: On April 13, 2005, Henry Sarpy and several other plaintiffs (collectively, “Plaintiffs”) filed a petition against Exxon, Extex, The Meridian Resource Corporation (“TMRC,” our wholly-owned subsidiary), and the State of Louisiana for contamination of their land in the New Sarpy and/or Good Hope Field in St. Charles Parish. Plaintiffs claimed they are owners of land upon which oil field waste pits containing dangerous and contaminating substances are located. Plaintiffs alleged that they discovered in May 2004

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that their property is contaminated with oil field wastes greater than represented by Exxon. The property was originally owned by Exxon and was sold to TMRC. TMRC subsequently sold the property to Extex. On April 14, 2015, TMRC entered into a Memorandum of Understanding with Exxon to settle the claims in this ongoing matter. On July 10, 2015, the settlement and comprised agreements were finalized and signed by the Plaintiffs and Exxon. On July 28, 2015, the State of Louisiana issued a letter of no objection to the settlement. As of September 30, 2017, we have accrued approximately $3.2 million ($0.8 million in current liabilities and $2.4 million in other long-term liabilities) as the outcome of the litigation was deemed probable and estimable. The settlement requires payment over the term of six years.

On January 25, 2017, Bollenbach Enterprises Limited Partnership filed a class action petition in Kingfisher County, Oklahoma against Oklahoma Energy Acquisitions, LP, our wholly owned subsidiary, Alta Mesa Services, LP, our wholly owned subsidiary, and us (collectively, the “AMH Parties”) claiming royalty underpayment or non-payment of royalty. The suit alleges that the AMH Parties made improper deductions that resulted in underpayment of royalties on natural gas and/or constituents of the gas stream produced from wells. The case was moved to federal court and stayed by the court pending the parties’ efforts to settle the case. In June 2017, the court administratively closed the case following mediation. Class settlement requires approval of the court after certain lengthy notice periods. As of September 30, 2017, we believe losses are probable and estimable in connection with this litigation and have accrued approximately $4.5 million in accounts payable and accrued liabilities in our condensed consolidated balance sheets.

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.

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 designated value (“SIDV”). 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 SIDV 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 can be construed in accordance with the meaning of the term “change in control event”) 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 first nine months of 2017, we granted 308,800 new PARs with a SIDV of $40 and terminated 1,400 PARs with a SIDV of $40, resulting in 883,300 PARs issued at a weighted average of $37.91 as of September 30, 2017. 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 condensed consolidated financial statements at September 30, 2017 or December 31, 2016.

12. SIGNIFICANT RISKS AND UNCERTAINTIES

Our business makes us vulnerable to changes in wellhead prices of crude oil and natural gas. Historically, world-wide oil and natural gas prices and markets have been volatile, and may continue to be volatile in the future. In particular, the prices of oil and natural gas have been highly volatile and declined dramatically since the second half of 2014. Although oil and natural gas prices have started to improve, the duration and magnitude of changes in oil and natural gas prices cannot be predicted. Continued depressed oil and natural gas prices, further price declines or any other unfavorable market conditions could have a material adverse effect on our financial condition and on the carrying value of our proved oil and natural gas reserves. Sustained low oil or natural gas prices may require us to 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 to the extent that we are not able to replace the reserves that we produce. Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness. We mitigate some of this vulnerability by entering into oil, natural gas and natural gas liquids price derivative contracts. See Note 7.

13. PARTNERS’ CAPITAL

Management and Control: Our business and affairs are managed by Alta Mesa Holdings GP, LLC, our general partner (“General Partner”). With certain exceptions, the General Partner may not be removed except for the reasons of “cause,” which are defined in the Sixth Amended and Restated Agreement of Limited Partnership (the “Amended Partnership Agreement”). Our Amended Partnership Agreement currently provides for two classes of limited partners, Class A and Class B. Our limited partners include our General Partner, HMH and Riverstone.

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On August 16, 2017, we entered into a Contribution Agreement (the “Contribution Agreement”) with Silver Run Acquisition Corporation II, a Delaware corporation (“SRII”), HMH, High Mesa Holdings GP, LLC, a Texas limited liability company, our General Partner and solely for certain provisions therein, the equity owners of HMH.�� Pursuant to the Contribution Agreement, SRII will acquire from HMH (i) all of its limited partner interest in us and (ii) 100% of the economic interests and 90% of the voting interests in our General Partner. In return, the HMH will receive: (i) 220,000,000 common units as adjusted of SRII Opco, LP, a Delaware limited partnership and wholly owned subsidiary of SRII; (ii) $400 million in cash, which shall be contributed to us; and (iii) up to $800 million in earn-out consideration in the form of common units of SRII Opco, LP (the “Earn-out Consideration”). The Earn-out Consideration will be paid as set forth below if the 20-day volume-weighted average price (“VWAP”) of the Class A Common Stock of SRII (the “Class A Common Stock”) equals or exceeds the following prices:


20-Day
VWAP		Earn-Out Consideration
$	14.00	10,714,285 Common Units
$	16.00	9,375,000 Common Units
$	18.00	13,888,889 Common Units
$	20.00	12,500,000 Common Units

Additionally, HMH will purchase non-economic capital stock of SRII, dedicated as Class C Common Stock (“Class C Common Stock”). The common units of SRII Opco, LP and corresponding Class C Common Stock are redeemable for Class A Common Stock beginning 180 days after the closing.

The Contribution Agreement contains customary representations and warranties and pre-closing covenants, with the representations and warranties not surviving the closing. Additionally, prior to closing, we have agreed to transfer to HMH all assets and liabilities related to the non-STACK assets. The closing of the Contribution Agreement is subject to (i) the approval of the SRII stockholders, (ii) the simultaneous closing of the contribution agreement by and among SRII, KFM Holdco, LLC, a Delaware limited liability company, Kingfisher Midstream, LLC, a Delaware limited liability company (“Kingfisher”) and the equity owners party thereto pursuant to which SRII will acquire 100% of the outstanding membership interests in Kingfisher, (iii) a SRII Opco, LP leverage ratio of less than 1.5x, (iv) certain regulatory approvals and (v) the satisfaction or waiver of other customary closing conditions. The Contribution Agreement also contains certain customary termination rights, including if the transaction is not consummated by February 28, 2018.

On August 16, 2017, our General Partner, HMH and Riverstone entered into the Amended Partnership Agreement. The Amended Partnership Agreement reflects, among other things, certain changes in our ownership, and provides for certain preemptive rights, tag-along rights, and drag-along rights for the limited partners. In connection with the Amended Partnership Agreement, our limited partners at the time transferred their interests in us to HMH. The Amended Partnership Agreement also reflects the admission of Riverstone and HMH to the Company as limited partners, and provides for certain distribution rights for the Class A and Class B Limited Partners (as defined therein) with respect to the STACK and non-STACK assets.

Riverstone was admitted as a limited partner in connection with its $200 million capital contribution to us on August 17, 2017, in exchange for limited partner interests in us with respect to the economic rights to the STACK assets. We used all of the capital contribution to pay down our credit facility.

On August 16, 2017, the owners of our General Partner entered into a Fifth Amended and Restated Limited Liability Company Agreement, which was amended to, among other things, show certain changes in the ownership of our General Partner and reflect that the holders of Class A Units (as defined therein) are entitled to 100% of the economic rights with respect to our General Partner and the holders of Class B Units (as defined therein) are entitled to 100% of the voting rights with respect to our General Partner.

Contribution, Distribution and Income Allocation: The Amended Partnership Agreement specifies the manner in which we will make cash distributions to our partners.

Distributions from Operations. Current distributions of Net Cash Flow and distributions upon the liquidation, sale, merger, consolidation, dissolution or winding up of the Company shall be made by the General Partner as described below. The General Partner shall have sole discretion to determine the timing of any distribution and the aggregate amounts available for such distribution and such distributions will be made:

• With respect to distributions of Net Cash Flow attributable to the STACK Assets, one hundred percent (100%) to the Class A Partners Pro Rata. Notwithstanding the foregoing, to the extent the Company makes a payment under the Founder Notes, such payment shall be treated as an advance against and, thus, shall reduce the amount otherwise distributable to HMH or its permitted transferees under the Partnership Agreement.

