10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

_____________________________________

FORM 10-Q

_____________________________________

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

For the quarterly period ended June 30, 2019

OR

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

For the transition period from ___ to___             

Commission file number: 333-173751

_______________________________________

ALTA MESA HOLDINGS, LP

(Exact name of registrant as specified in its charter)

_______________________________________

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

Registrant’s telephone number, including area code: 281-530-0991

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
None	None	None

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  x

(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 every Interactive Data File required to be submitted 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 such files.)    Yes  x    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 the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	¨	Accelerated filer	¨	Non-accelerated filer	¨
Smaller reporting company	¨	Emerging growth company	x

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 x

TABLE OFCONTENTS

	Page Number
Glossary	i
Cautionary Statement Regarding Forward-Looking Statements	1
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements (unaudited)	3
Condensed Consolidated Statements of Operations	3
Condensed Consolidated Balance Sheets	4
Condensed Consolidated Statements of Changes in Partners’ Capital	5
Condensed Consolidated Statements of Cash Flows	6
Notes to Condensed Consolidated Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3. Quantitative and Qualitative Disclosures about Market Risk	35
Item 4. Controls and Procedures	36
PART II - OTHER INFORMATION
Item 1. Legal Proceedings	37
Item 1A. Risk Factors	37
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	37
Item 3. Defaults Upon Senior Securities	37
Item 4. Mine Safety Disclosures	37
Item 5. Other Information	37
Item 6. Exhibits	38
Signatures	39

Glossary of Terms

The definitions and abbreviations set forth below apply to the indicated terms throughout this filing.

Company Specific Terms -
2018 10-K -	Alta Mesa Holdings, LP Annual Report on Form 10-K for the year ended December 31, 2018.
2024 Notes -	$500 million aggregate principal amount of 7.875% senior unsecured notes due December 2024.
Alta Mesa RBL -	Alta Mesa Eighth Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as administrative agent.
AMR -	Alta Mesa Resources, Inc., our parent company.
ARM -	ARM Energy Management, LLC, a company that markets our oil and gas production and provides services relating to our derivatives.
BCE -	BCE-STACK Development LLC, a fund advised by Bayou City Management, LLC.
Business Combination -	The acquisition by Alta Mesa Resources, Inc. of controlling interests in Alta Mesa Holdings GP, LLC, Alta Mesa Holdings, LP, and KFM Midstream, LLC.
High Mesa -	High Mesa Holdings, LP, a partnership formed in connection with executing the Business Combination.
HMI -	High Mesa, Inc., the predecessor owner of Alta Mesa Holdings, LP.
Predecessor Period -	The period from January 1, 2018 through February 8, 2018.
SRII Opco -	SRII Opco, LP is a subsidiary of Alta Mesa Resources, Inc. and direct owner of Alta Mesa Holdings, LP and Kingfisher Midstream, LLC.
Successor Period -	The period from February 9, 2018 through December 31, 2018, and all periods thereafter.
Oil, Gas and Other Terms -
Basin -	A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
bbl -	One stock tank barrel, of 42 U.S. gallons liquid volume, used herein to describe volumes of crude oil, condensate or natural gas liquids.
bbld -	Barrels per day.
Boe -	One barrel of oil equivalent is determined using the ratio of six Mcf of natural gas to one barrel of oil, condensate or natural gas liquids. The ratio of six Mcf of natural gas to one Bbl of oil or natural gas liquids is commonly used in our business and represents the approximate ratio at energy content, and does not represent the price equivalency of natural gas to oil or natural gas liquids.
Boed -	One Boe per day.
Btu or British Thermal Unit -	The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Completion -	The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil.
DD&A -	Depreciation, depletion and amortization.
Development costs -	Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas.
Development project -	A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
Differential -	An adjustment to the market reference price of oil, natural gas or natural gas liquids from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
Dry hole -	A well found to be incapable of producing hydrocarbons in commercial quantities.
EBITDAX -	Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses.

i

Enhanced recovery -	The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are often applied when production slows due to depletion of the natural pressure.
Exploitation -	A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
Formation -	A layer of rock which has distinct characteristics that differs from adjacent rock.
Fracing, fracture stimulation technology, hydraulic fracturing -	A well stimulation technique to improve a well’s production by pumping a mixture of fluids into the formation to create hydraulic fractures which intersect existing natural fractures. As part of this technique, sand or other material may also be injected to keep the hydraulic fracture open, so that fluids or natural gases may more easily flow through the formation.
Held by production -	Acreage covered by mineral leases that perpetuates a company’s right to operate a property usually requiring production to be maintained at a minimum paying quantity of production.
Horizontal drilling -	A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at an angle within a specified interval.
Lease operating expenses -	The expenses of lifting oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a well. Such expenses include labor, supplies, repairs, utilities, environmental and safety, maintenance, allocated overhead costs, severance taxes, insurance and other expenses incidental to production, but excluding lease acquisition, drilling or completion expenses.
Mbbl -	One thousand barrels of crude oil, condensate, natural gas liquids, or produced water.
Mbblsd -	One thousand barrels per day.
MBoe -	One thousand boe.
MBoed -	One thousand boe per day.
Mcf -	One thousand cubic feet of natural gas.
Mcfd -	One thousand cubic feet per day.
MMBtu -	One million British thermal units.
MMBtud -	One million British thermal units per day.
MMcf -	One million cubic feet of natural gas.
MMcfd -	One million cubic feet per day.
Net acres -	The total acres a working interest owner has attributable to a particular number of acres, or a specified tract.
Net production -	Production that is owned by us after royalties and production attributable to other owners.
NGLs or natural gas liquids -	Natural gas liquids are a group of hydrocarbons including ethane, propane, normal butane, isobutane and natural gasoline.
Non-operated working interests -	The working interest or fraction thereof in a lease or unit, the owner of which is without operating rights by reason of an operating agreement.
NYMEX -	The New York Mercantile Exchange.
Prospect -	A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved properties -	Properties with proved reserves.
Proved reserves -	Quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs, and under existing economic conditions, operating methods and government regulations.
Realized price -	The cash market price less all expected quality, transportation and demand adjustments.
Recompletion -	The process of treating an existing wellbore in an attempt to establish or increase existing production.
Reserves -	Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

ii

Resources -	Quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable.
Spacing -	The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.
STACK -	An oilfield in the eastern portion of the Anadarko Basin; 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.
Unproved properties -	Properties with no proved reserves.
Wellbore -	The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.
Working interest -	The right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs.
Workover -	Operations on a producing well to restore or increase production.

iii

Cautionary Statement Regarding Forward-Looking Statements

The information in this Quarterly 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, regarding our ability to continue as a going concern, strategy, future operations, financial position, estimated revenue and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “could”, “should”, “will”, “plan”, “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” in our Annual Report on Form 10-K for the year ended December 31, 2018 (“2018 10-K”). 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 and our parent’s ability to continue as going concerns;

• the sufficiency of liquidity to fund our operations and capital expenditures;

• our access to capital, including constraints from the cost and availability of debt and equity financing;

• our ability to comply with, or amend the terms of, the covenants and restrictions imposed by our debt agreements, including our ability to repay amounts borrowed under the Alta Mesa RBL that exceed the current borrowing base;

• our ability to execute our stated business strategy;

• our reserve quantities and the present value of our reserves;

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

• our exploration and drilling prospects, inventories, projects and programs;

• our drilling, completion and production technology;

• future oil and gas prices;

• the supply and demand for our production;

• the timing and amount of our future production;

• our hedging strategy and expected results;

• competition and government regulation;

• our ability to obtain permits and governmental approvals;

• expected or anticipated regulatory changes, including to the Oklahoma forced pooling system;

• pending legal and environmental matters;

• our future drilling plans, spacing plans and development pace;

• our marketing of our production;

• our leasehold or business acquisitions;

• our costs of developing our properties;

• our ability to hire, train or retain qualified personnel;

• general economic conditions;

• operating hazards and other risks incidental to transporting, storing, gathering and processing natural gas, natural gas liquids and crude oil;

• our future operating results, including production levels, initial production rates and yields in our type curve areas;

• the costs, terms and availability of midstream services;

• our ability to collect receivables from High Mesa, Inc. and its subsidiaries; and

• our plans, objectives, expectations and intentions contained in this Quarterly Report that are not historical.

We caution you that any 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, commodity price volatility, global economic conditions, including supply and demand levels for oil, gas and NGLs, inflation, increased operating costs, lack of availability of drilling and production equipment, supplies, services and qualified personnel, liabilities resulting from litigation or the SEC investigation, difficulties in obtaining necessary approvals and permits, 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 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

1

agreements, the timing of development expenditures, managing our growth and integration of acquisitions, cyber-attacks, failure to realize expected value creation from property acquisitions, title defects, limited control over non-operated properties, and the other risks described in Risk Factors of our 2018 10-K.