• With respect to distributions of Net Cash Flow attributable to the Non-STACK Assets, one hundred percent (100%) to the Class B Partners Pro Rata.

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Net cash flow means all cash flow, receipts and revenues generated by the Company minus amounts necessary for (i) operating expenses (as defined in the Amended Partnership Agreement), (ii) a reserve fund for future operating expenses, (iii) debt service of the Company, or (iv) any other expenses of the Company. STACK assets means (a) interests in each of Alta Mesa Finance Services Corp., a Delaware corporation, Oklahoma Energy Acquisitions, LP, a Texas limited partnership, and Alta Mesa Services, LP, a Texas limited partnership, (b) all assets held by each of the foregoing as of the date hereof and (c) all oil and gas properties acquired by the Company or any of its subsidiaries after the date hereof in any of Kingfisher, Garfield, Major, Blaine, Logan, Canadian, Dewey, Woodward and Oklahoma counties, in each case, in the State of Oklahoma.

On December 31, 2016, High Mesa purchased from BCE and contributed interest in 24 producing wells drilled under the joint development agreement to us. High Mesa’s equity contribution was recorded at the fair value of the wells contributed of approximately $65.7 million and included contributed cash of $11.3 million, of which $7.9 million was collected during the first quarter of 2017. There were no contributions during the first nine months of 2016.

14. RELATED PARTY TRANSACTIONS

We entered into a promissory note receivable with our affiliate Northwest Gas Processing, LLC, a Delaware limited liability company (“NWGP”), effective September 29, 2017, for approximately $1.5 million. The promissory note was issued by NWGP to us and bears interest (or paid-in-kind interest from time to time) on the principal balance at a rate of 8% per annum, with interest payable in quarterly installments beginning January 1, 2018, and matures on February 28, 2019. Subsequent to quarter end, the $1.5 million promissory note was transferred from NWGP to High Mesa Services, LLC, a subsidiary of our parent company High Mesa.

15. SUBSIDIARY GUARANTORS

All of our material wholly-owned subsidiaries are guarantors under the terms of our senior notes and our credit facility. Our condensed consolidated financial statements reflect the financial position of these subsidiary guarantors. As the parent company, we have no independent operations, assets, or liabilities. The guarantees are full and unconditional (except for customary release provisions) and joint and several. Those subsidiaries which are not wholly owned by us and are not guarantors of our senior notes or our credit facility, are immaterial subsidiaries. There are no restrictions on dividends, distributions, loans or other transfers of funds from the subsidiary guarantors to us.

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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 condensed consolidated financial statements and related notes included elsewhere in this report. In addition, such analysis should be read in conjunction with the consolidated financial statements and the related notes included in our Annual Report on Form 10-K for the year ended December 31, 2016 (“2016 Annual Report”). The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the volatility of oil and natural gas prices, production timing and volumes, estimates of proved reserves, operating costs and capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below in “Cautionary Statement Regarding Forward-Looking Statements,” and in our 2016 Annual Report, particularly in the section titled “Risk Factors,” all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

We have been engaged in the onshore oil and natural gas acquisition, exploitation, exploration and production in the United States since 1987. Currently, we are focusing on the development and acquisition of unconventional oil and natural gas reserves in the STACK. We have transitioned our focus from our diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource play in the STACK with an extensive inventory of drilling opportunities. The STACK is a prolific hydrocarbon system with high oil and liquids-rich natural gas content, multiple horizontal target horizons, extensive production history and historically high drilling success rates. The STACK is an acronym describing both its location – Sooner Trend Anadarko Basin Canadian and Kingfisher County – and the multiple, stacked productive formations present in the area. We maintain operational control of the majority of our properties, either through directly operating them or through operating arrangements with other interest owners.

The amount of revenue 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, natural gas and natural gas liquids we produce; and

•the level of our operating and administrative costs.

In order to mitigate the impact of changes in oil, natural gas and natural gas liquids 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 price volatility on our cash flows.

Substantially all of our oil and natural gas activities are conducted jointly with others and, accordingly, amounts presented reflect our proportionate interest in such activities. Inflation has not had a material impact on our results of operations and is not expected to have a material impact on our consolidated results of operations in the future.

Contribution Agreement

On August 16, 2017, we entered into a Contribution Agreement (the “Contribution Agreement”) with Silver Run Acquisition Corporation II, a Delaware corporation (“SRII”), High Mesa Holdings, LP, a Delaware limited partnership (“HMH”), High Mesa Holdings GP, LLC, a Texas limited liability company, our General Partner and solely for certain provisions therein, the equity owners of HMH. Pursuant to the Contribution Agreement, SRII will acquire from HMH (i) all of its limited partner interest in us and (ii) 100% of the economic interests and 90% of the voting interests in our General Partner. In return, HMH will receive: (i) 220,000,000 common units as adjusted of SRII Opco, LP, a Delaware limited partnership and wholly owned subsidiary of SRII; (ii) $400 million in cash, which shall be contributed to us; and (iii) up to $800 million in earn-out consideration in the form of common units of SRII Opco, LP (the “Earn-out Consideration”). The Earn-out Consideration will be paid as set forth below if the 20-day volume-weighted average price (“VWAP”) of the Class A Common Stock of SRII (the “Class A Common Stock”) equals or exceeds the following prices:


20-Day
VWAP		Earn-Out Consideration
$	14.00	10,714,285 Common Units
$	16.00	9,375,000 Common Units
$	18.00	13,888,889 Common Units
$	20.00	12,500,000 Common Units

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Amended Partnership Agreement

Riverstone was admitted as a limited partner in connection with its $200 million capital contribution to us on August 17, 2017, in exchange for limited partner interests in us. We used all of the capital contribution to pay down our credit facility.

Outlook, Market Conditions and Commodity Prices

Our revenue, profitability and future growth rate depend on many factors, particularly the prices of oil, natural gas and natural gas liquids, which are beyond our control. The relatively low level of natural gas prices prompted our shift in emphasis to oil and natural gas liquids over the past several years. Accordingly, the success of our business is significantly affected by the price of oil due to our current focus on development of oil reserves. Oil prices are subject to significant changes. Beginning in the third quarter of 2014, the price for oil began a dramatic decline, and current prices for oil are significantly less than they have been historically. Factors affecting the oil prices include worldwide economic conditions, including the European credit markets; geopolitical activities, including developments in the Middle East, South America, and elsewhere; worldwide supply conditions; weather conditions; actions taken by the Organization of Petroleum Exporting Countries; and the value of the U.S. dollar in international currency markets. Sustained low prices for oil, natural gas and natural gas liquids could have a material adverse effect on our financial condition, the carrying value of our oil and natural gas properties, our proved reserves and our ability to finance operations, including the amount of our borrowing base under our senior secured revolving credit facility.

During the twelve month period ended September 30, 2017, NYMEX West Texas Intermediate (“NYMEX WTI”) oil prices ranged from a high of $53.46 per Bbl in February 2017 to a low of $45.20 per Bbl in June 2017. During the third quarter of 2017, NYMEX WTI prices averaged approximately $48.20 per Bbl compared to $44.94 per Bbl for the same period of 2016. We received an average price of $47.20 per Bbl for the third quarter of 2017 before the effects of hedging. NYMEX Henry Hub natural gas prices (“NYMEX HH”) have also been volatile and ranged from a high of $3.93 per MMBtu in January 2017 to a low of $2.63 in March 2017. During the third quarter of 2017, NYMEX HH prices averaged approximately $3.00 per MMBtu compared to $2.81 per MMBtu for the same period of 2016. We received an average price of $2.50 per Mcf for natural gas in the third quarter of 2017 before the effects of hedging. On November 7, 2017, NYMEX WTI was $57.20 per Bbl and NYMEX HH was $3.15 per Mcf. Commodity prices remain volatile and unpredictable but have improved over the last year.

We have increased our anticipated capital expenditures, including acquisitions, for 2017 to $375 million, which is approximately 66% over the $226 million of capital expenditures, including acquisitions made in 2016. Additionally, we anticipate that up to an additional $111 million will be funded for 2017 drilling and completions activity in the STACK by BCE-STACK Development LLC (“BCE”) pursuant to our joint development agreement. For the nine months ended September 30, 2017, we have received approximately $92.7 million from BCE under our joint development agreement. We have allocated over 95% of our 2017 capital expenditure to develop the STACK. We anticipate operating up to six drilling rigs by the end of 2017, which will result in drilling a

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total of approximately 116 gross wells in the STACK in 2017. Of the total anticipated gross wells to be drilled in 2017, we plan to drill approximately 35 gross wells as part of our joint development agreement with BCE. As of September 30, 2017, we have drilled 43 BCE wells of which 20 BCE wells were drilled in 2016.

Our derivative contracts are reported at fair value on our condensed consolidated balance sheets and are sensitive to changes in the price of oil, natural gas and natural gas liquids. Changes in these derivative assets and liabilities are reported in our condensed consolidated statements of operations as gain (loss) on derivative contracts, which include both the non-cash increase and 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 2017, we recognized a net gain on our derivative contracts of $38.0 million, which includes $1.8 million in cash settlements received on 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, natural gas and natural gas liquids 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 these gains and losses will continue to reflect changes in oil, natural gas and natural gas liquids prices.

As of September 30, 2017, we have hedged approximately 73% of our forecasted production of proved developed producing reserves through 2019 at weighted average annual floor prices ranging from $3.18 per MMBtu to $4.43 per MMBtu for natural gas and $50.00 per Bbl to $51.37 per Bbl for oil. If oil, natural gas and natural gas liquids prices decline for an extended period of time, we may be unable to replace expiring hedge contracts or enter new contracts for additional oil, natural gas and natural gas liquids production at favorable prices.

Depressed oil, natural gas and natural gas liquids prices have impacted our earnings by necessitating impairment write-downs in some of our oil and natural gas properties, either directly by decreasing the market values of the properties, or indirectly, by lowering rates of return on oil and natural gas development projects and increasing the chance of impairment write-downs. We recorded total non-cash impairment expenses of $29.2 million and $14.2 million for the nine months ended September 30, 2017 and 2016, respectively. Approximately $18.8 million of the total impairment expense in the first nine months of 2017 were related to non-STACK undeveloped acreage not intended to be developed. In the nine months ended September 30, 2017, write-downs were primarily due to downward revisions in proved reserves and the effects of decreased prices for oil, natural gas and natural gas liquids on producing wells and undeveloped acreage in certain non-STACK fields. In the nine months ended September 30, 2016, our impairments were primarily related to our non-STACK properties. Further declines in oil and/or natural gas prices may result in additional impairment expenses.

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.

Operations Update

STACK, Oklahoma. Our STACK properties consist largely of contiguous leased acreage primarily in Kingfisher County, Oklahoma, which is the eastern portion of the Anadarko Basin referred to as the STACK, an acronym describing both its location – Sooner Trend Anadarko Basin Canadian and Kingfisher County – and the multiple, stacked pay zones present in the area. This continuously growing position is characterized by multiple productive zones located at total vertical depths between 4,000 feet and 8,000 feet. The legacy operations within our acreage are primarily shallow-decline, long-lived oil fields developed on 80-acre vertical well spacing associated with waterfloods in the Oswego, Big Lime and Manning Limestones. We continue to maintain production in these historical field pay zones. More recently, our focus in the STACK has been to implement a multi-year, multi-rig program to develop the Mississippian-age Osage and Meramec formations underlying the waterflood zones, as well as the Pennsylvanian-age Oswego formation, using horizontal drilling and multi-stage hydraulic fracturing technology.

In the third quarter of 2017, we brought 36 horizontal wells on production in the Osage/Meramec interval of the STACK, eight of which were funded through our joint development agreement with BCE. We had 43 horizontal wells in progress as of the end of the third quarter of 2017, nine of which were funded through our joint development agreement with BCE. Subsequent to the end of the third quarter of 2017, 13 of the 43 horizontal wells in progress as of September 30, 2017 were on production.

As of September 30, 2017, we had six drilling rigs operating in the STACK. We plan to continue targeting the Mississippian-age Osage, Meramec, and Manning formations and the Pennsylvanian-age Oswego formation with horizontal drilling. We will also participate in other horizontal wells as a non-operator, primarily targeting the Oswego Lime, Meramec and Osage formations.

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Production from our STACK assets in the third quarter of 2017 was an average of approximately 20,400 BOE/d net to our interest, 67% oil and natural gas liquids, as compared to an average of approximately 13,600 BOE/d, 67% oil and natural gas liquids, in the third quarter of 2016. Production from our STACK properties in the first nine months of 2017 was an average of approximately 20,000 BOE/d net to our interest, 67% oil and natural gas liquids, as compared to an average of approximately 12,300 BOE/d, 72% oil and natural gas liquids, in the first nine months of 2016.

Weeks Island Area, Louisiana. The Weeks Island Area, located in Iberia and St. Mary Parish, Louisiana, contains our most significant conventional proved developed oil reserves and consists of the Weeks Island and Cote Blanche Island fields. The Weeks Island field, located in Iberia Parish, Louisiana, is a historically-prolific oil field with 55 potential pay zones that are structurally and stratigraphically trapped around a piercement salt dome, which we believe offer significant future opportunities for added production and reserves. The Cote Blanche Island field, located near the Weeks Island field in St. Mary Parish, is also a salt dome structure. The geology is similar to the Weeks Island field, and we anticipate that the same geologic interpretation methods and engineering development techniques could be utilized at the Cote Blanche Island field that were used at the Weeks Island field to increase reserves and production.

Production from the Weeks Island Area in the third quarter of 2017 was approximately 2,100 BOE/d, net to our interest, 96% oil, as compared to 3,100 BOE/d, 91% oil, for the third quarter of 2016. Production from the Weeks Island Areas in the first nine months of 2017 was approximately 2,200 BOE/d, net to our interest, 96% oil, as compared to 3,700 BOE/d, 91% oil in the first nine months of 2016.

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Results of Operations: Three Months Ended September 30, 2017 v. Three Months Ended September 30, 2016



	Three Months Ended September 30,				Increase
	2017		2016		(Decrease)		% Change

	(in thousands, except average sales prices and unit costs)
Summary Operating Information:
Net Production:
Oil (MBbls)		1,169		945		224	24%
Natural gas (MMcf)		4,788		3,873		915	24%
Natural gas liquids (MBbls)		349		254		95	37%
Total oil equivalent (MBOE)		2,316		1,844		472	26%
Average daily oil production (MBOE per day)		25.2		20.0		5.2	26%
Average Sales Price:
Oil (per Bbl) including settlements of derivative contracts	$	48.00	$	60.35	$	(12.35)	(20)%
Oil (per Bbl) excluding settlements of derivative contracts		47.20		43.08		4.12	10%
Natural gas (per Mcf) including settlements of derivative contracts		2.71		2.92		(0.21)	(7)%
Natural gas (per Mcf) excluding settlements of derivative contracts		2.50		2.53		(0.03)	(1)%
Natural gas liquids (per Bbl) including settlements of derivative contracts		22.14		15.85		6.29	40%
Natural gas liquids (per Bbl) excluding settlements of derivative contracts		23.29		15.75		7.54	48%
Combined (per BOE) including settlements of derivative contracts		33.16		39.23		(6.07)	(15)%
Combined (per BOE) excluding settlements of derivative contracts		32.50		29.55		2.95	10%
Hedging Activities:
Settlements of derivatives received, oil	$	925	$	16,310	$	(15,385)	(94)%
Settlements of derivatives received, natural gas		994		1,513		(519)	(34)%
Settlements of derivatives (paid) received, natural gas liquids		(398)		25		(423)	NA
Summary Financial Information
Operating Revenues and Other
Oil	$	55,195	$	40,691	$	14,504	36%
Natural gas		11,959		9,790		2,169	22%
Natural gas liquids		8,119		3,994		4,125	103%
Other revenues		72		57		15	26%
Loss on sale of assets		—		(8)		(8)	(100)%
Gain on acquisition of oil and gas properties		5,267		—		5,267	100%
Gain (loss) on derivative contracts		(10,468)		3,508		(13,976)	(398)%
Total Operating Revenues and Other		70,144		58,032		12,112	21%
Expenses
Lease and plant operating expense		15,503		14,644		859	6%
Marketing and transportation expense		8,666		5,254		3,412	65%
Production and ad valorem taxes		2,705		2,895		(190)	(7)%
Workover expense		1,714		727		987	136%
Exploration expense		5,523		8,590		(3,067)	(36)%
Depreciation, depletion, and amortization expense		28,784		22,433		6,351	28%
Impairment expense		82		919		(837)	(91)%
Accretion expense		395		540		(145)	(27)%
General and administrative expense		17,458		10,650		6,808	64%
Interest expense, net		13,518		17,947		(4,429)	(25)%
Net Loss	$	(24,204)	$	(26,567)	$	2,363	9%
Average Unit Costs per BOE:
Lease and plant operating expense	$	6.69	$	7.94	$	(1.25)	(16)%
Marketing and transportation expense		3.74		2.85		0.89	31%
Production and ad valorem tax expense		1.17		1.57		(0.40)	(25)%
Workover expense		0.74		0.39		0.35	90%
Exploration expense		2.38		4.66		(2.28)	(49)%
Depreciation, depletion and amortization expense		12.43		12.17		0.26	2%
General and administrative expense		7.54		5.78		1.76	30%