Estimating reserve quantities of oil, natural gas and NGLs is complex, inexact and relies on interpretations of geologic, geophysical, engineering and production data. The extent, quality, reliability and interpretation of these data can vary. The process also requires making a number of economic assumptions, such as sales prices, the relative mix of oil, natural gas and NGLs that will be ultimately produced, drilling and operating costs, capital expenditures, the effect of government regulation, taxes and availability of funds.  Future prices received for production and costs may vary, perhaps significantly, from the assumptions used in our estimates.  In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of development and related production. Accordingly, reserve estimates may differ significantly from the quantities of oil and gas that are ultimately recovered.

Should one or more of the risks or uncertainties described in this Quarterly Report or in the 2018 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

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 occurring after the date of this Quarterly Report.

2

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

ALTA MESA HOLDINGS, LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(in thousands)

	Successor												Predecessor
	Three Months Ended June 30, 2019			Three Months Ended June 30, 2018			Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Revenue
Oil	$	90,668		$	75,291		$	177,031		$	115,569		$	30,972
Natural gas	12,384			7,980			30,834			13,190			4,276
Natural gas liquids	10,251			10,241			21,467			14,955			4,000
Other	330			2,229			898			2,784			888
Operating revenue	113,633			95,741			230,230			146,498			40,136
Gain (loss) on sale of assets	—			(63		)	1,483			5,076			840
Gain (loss) on derivatives	12,412			(29,219		)	(11,365		)	(51,230		)	6,663
Total revenue	126,045			66,459			220,348			100,344			47,639
Operating expenses
Lease operating	19,123			12,679			44,231			20,996			4,408
Transportation and marketing	19,614			11,206			37,375			16,788			3,725
Production taxes	5,117			2,606			10,600			4,021			953
Workovers	412			333			609			1,578			423
Exploration	3,289			8,083			5,343			9,668			7,003
Depreciation, depletion and amortization	34,504			26,670			69,179			37,708			11,670
Impairment of assets	6,500			—			6,500			—			—
General and administrative	15,723			17,811			36,670			52,465			21,234
Total operating expenses	104,282			79,388			210,507			143,224			49,416
Operating income	21,763			(12,929		)	9,841			(42,880		)	(1,777		)
Other income (expense)
Interest expense	(14,071		)	(10,361		)	(26,901		)	(15,557		)	(5,511		)
Interest income and other	54			820			81			1,366			172
Total other expense, net	(14,017		)	(9,541		)	(26,820		)	(14,191		)	(5,339		)
Income (loss) from continuing operations before income taxes	7,746			(22,470		)	(16,979		)	(57,071		)	(7,116		)
Income tax provision (benefit)	—			7			—			7			—
Income (loss) from continuing operations	7,746			(22,477		)	(16,979		)	(57,078		)	(7,116		)
Loss from discontinued operations, net of tax	—			—			—			—			(7,746		)
Net income (loss)	$	7,746		$	(22,477	)	$	(16,979	)	$	(57,078	)	$	(14,862	)

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

3

ALTA MESA HOLDINGS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands)

໿

	June 30, 2019		December 31, 2018
ASSETS
Current assets
Cash and cash equivalents	$	78,275	$	12,984
Restricted cash	890		1,001
Accounts receivable, net	61,662		68,370
Other receivables	3,530		6,267
Related party receivables, net	13,149		24,282
Notes receivable from related parties, net	—		—
Prepaid expenses and other current assets	4,623		747
Derivatives	4,727		16,423
Total current assets	166,856		130,074
Property and equipment, net
Oil and gas properties, successful efforts method	784,079		763,337
Other property and equipment	37,371		38,147
Total property and equipment	821,450		801,484
Other assets
Operating lease right-of-use assets, net	7,871		—
Deferred financing costs, net	1,021		1,151
Deposits and other long-term assets	38		63
Derivatives	2,508		2,947
Total other assets	11,438		4,161
Total assets	$	999,744	$	935,719

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

	June 30, 2019		December 31, 2018
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Current portion of debt	$	871,162	$	—
Accounts payable and accrued liabilities	91,694		197,064
Accounts payable - related party	222		3,425
Advances from non-operators	1,755		5,193
Advances from related party	4,003		9,822
Asset retirement obligations	44		2,079
Current operating lease liability	938		—
Derivatives	840		1,710
Total current liabilities	970,658		219,293
Long-term liabilities
Asset retirement obligations, net of current portion	12,293		9,330
Long-term debt, net	—		690,123
Operating lease liabilities, net of current portion	13,733		—
Derivatives	189		180
Total long-term liabilities	26,215		699,633
Total liabilities	996,873		918,926
Commitments and contingencies
Partners’ capital	2,871		16,793
Total liabilities and partners’ capital	$	999,744	$	935,719