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Revenues

Oil revenues in the three months ended September 30, 2017 increased $14.5 million, or 36%, to $55.2 million from $40.7 million in the corresponding period in 2016. The increase in revenue was primarily attributable to an increase in average price as well as an increase in production during the third quarter of 2017. The average price of oil exclusive of derivative contract settlements increased $4.12 per Bbl or 10% in the third quarter of 2017 compared to the third quarter of 2016, resulting in an increase in oil revenues of approximately $4.8 million. When including the effects of derivative contract settlements, the overall price decreased 20% from $60.35 per Bbl in the third quarter of 2016 to $48.00 per Bbl in the third quarter of 2017. The overall price in the third quarter of 2017 included no settlements of oil derivative contracts prior to contract expiry compared to $18.2 million of similar settlements of oil derivative contracts in the corresponding period in 2016. Production increased 224 MBbls, resulting in an increase of $9.7 million in oil revenues. The oil production volume increase is primarily due to new production from wells coming online in the STACK of 319 MBbls, partially offset by a decrease in production in the Weeks Island Area of 78 MBbls due to natural decline in production.

Natural gas revenues in the three months ended September 30, 2017 increased $2.2 million, or 22%, to $12.0 million from $9.8 million in the same period in 2016. The increase in natural gas revenue was primarily attributable to an increase in production, partially offset by a decrease in average price during the third quarter of 2017. Production increased 0.9 Bcf resulting in an increase of $2.3 million in natural gas revenues. The natural gas volume increase is primarily due to new production from wells coming online in the STACK of 1.2 Bcf as natural gas is produced in association with oil, partially offset by decreases in the Weeks Island Area and one other non-STACK area of approximately 0.2 Bcf. The average price of natural gas exclusive of derivative contract settlements decreased $0.03 per Mcf in the third quarter of 2017, resulting in a decrease in natural gas revenues of approximately $0.1 million. When including the effects of derivative contract settlements, the overall price decreased 7% from $2.92 per Mcf in the third quarter of 2016 to $2.71 per Mcf in the third quarter of 2017. There were no settlements of natural gas derivative contracts prior to contract expiry in the third quarter of 2017; however, the overall price in the third quarter of 2016 included settlements of natural gas derivative contracts prior to contract expiry of approximately $2.4 million.

Natural gas liquids revenues increased $4.1 million, or 103%, during the third quarter of 2017 to $8.1 million from $4.0 million in the same period in 2016. The increase in natural gas liquids revenue was attributable to an increase in average price as well as an increase in processed volumes during the third quarter of 2017. The average price of natural gas liquids exclusive of derivative contract settlements increased $7.54 per Bbl in the third quarter of 2017 compared to the third quarter of 2016, resulting in an increase in natural gas liquids revenues of $2.6 million. The overall price including derivative contract settlements increased 40% from $15.85 per Bbl in the third quarter of 2016 to $22.14 per Bbl in the third quarter of 2017. Production increased 95 MBbls from 254 MBbls to 349 MBbls, resulting in an increase of $1.5 million in natural gas liquids revenues. The natural gas liquids volume is predominately in the STACK where natural gas liquid processed volumes increased 107 MBbls, partially offset by a decrease in production in our non-STACK assets of approximately 15 MBbls.

Gain on acquisition of oil and gas properties was a gain of $5.3 million in the third quarter of 2017, primarily related to the acquisition of proved STACK oil and natural gas properties. The fair market value of proven reserves exceeded the allocated purchase price of those assets acquired. The acquisition of Brown and Borelli, et al resulted in a bargain purchase gain as a result of timing from the execution of the purchase and sale agreement to the closing date of the acquisition at which time the value of the underlying properties increased substantially due to increased proved reserves.

Gain (loss) on derivative contracts was a loss of $10.5 million in the third quarter of 2017 as compared to a gain of $3.5 million during the same period in 2016. The fluctuation from period to period is due to the volatility of oil, natural gas and natural gas liquids prices and changes in our outstanding hedge contracts during these periods. The $3.5 million gain in the third quarter of 2016 is inclusive of $17.8 million from settlements received on our derivative contracts of which $18.2 million were from settlements of oil and natural gas derivative contracts prior to contract expiry. In the third quarter of 2017, the $10.5 million loss is inclusive of $1.5 million from settlements received on our derivative contracts of which none were from settlements of oil and natural gas derivative contracts prior to contract expiry.

Expenses

Lease and plant operating expense increased $0.9 million or 6% in the third quarter of 2017 as compared to the third quarter of 2016, to $15.5 million from $14.6 million. In general, there was an increase in compression and chemical costs of $0.9 million. All other costs did not materially fluctuate. On a per unit basis, lease and plant operating expense was $6.69 per BOE and $7.94 per BOE in the third quarters of 2017 and 2016, respectively.

Marketing and transportation expense increased $3.4 million to $8.7 million in the third quarter of 2017 as compared to $5.3 million in the third quarter of 2016. The increase is primarily due to increased throughput for our properties in the STACK at the Kingfisher processing facility commissioned during the second quarter of 2016. In addition, the increase is due to continued higher marketing and transportation fee charged to provide effective gathering, efficient processing and assurance that our production will

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continue to flow as the activity in the basin expands at the Kingfisher processing facility. On a per unit basis, marketing and transportation expense was $3.74 per BOE and $2.85 per BOE in the third quarters of 2017 and 2016, respectively.

Production and ad valorem taxes decreased $0.2 million, or 7%, to $2.7 million in the third quarter of 2017, as compared to $2.9 million in the third quarter of 2016. The decrease is primarily due to a decrease in ad valorem taxes of $0.4 million partially offset by an increase in severance taxes of $0.2 million. The decrease in ad valorem taxes is the result of lower assessed taxable values on our non-STACK assets.

Workover expense increased $1.0 million during the third quarter of 2017, as compared to the third quarter of 2016. This expense varies depending on activities in the field and is attributable to several properties.

Exploration expense includes dry hole costs, the costs of our geology department, costs of geological and geophysical data, expired leases, plug and abandonment expenditures, and delay rentals. Exploration expense decreased $3.1 million to $5.5 million in the third quarter of 2017, as compared to $8.6 million in the third quarter of 2016. The decrease is primarily due to a decrease in geologic and geophysical (“G&G”) seismic expense of $2.7 million and a decrease in expired leasehold of $1.8 million, partially offset by an increase in dry hole cost of $1.4 million related to a non-STACK asset.

Depreciation, depletion and amortization expense increased from $22.4 million in the third quarter of 2016 to $28.8 million in the third quarter of 2017. Depreciation, depletion, and amortization is a function of capitalized costs of proved properties, proved reserves and production by field.

Impairment expense decreased from $0.9 million in the third quarter of 2016 to $0.1 million in the third quarter of 2017. This expense varies with the results of exploratory and development drilling, as well as with well performance, declines in commodity price and other factors that may render some fields uneconomic, resulting in impairment. Impairment expenses in the third quarters of 2017 and 2016 were write-downs related to our non-STACK assets.