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

4

ALTA MESA HOLDINGS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL (Unaudited)

(in thousands)

໿

	Predecessor
Balance, December 31, 2017	$	154,445
Distribution of non-STACK oil and gas assets, net of associated liabilities	43,482
Net loss	(14,862		)
Balance, February 8, 2018	$	183,065
	Successor
Balance, February 9, 2018	$	1,535,891
Contributions	560,344
Equity-based compensation expense	2,768
Net loss	(34,601		)
Balance, March 31, 2018	2,064,402
Issuance of additional purchase consideration	9,467
Equity-based compensation expense	3,621
Distributions	(7,000		)
Net loss	(22,477		)
Balance, June 30, 2018	$	2,048,013
Balance, December 31, 2018	$	16,793
Equity-based compensation expense	1,661
Net loss	(24,725		)
Balance, March 31, 2019	(6,271		)
Equity-based compensation expense	1,396
Net income	7,746
Balance, June 30, 2019	$	2,871

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

5

ALTA MESA HOLDINGS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(in thousands)

	Successor						Predecessor
	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Cash flows from operating activities:
Net loss	$	(16,979	)	$	(57,078	)	$	(14,862	)
Adjustments to reconcile net loss to cash from operating activities:
Depreciation, depletion, amortization and accretion	69,179			37,708			12,554
Non-cash lease expense	1,587			—			—
Provision for uncollectible receivables	1,177			—			—
Impairment of assets	6,500			—			5,560
Amortization of deferred financing costs	139			80			171
Amortization of debt (premium) discount	(2,462		)	(2,051		)	—
Equity-based compensation expense	3,057			6,389			—
Non-cash exploration expense	388			10,658			4,575
(Gain) loss on derivatives	11,365			51,230			(6,663		)
Cash settlements of derivatives	909			(18,334		)	(2,296		)
Premium paid on derivatives	(1,000		)	—			—
Interest converted into debt	—			—			103
Interest added to notes receivable from affiliate	—			(417		)	(85		)
Loss on sale of fixed assets	—			63			1,923
Impact on cash from changes in:
Accounts receivable	6,384			(2,923		)	(21,184		)
Other receivables	2,737			1,426			(662		)
Receivables from related parties	10,280			(18,494		)	(117		)
Prepaid expenses and other non-current assets	(3,853		)	7,810			(591		)
Advances from related party	(5,819		)	(10,371		)	24,116
Settlement of asset retirement obligations	—			(806		)	(63		)
Accounts payable to related party	(3,203		)	(4,994		)	—
Accounts payable, accrued liabilities and other liabilities	(17,281		)	(45,385		)	23,857
Operating lease obligations	(1,287		)	—			—
Cash from operating activities	61,818			(45,489		)	26,336
Cash flows from investing activities:
Capital expenditures	(180,138		)	(319,042		)	(36,695		)
Acquisitions, net of cash acquired	—			—			(1,218		)
Proceeds from sale of assets	—			11,299			—
Cash from investing activities	(180,138		)	(307,743		)	(37,913		)
Cash flows from financing activities:
Proceeds from long-term debt borrowings	183,500			—			60,000
Repayments of long-term debt	—			(134,065		)	(43,000		)
Deferred financing costs paid	—			(1,366		)	—
Capital distributions	—			(7,000		)	(68		)
Capital contributions	—			560,344			—
Cash from financing activities	183,500			417,913			16,932
Net increase in cash, cash equivalents and restricted cash	65,180			64,681			5,355
Cash, cash equivalents and restricted cash, beginning of period	13,985			10,345			4,990
Cash, cash equivalents and restricted cash, end of period	$	79,165		$	75,026		$	10,345

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

6

ALTA MESA HOLDINGS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 — DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

Alta Mesa Holdings, LP (“Alta Mesa” or “the Company”) is an exploration and production company focused on the acquisition, development, exploration and exploitation of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma commonly referred to as the STACK. Our operations prior to February 9, 2018, also included other oil and natural gas interests in Texas, Idaho, Louisiana and Florida. In connection with our acquisition by Alta Mesa Resources, Inc. (“AMR”), on February 9, 2018 (“the Business Combination”), we distributed the non-STACK oil and gas assets and liabilities to our prior owner, High Mesa Holdings, LP (“High Mesa”), and completed our transition from a diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource unconventional play in the STACK.  Prior to the closing of the Business Combination, we were controlled by High Mesa Inc. (“HMI”). The 2018 10-K contains substantially more information about our operations and the Business Combination.