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 in the third quarter of 2017 as compared to $0.5 million in the third quarter of 2016.

General and administrative expense increased $6.8 million in the third quarter of 2017 to $17.5 million from $10.7 million in the third quarter of 2016. The increase is primarily due to non-recurring consulting fees attributable to the Contribution Agreement with SRII during the third quarter of 2017 of approximately $2.5 million and settlement expense of $3.6 million. On a per unit basis, general and administrative expenses were $7.54 per BOE and $5.78 per BOE in the third quarters of 2017 and 2016, respectively.

Interest expense, net decreased from $17.9 million in the third quarter of 2016 to $13.5 million in the third quarter of 2017. The interest on our senior unsecured notes decreased $1.1 million due to the repurchase and redemption of our $450 million aggregate principal amount of 9.625% senior unsecured notes due 2018 by issuing $500 million aggregate principal amount of 7.875% senior unsecured notes due 2024 during the fourth quarter of 2016. In addition, interest and deferred financing costs on our senior secured term loan decreased $3.1 million as we retired our $125 million secured term loan during the fourth quarter of 2016.

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Results of Operations: Nine Months Ended September 30, 2017 v. Nine Months Ended September 30, 2016


	Nine Months Ended September 30,				Increase
	2017		2016		(Decrease)		% Change

	(in thousands, except average sales prices and unit costs)
Summary Operating Information:
Net Production:
Oil (MBbls)		3,533		2,985		548	18%
Natural gas (MMcf)		14,073		10,017		4,056	40%
Natural gas liquids (MBbls)		995		691		304	44%
Total oil equivalent (MBOE)		6,873		5,346		1,527	29%
Average daily oil production (MBOE/Day)		25.2		19.5		5.7	29%
Average Sales Price:
Oil (per Bbl) including settlements of derivative contracts	$	48.25	$	64.60	$	(16.35)	(25)%
Oil (per Bbl) excluding settlements of derivative contracts		48.01		38.78		9.23	24%
Natural gas (per Mcf) including settlements of derivative contracts		2.81		2.70		0.11	4%
Natural gas (per Mcf) excluding settlements of derivative contracts		2.68		2.02		0.66	33%
Natural gas liquids (per Bbl) including settlements of derivative contracts		22.14		14.67		7.47	51%
Natural gas liquids (per Bbl) excluding settlements of derivative contracts		22.93		14.62		8.31	57%
Combined (per BOE) including settlements of derivative contracts		33.75		43.02		(9.27)	(22)%
Combined (per BOE) excluding settlements of derivative contracts		33.49		27.34		6.15	22%
Hedging Activities:
Settlements of derivatives received, oil	$	846	$	77,085	$	(76,239)	(99)%
Settlements of derivatives received, natural gas		1,719		6,724		(5,005)	(74)%
Settlements of derivatives (paid) received, natural gas liquids		(790)		30		(820)	NA
Summary Financial Information
Revenues and other
Oil	$	169,611	$	115,778	$	53,833	46%
Natural gas		37,780		20,277		17,503	86%
Natural gas liquids		22,814		10,109		12,705	126%
Other revenues		274		358		(84)	(23)%
Gain on sale of assets		—		3,723		(3,723)	(100)%
Gain on acquisition of oil and gas properties		6,893		—		6,893	100%
Gain (loss) on derivative contracts		38,024		(23,970)		61,994	259%
Total Operating Revenues and Other		275,396		126,275		149,121	118%
Expenses
Lease and plant operating expense		49,836		45,222		4,614	10%
Marketing and transportation expense		21,566		8,140		13,426	165%
Production and ad valorem taxes		8,812		8,021		791	10%
Workover expense		5,112		3,242		1,870	58%
Exploration expense		19,930		15,304		4,626	30%
Depreciation, depletion, and amortization expense		80,082		66,857		13,225	20%
Impairment expense		29,206		14,238		14,968	105%
Accretion expense		1,447		1,615		(168)	(10)%
General and administrative expense		35,534		32,909		2,625	8%
Interest expense, net		38,189		51,581		(13,392)	(26)%
Provision for state income taxes		285		107		178	166%
Net Loss	$	(14,603)	$	(120,961)	$	106,358	88%
Average Unit Costs per BOE:
Lease and plant operating expense	$	7.25	$	8.46	$	(1.21)	(14)%
Marketing and transportation expense		3.14		1.52		1.62	107%
Production and ad valorem tax expense		1.28		1.50		(0.22)	(15)%
Workover expense		0.74		0.61		0.13	21%
Exploration expense		2.90		2.86		0.04	1%
Depreciation, depletion and amortization expense		11.65		12.51		(0.86)	(7)%
General and administrative expense		5.17		6.16		(0.99)	(16)%

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Revenues

Oil revenues in the nine months ended September 30, 2017 increased $53.8 million, or 46%, to $169.6 million from $115.8 million in the corresponding period in 2016. The increase in revenue was primarily attributable to an increase in average price as well as an increase in production. The average price of oil exclusive of derivative contract settlements increased $9.23 per Bbl or 24% in the first nine months of 2017 compared to the first nine months of 2016, resulting in an increase in oil revenues of approximately $32.6 million. When including the effects of derivative contract settlements, the overall price decreased 25% from $64.60 per Bbl in the first nine months of 2016 to $48.25 per Bbl in the first nine months of 2017. The overall price included settlement of oil derivative contracts prior to contract expiry of approximately $0.9 million in the first nine months of 2017 compared to $56.0 million of similar settlements of oil derivative contracts in the corresponding period in 2016. Production increased 548 MBbls, resulting in an increase of $21.2 million in oil revenues. The oil production volume increase is primarily due to new production from wells coming online in the STACK of 943 MBbls, partially offset by a decrease in production in the Weeks Island Area and other non-STACK assets of 390 MBbls due to a natural decline in production.

Natural gas revenues in the nine months ended September 30, 2017 increased $17.5 million, or 86%, to $37.8 million from $20.3 million in the same period in 2016. The increase in natural gas revenue was primarily attributable to an increase in average price as well as an increase in production during the first nine months of 2017. The average price of natural gas exclusive of derivative contract settlements increased $0.66 per Mcf in the first nine months of 2017, resulting in an increase in natural gas revenues of approximately $9.3 million. When including the effects of derivative contract settlements, the overall price increased 4% from $2.70 per Mcf in the first nine months of 2016 to $2.81 Mcf in the first nine months of 2017. The overall price in the first nine months of 2016 includes $2.4 million we received related to settlement of several of our natural gas derivative contracts prior to contract expiry. Production increased 4.1 Bcf resulting in an increase of $8.2 million in natural gas revenues. The natural gas volume increase is primarily due to new production from wells coming online in the STACK of 5.1 Bcf as natural gas is produced in association with oil, partially offset by production declines of 0.9 Bcf from non-STACK assets.

Natural gas liquids revenues increased $12.7 million, or 126%, during the first nine months of 2017 to $22.8 million from $10.1 million in the same period in 2016. The increase in natural gas liquids revenue was attributable to an increase in higher average price as well as an increase in processed volumes during the first nine months of 2017. The average price of natural gas liquids exclusive of derivative contract settlements increased $8.31 per Bbl or 57% in the first nine months of 2017 compared to the first nine months of 2016, resulting in an increase in natural gas liquids revenues of $8.3 million. The overall price including derivative contract settlements increased 51% from $14.67 per Bbl in the first nine months of 2016 to $22.14 per Bbl in the first nine months of 2017. Production increased 304 MBbls from 691 MBbls to 995 MBbls, resulting in an increase of $4.4 million in natural gas liquids revenue. The natural gas liquids volume is predominately in the STACK where natural gas liquids processed volumes increased 321 MBbls.

Gain on sale of assets was a gain of $3.7 million in the first nine months of 2016, primarily due to the sale of certain non-STACK assets.

Gain on acquisition of oil and gas properties was a gain of $6.9 million in the first nine months of 2017, primarily related to the acquisition of STACK oil and natural gas properties. The fair market value of proven reserves exceeded the allocated purchase price of those assets acquired. The acquisition of Brown and Borelli, et al resulted in a bargain purchase gain of approximately $5.3 million as a result of timing from the execution of the purchase and sale agreement to the closing date of the acquisition at which time the value of the underlying properties increased substantially due to increased proved reserves. The Setanta acquisition resulted in a bargain purchase gain of approximately $1.6 million as a result of the seller’s financial distress and needing to dispose of the underlying properties for cash in an expedited manner which resulted in a below market purchase price.

Gain (loss) on derivative contracts was a gain of $38.0 million in the first nine months of 2017 as compared to a loss of $24.0 million during the same period in 2016. The fluctuation from period to period is due to the volatility of oil, natural gas and natural gas liquid prices and changes in our outstanding hedge contracts during these periods. The $24.0 million loss in the first nine months of 2016 is inclusive of $83.8 million in settlements received on derivative contracts of which $58.4 million were from settlements of oil and natural gas derivative contracts prior to contract expiry. The $38.0 million gain in the first nine months of 2017 is inclusive of $1.8 million in settlements received on derivative contracts of which $0.9 million were from settlements of oil and natural gas derivative contracts prior to contract expiry.

Expenses

Lease and plant operating expense increased $4.6 million or 10% in the first nine months of 2017 as compared to the first nine months of 2016, to $49.8 million from $45.2 million. The increase is primarily due to an increase in compression, chemical, field services, and salt water disposal fees of $4.7 million, partially offset by an aggregate decrease in the remaining cost categories. On a per unit basis, lease and plant operating expense was $7.25 per BOE and $8.46 per BOE in the first nine months of 2017 and 2016, respectively.

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Marketing and transportation expense increased $13.4 million to $21.5 million in the first nine months of 2017 as compared to $8.1 million in the first nine months of 2016. The increase is primarily due to increased throughput for our properties in the STACK at the Kingfisher processing facility commissioned during the second quarter of 2016. In addition, the increase is due to continued higher marketing and transportation fee charged to provide effective gathering, efficient processing and assurance that our production will continue to flow as the activity in the basin expands at the Kingfisher processing facility. On a per unit basis, marketing and transportation expense was $3.14 per BOE and $1.52 per BOE in the first nine months of 2017 and 2016, respectively.

Production and ad valorem taxes increased $0.8 million, or 10%, to $8.8 million in the first nine months of 2017, as compared to $8.0 million in the first nine months of 2016. The increase is primarily due to an increase in production taxes of $1.3 million as a result of the increase in oil, natural gas and natural gas liquids revenues, partially offset by a decrease in ad valorem taxes of $0.5 million. Production taxes increased from $6.6 million in the first nine months of 2016 to $7.9 million in the first nine months of 2017.

Workover expense increased $1.9 million during the first nine months of 2017, as compared to the first nine months of 2016. This expense varies depending on activities in the field and is attributable to several properties.

Exploration expense includes dry hole costs, the costs of our geology department, costs of geological and geophysical data, expired leases, plug and abandonment expenditures, and delay rentals. Exploration expense increased $4.6 million to $19.9 million in the first nine months of 2017, as compared to $15.3 million in the first nine months of 2016. The increase is primarily due to an increase in expired leasehold and settlements of our asset retirement obligation in excess of our estimate of $4.1 million and an increase of dry hole expense of $2.0 million, partially offset by a decrease in G&G seismic expense of $1.4 million.

Depreciation, depletion and amortization expense increased from $66.9 million in the first nine months of 2016 to $80.1 million in the first nine months of 2017. Depreciation, depletion, and amortization is a function of capitalized costs of proved properties, proved reserves and production by field. In addition, the impairment of proved properties in the third quarter of 2017 and in previous periods and an increase in proved reserves contributed to the lowered depletable base and rate in the first nine months of 2017.

Impairment expense increased from $14.2 million in the first nine months of 2016 to $29.2 million in the first nine months of 2017. This expense varies with the results of exploratory and development drilling, as well as with well performance, declines in commodity price and other factors that may render some fields uneconomic, resulting in impairment. Impairment expense in the first nine months of 2017 and 2016 were primarily write-downs in our non-STACK assets.

Accretion expense is related to our obligation for retirement of oil and natural gas wells and facilities. We record these liabilities when we place the assets in service, using discounted present values of the estimated future obligation. We then record accretion of the liabilities as they approach maturity. Accretion expense was $1.4 million and $1.6 million in the first nine months of 2017 and 2016, respectively.

General and administrative expense increased $2.6 million in the first nine months of 2017 to $35.5 million from $32.9 million in the first nine months of 2016. The increase is primarily due to the non-recurring consulting fees attributable to the Contribution Agreement with SRII during the first nine months of 2017 of approximately $2.5 million and settlement expense of $3.8 million. In addition, information systems maintenance fees increased $1.3 million. These increases were partially offset by a decrease in salary and benefits of $2.1 million including prior period performance bonus accrual adjustments, and a decrease in legal fees of $3.1 million. During the first nine months of 2016, legal fees included non-recurring tender offer fees of $1.8 million. On a per unit basis, general and administrative expenses were $5.17 per BOE and $6.16 per BOE in the first nine months of 2017 and 2016, respectively.

Interest expense, net decreased from $51.6 million in the first nine months of 2016 to $38.2 million in the first nine months of 2017. The interest on our senior unsecured notes decreased $3.3 million due to the repurchase and redemption of our $450 million aggregate principal amount of 9.625% senior unsecured notes due 2018 by issuing $500 million aggregate principal amount of 7.875% senior unsecured notes due 2024. In addition, interest including amortization of deferred financing cost on our senior secured term loan decreased $9.2 million as we retired our $125 million secured term loan during the fourth quarter of 2016.

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 payment of debt interest and any amounts owed during the period related to our hedging positions.

Our 2017 capital budget is primarily focused on the development of our STACK play. Currently, we plan to spend approximately $375 million in 2017, which includes acquisitions, of which over 95% is allocated to develop our STACK properties. Additionally, we anticipate that up to an additional $111 million will be funded for 2017 drilling and completions activity in the STACK by BCE pursuant to our joint development agreement. For the nine months ended September 30, 2017, we have received approximately $92.7 million from BCE under our joint development agreement. We have expended approximately $299.5 million of our capital budget through September 30, 2017. 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 the consummation of the transactions

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under the Contribution Agreement, drilling results, oil, natural gas and natural gas liquids 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. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could result in a reduction in anticipated production, revenues and cash flows. Additionally, if we curtail our drilling program, we may lose a portion of our acreage through lease expirations. However, because a large percentage of our acreage is held by production, we have the ability to materially increase or decrease our drilling and recompletion budget in response to market conditions with decreased risk of losing significant acreage. In addition, we may be required to reclassify some portion of our reserves currently booked as proved undeveloped reserves to no longer be proved reserves if such a deferral of planned capital expenditures means we will be unable to develop such reserves within five years of their initial booking.

We expect to fund our 2017 capital budget predominantly with cash flows from operations, drilling and completion capital funded through our joint development agreement with BCE, the capital contribution from Riverstone and borrowings under our senior secured revolving credit facility. If necessary, we may also access capital through proceeds from potential asset dispositions and the future issuances of debt and/or equity securities, subject to the distribution of proceeds therefrom as set forth in our partnership agreement. We strive to maintain financial flexibility and may access capital markets as necessary to 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.

As we execute our business strategy, we will continually monitor the capital resources available to meet future financial obligations and planned capital expenditures. We believe our cash flows provided by operating activities, cash on hand and availability under our senior secured revolving credit facility will provide us with the financial flexibility and wherewithal to meet our cash requirements, including normal operating needs, and to pursue our currently planned 2017 development drilling activities. However, future cash flows are subject to a number of variables, including the level of oil, natural gas and natural gas liquids production and prices, and significant additional capital expenditures will be required to more fully develop our properties and acquire additional properties. We cannot make assurances that operational and other needed capital will be available on acceptable terms, or at all.

Senior Unsecured Notes

We have $500 million in aggregate principal amount of 7.875% senior unsecured notes, or the “senior notes”, due December 15, 2024 which were issued at par by us and our wholly owned subsidiary Alta Mesa Finance Services Corp. (collectively, the “Issuers”) during the fourth quarter of 2016. Interest is payable semi-annually on June 15 and December 15 of each year, beginning June 15, 2017. At any time prior to December 15, 2019, we may, from time to time, redeem up to 35% of the aggregate principal amount of the senior notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 107.875% of the principal amount, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the senior notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. At any time prior to December 15, 2019, we may, on any one or more occasions, redeem all or part of the senior notes for cash at a redemption price equal to 100% of their principal amount of the senior notes redeemed plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of redemption. Upon the occurrence of certain kinds of change of control, each holder of the senior notes may require us to repurchase all or a portion of the senior notes for cash at a price equal to 101% of the aggregate principal amount of the senior notes, plus accrued and unpaid interest, if any, to the date of repurchase. On and after December 15, 2019, we may redeem the senior notes, in whole or in part, at redemption prices (expressed as percentages of principal amount) equal to 105.906% for the twelve-month period beginning on December 15, 2019, 103.938% for the twelve-month period beginning on December 15, 2020, 101.969% for the twelve-month period beginning on December 15, 2021 and 100.000% beginning on December 15, 2022, plus accrued and unpaid interest, if any, to the date of redemption.

The senior notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries, subject to certain customary release provisions. Accordingly, they will rank equal in right of payment to all of our existing and future senior indebtedness; senior in right of payment to all of our existing and future indebtedness that is expressly subordinated to the senior notes or the respective guarantees; effectively subordinated to all of our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including amounts outstanding under our senior secured revolving credit facility; and structurally subordinated to all existing and future indebtedness and obligations of any of our subsidiaries that do not guarantee the senior notes.

The senior notes contain certain covenants limiting the Issuers’ ability and the ability of the Restricted Subsidiaries (as defined in the indenture) to, under certain circumstances, prepay subordinated indebtedness, pay distributions, redeem stock or make certain restricted investments; incur indebtedness; create liens on the Issuers’ assets to secure debt; restrict dividends, distributions or other payments; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries; sell or otherwise transfer or dispose of assets, including equity interests of restricted subsidiaries; effect a consolidation or merger; and change our line of business.

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The indenture contains customary events of default, including:

default in any payment of interest on the senior notes when due, continued for 30 days;

default in the payment of principal of or premium, if any, on the senior notes when due;

failure by the Issuers or any subsidiary guarantor to comply with its obligations under the indenture;

default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any indebtedness for money borrowed by the Issuers or restricted subsidiaries;

certain events of bankruptcy, insolvency or reorganization of the Issuers or restricted subsidiaries; and

failure by the Issuers or certain subsidiaries that would constitute a payment of final judgment aggregating in excess of $20.0 million.

As of September 30, 2017, we were in compliance with the indentures governing the senior notes.

Senior Secured Revolving Credit Facility

In November 2016, we entered into the Seventh Amended and Restated Credit Agreement (as amended, the “credit facility”) with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of banks. On June 13, 2017, we entered into an Agreement and Amendment No. 2 (the “Second Amendment”) to the credit facility which, among other things: (i) increased our borrowing base from $287.5 million to $315.0 million until the next scheduled redetermination and (ii) permits us to make a one-time cash distribution of no more than $1.0 million to a limited partner. Our credit facility does not permit us to borrow funds if at the time of such borrowing, after giving pro forma effect to the application of funds from the borrowing, we have available cash in our deposit accounts in excess of $25 million. Our credit facility also does not permit us to borrow funds if at the time of such borrowing we are not in pro forma compliance with our financial covenants.

As of September 30, 2017, we have borrowed $75.1 million under the credit facility and have $5.3 million of outstanding letters of credit reimbursement obligations.

Principal amounts borrowed are payable on the maturity date with such borrowings bearing interest, payable quarterly. We have a choice of borrowing in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to the rate appearing on the Reuters Reference LIBOR01 page as the London Interbank Offered Rate (“LIBOR”), for deposits in dollars at 11:00 a.m. (London, England time) for one, three, or six months plus an applicable margin ranging from 275 to 375 basis points if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing base utilized, and ranging from 300 to 400 basis points if our leverage ratio exceeds 3.25 to 1.00. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 1%, plus an applicable margin ranging from 1.75% to 2.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing base utilized, and ranging from 2.00% to 3.00% if our leverage ratio exceeds 3.25 to 1.00.

On November 14, 2017, our outstanding borrowing under the credit facility was $122.1 million, letters of credit totaling $13.6 million were outstanding, and the available unused capacity of the borrowing base was $179.3 million. Availability under the credit facility is subject to a borrowing base, as well as financial covenants. The next scheduled redetermination of our borrowing base is in November 2017. Our borrowing base may be reduced in connection with the next redetermination of our borrowing base. The amounts outstanding under our credit facility are secured by first priority liens on substantially all of our oil and natural gas properties and associated assets and all of the stock of our material operating subsidiaries that are guarantors of our credit facility. If an event of default occurs under our credit facility, the administrative agent will have the right to proceed against the pledged capital stock and take control of substantially all of our and our material operating subsidiaries that are guarantors’ assets.

Our credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, guaranty or make loans to others, make investments, enter into mergers, make certain payments and distributions, enter into or be party to hedge agreements, amend our organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. Our credit facility permits us to make distributions in any fiscal quarter so long as the amount of distributions made in such fiscal quarter does not exceed our excess cash flow from the immediately preceding fiscal quarter, no event of default exists, before and after giving effect to such distribution, our pro forma leverage ratio is less than 3.00 to 1.00 and before and after giving effect to such distribution the unused commitment amounts available under our credit facility is at least 20% of the commitments in effect.

Our credit facility also requires us to maintain the following two financial ratios:

•a modified current ratio, tested quarterly, of our consolidated current assets to our consolidated current liabilities of not less than 1.0 to 1.0 as of the end of each fiscal quarter; and

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•a leverage ratio, tested quarterly, commencing with the fiscal quarter ended December 31, 2016, of our consolidated debt (other than obligations under hedge agreements) as of the end of such fiscal quarter to our consolidated EBITDAX over the four quarter period then ended) of not greater than 4.0 to 1.0.

We were in compliance with all of the covenants under our credit facility at September 30, 2017 and we expect to maintain compliance.

The terms of the credit facility also restrict our ability to make distributions and investments. As of September 30, 2017, the covenants of our credit facility prohibit us from making any distributions, except for the $1.0 million one-time distribution to a limited partner.

Cash flow provided by operating activities

Operating activities provided cash of $55.5 million during the nine months ended September 30, 2017 as compared to $7.5 million during the comparable period in 2016, resulting in an increase in cash of $48.0 million. The increase in operating cash flows was attributable to various factors. Cash-based items of net loss including revenues (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense, resulted in a net decrease of approximately $10.9 million in the first nine months of 2017. Changes in restricted cash, working capital and other assets and liabilities resulted in an increase of $58.9 million in the first nine months of 2017 as compared to the corresponding period in 2016.

Cash flow used in investing activities

Investing activities used cash of $301.1 million during the nine months ended September 30, 2017 as compared to cash used by investing activities of $147.8 million during the comparable period of 2016. Capital expenditures for property and equipment, including acquisitions used cash of $299.5 million and $149.2 million in the first nine months of 2017 and 2016, respectively. Sales of properties provided proceeds of $1.4 million in the first nine months of 2016. In addition, we entered into an interest bearing promissory note receivable with our affiliate Northwest Gas Processing, LLC for approximately $1.5 million during the first nine months of 2017. See Note 14 to our condensed consolidated financial statements entitled “Related Party Transactions.”

Cash flow provided by financing activities

Financing activities provided cash of $242.1 million during the nine months ended September 30, 2017 as compared to $139.6 million during the comparable period in 2016. During the first nine months of 2017, we increased our borrowings under our credit facility by approximately $34.4 million (net), and paid $0.2 million of deferred financing costs related to our credit facility and senior notes. In addition, we received approximately $7.9 million in capital contributions from High Mesa and $200 million in capital contributions from Riverstone in connection with their admittance as a limited partner. During the first nine months of 2016, we drew down $141.9 million on our credit facility and deposited the cash in a controlled account pursuant to the Thirteenth Amendment of our credit facility. We paid down our credit facility by approximately $1.5 million and we paid $0.8 million of deferred financing costs related to our credit facility.

Cautionary Statement Regarding Forward-Looking Statements

The information in this report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). 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”, the negative of such terms and other 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 2016 Annual Report 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:

ability to effect the business combination;

the benefits of the business combination;

the future financial performance of the combined company following the business combination;

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business strategy;

reserves quantities and the present value of our reserves;

exploration and drilling prospects, inventories, projects and programs;

our horizontal drilling, completion and production technology;

ability to replace the reserves we produce through drilling and property acquisitions;

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

future oil, and natural gas prices;

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

hedging strategy and results;

drilling and completion of wells, including statements about future horizontal drilling plans;

competition and government regulation;

ability to obtain permits and governmental approvals;

changes in the Oklahoma forced pooling system;

pending legal and environmental matters;

future drilling plans;

marketing of oil, natural gas and natural gas liquids;

leasehold or business acquisitions;

costs of developing our properties;

liquidity and access to capital;

ability to hire, train or retain qualified personnel;

general economic conditions;

future operating results, including initial production values and liquid yields in our type curve areas

the costs, terms and availability of gathering, processing, fractionation and other midstream services; 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, production, gathering and sale of oil, natural gas and natural gas liquids. Some factors that could cause actual results to differ materially from those expressed or implied by these forward looking statements include, but are not limited to, the occurrence of any event, change or other circumstances that could delay the business combination or give rise to the termination of the Contribution Agreement, the outcome of any legal proceedings that may be instituted against SRII or us following announcement of the transactions, the inability to complete the business combination due to the failure to obtain approval of the stockholders of SRII or other conditions to closing in the Contribution Agreement, the risk that the proposed business combination disrupts our current plans and operations as a result of the announcement and consummation of the transactions, the ability of the combined company to realize the anticipated benefits of the business combination, costs related to the business combination, commodity price volatility, low prices for oil, natural gas and/or natural gas liquids, global economic conditions, inflation, increased operating costs, lack of availability of drilling and production equipment, supplies, services and qualified personnel, uncertainties related to new technologies, geographical concentration of our operations, environmental risks, weather risks, security 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, lack of access to capital, our ability to satisfy future cash obligations, restrictions in our debt agreements, the timing of development expenditures, managing our growth and integration of acquisitions, failure to realize expected value creation from property acquisitions, title defects, limited control over non-operated properties, and the other risks described under “Item 1A. Risk Factors” in our 2016 Annual Report and in this report.

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. Specifically, future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. In addition, the results of drilling, testing and

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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 2016 Annual Report 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 2016 Annual Report. There have been no material changes to the disclosure regarding market risks other than as noted below. See Part I, Item 1, Notes 6 and 7 to our condensed consolidated financial statements for a description of our outstanding derivative contracts at the most recent reporting date.

The fair value of our commodity derivative contracts at September 30, 2017 was a net asset of $11.9 million. A 10% increase or decrease in oil, natural gas and natural gas liquids 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 commodity derivative contracts of approximately $23.1 million (decrease in value) or $21.9 million (increase in value), respectively, as of September 30, 2017.

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 $0.8 million, based on the balance outstanding as of September 30, 2017.

ITEM 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Rules 13a-15 and 15d-15 under the 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, 2017 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, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings

See Part I, Item 1, Note 11 to our condensed consolidated financial statements entitled “Commitments and Contingencies,” which is incorporated in this item by reference.

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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 2016 Annual Report. Other than as set forth below, there have been no material changes with respect to the risk factors disclosed in the 2016 Annual Report during the quarter ended September 30, 2017.

The following risk factors are applicable to the business combination with SRII pursuant to the Contribution Agreement:

The closing of the business combination is subject to many conditions and if these conditions are not satisfied or waived, the business combination will not be completed.

The closing of the business combination is subject to a number of conditions as set forth in the Contribution Agreement that must be satisfied or waived, including, among others, the following (i) the absence of specified adverse laws or orders; (ii) if applicable, the expiration of the waiting period (or extension thereof) under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; (iii) the representations and warranties of the other parties being true and correct, subject to the materiality standards contained in the Contribution Agreement; (iv) material compliance by the other parties with their respective covenants; (v) no material adverse effect having occurred with respect to us since the signing of the Contribution Agreement; (vi) the approval for listing on the NASDAQ of the shares of Class A Common Stock issuable to HMH; and (vii) the approval of the business combination and the transactions by SRII’s stockholders. The closing of the transactions contemplated under the Contribution Agreement is also conditioned upon the simultaneous closing of the Kingfisher contribution agreement and the Riverstone contribution agreement. There can be no assurance whether or when the conditions to closing of the business combination will be satisfied or waived or the business combination will be consummated.

We are subject to business uncertainties and contractual restrictions while the business combination is pending.

Uncertainty about the effect of the business combination on employees and third parties with whom we do business may have an adverse effect on us. These uncertainties may impair our ability to retain and motivate key personnel and could cause third parties that deal with us to defer entering into contracts or making other decisions or seek to change existing business relationships. All of this could negatively affect the financial condition and results of operations of the company and/or the combined company.

Under the terms of the Contribution Agreement, we are subject to certain restrictions on the conduct of our business prior to completing the business combination, which may adversely affect our ability to execute certain of our business strategies, including the ability in certain cases to enter into contracts, acquire or dispose of assets, incur indebtedness or incur capital expenditures. Such limitations could negatively affect our business and operations prior to the completion of the business combination.

Our ability to successfully effect the business combination and successfully operate the business thereafter will be largely dependent upon the efforts of certain key personnel. The loss of such key personnel and our inability to hire and retain replacements could negatively impact the operations and profitability of the combined company following the business combination.

Our ability to successfully effect the business combination and successfully operate the business is dependent upon the efforts of certain key personnel, including our senior management. If any such key personnel depart because of issues relating to the uncertainty of the business combination or a desire not to become employees of the combined company, the combined company’s ability to realize the anticipated benefits of the business combination could be reduced.

We will incur significant transaction costs in connection with the business combination.

We have and expect to incur significant, non-recurring costs in connection with consummating the business combination. Non-recurring transaction costs include, but are not limited to, legal, accounting, consulting, and investment banking fees. Our transaction expenses as a result of the business combination are currently estimated at approximately $12 million and subject to increase. This could limit funds available for operating our business which could have a negative effect on our financial condition.

Our management’s attention from our ongoing business operations may be disrupted due to the business combination.

We have expended, and continue to expend, significant management resources in an effort to complete the business combination. Management’s attention may be diverted away from the day-to-day operations of our business and execution of our existing business plan in our efforts to complete the business combination. This diversion of management resources could disrupt operations and have an adverse effect on our operating results and business.

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ITEM 6. Exhibits


2.1	Contribution Agreement, dated as of August 16, 2017, by and among High Mesa Holdings, LP, High Mesa Holdings GP, LLC, Alta Mesa Holdings, LP, Alta Mesa Holdings GP, LLC, Silver Run Acquisition Corporation II, and, solely for certain provisions therein, the Contributor Owners party thereto (incorporated by reference from Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the SEC on August 17, 2017 (File No.333-173751)).

3.1	Sixth Amended and Restated Agreement of Limited Partnership of Alta Mesa Holdings, LP, dated as of August 16, 2017 (incorporated by reference from Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the SEC on August 17, 2017 (File No. 333-173751)).

3.2	Fifth Amended and Restated Limited Liability Company Agreement of Alta Mesa Holdings GP, LLC, dated as of August 16, 2017 (incorporated by reference from Exhibit 3.2 to the Company’s Current Report on Form 8-K filed with the SEC on August 17, 2017 (File No. 333-173751)).

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 14, 2017		general partner

	By:	/s/ Harlan H. Chappelle
		Harlan H. Chappelle
		President and Chief Executive Officer
November 14, 2017
	By:	/s/ Michael A. McCabe
		Michael A. McCabe
		Vice President and Chief Financial Officer

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Alta Mesa Inactive 10-Q2017 Q3 Quarterly report

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