All intercompany transactions and accounts have been eliminated. These interim condensed consolidated financial statements are unaudited, but we believe these statements reflect all adjustments necessary for a fair presentation for the periods reported. All such adjustments are of a normal, recurring nature unless otherwise disclosed. These financial statements and disclosures have been prepared in accordance with the SEC’s rules for interim financial statements and do not include all the information and disclosures required by generally accepted accounting principles (“GAAP”). These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our 2018 10-K. The results for the three and six months ended June 30, 2019, are not necessarily indicative of the results to be expected for the full year. We have no items of other comprehensive income during any period presented. 

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Going Concern

We are required to evaluate our ability to continue as a going concern for a period of one year following the date of issuance of our financial statements. As part of that evaluation, we took into consideration the following factors:

• Market prices for crude oil have declined since the Business Combination. This negatively impacted our future operating cash flow and lowers our expected future economic results from our assets compared with the time of the Business Combination.

• Our 2018 drilling program, much of which involved the drilling of additional wells in close proximity to existing wells, did not meet our expectations for production and recovery and reduces the number of wells we expect to develop in the future compared with the time of the Business Combination. We also experienced an increasing gas-to-oil ratio as a well’s production ages, which has contributed to a lowering of the expected economics of our properties.

• Although our well costs for our 2019 capital program have averaged less than $3.0 million per well, we still expect our operating cash flow to be less than our 2019 capital spending. Future well costs are expected to increase as we move into higher cost areas of our acreage which have less infrastructure in place and that may require more intense completions.

• On April 1, 2019, our borrowing base under the Alta Mesa RBL was reduced to $370.0 million and we had no meaningful remaining capacity available thereunder at June 30, 2019. Without additional capital, we will only be able to utilize the cash on hand, which at July 31, 2019 was $79.7 million, to fund development and meet our financial obligations. We may be unable to obtain covenant relief or to replace the Alta Mesa RBL with debt that would allow us to meet any attendant covenant requirements. Also, the lack of sufficient capital may prevent us from maintaining our current levels of production, which could negatively impact our ability over time to service our debt and meet our other obligations. In August 2019, the lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reset to $200 million, effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceed the new borrowing base amount by $162.4 million, we have five months to make ratable payments of $32.5 million to cause utilization to be less than or equal to the borrowing base. The first payment is due in September 2019. If we are unable to make this repayment, we will be in default under the Alta Mesa RBL. There is

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a risk that future redeterminations could reduce the borrowing base further. Our decreased borrowing base could cause us to reduce or abandon our development activities.

• We do not anticipate meeting our existing leverage covenants through June 2020 without relief from our lenders and currently expect not to be able to satisfy the consolidated total leverage ratio covenant in the Alta Mesa RBL as early as the measurement date of September 30, 2019.

• We have $500.0 million of unsecured debt in the form of our 2024 Notes, with an interest payment of approximately $20.0 million due in December 2019, which could become an event of default if unpaid before January 14, 2020. The 2024 Notes trade substantially below par value.

• The Class A common stock of our parent company, AMR, has been trading below $1.00 per share since February 22, 2019. On April 3, 2019, AMR was notified by NASDAQ that it was not in compliance with the minimum bid price requirement. Continued trading at these levels may limit its and our ability to raise additional capital in the equity markets.

• Our ability to collect receivables due from High Mesa and its affiliates

The above factors raise substantial doubt about our and our parent’s ability to continue as a going concern. To address this, we have:

• retained financial advisors to assist in evaluating financial alternatives;

• engaged in discussions with the advisors for the Alta Mesa RBL lenders about obtaining covenant relief to address the future expected inability to satisfy the leverage requirement. To date we have been unable to reach an accord on any such relief and do not expect that the lenders would grant any extended period of covenant relief;

• considered seeking new sources of financing, however, such efforts do not appear to present a substantive solution; and

• engaged in discussions with and provided requested information to financial and legal advisors for a group of holders of Alta Mesa’s 2024 Notes, but we cannot predict what will result from the discussions or whether they will yield a constructive deal.

Regardless of whether we are able to reach an agreement with our creditors, it may be necessary for us to file a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code. In light of these factors, we believe substantial unresolved doubt exists regarding our ability to continue as a going concern for the 12 months following the issuance of these financial statements. Based on the foregoing, we believe that it is probable that our indebtedness will accelerate before July 2020 and, therefore, have reported all of our debt as current.

Recently Issued Accounting Standards Applicable to Us

Adopted

Effective January 1, 2019, we adopted ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which requires that lessees recognize a lease liability, which is a lessee’s discounted obligation to make payments under a lease and a right-of-use asset, arising from a lessee’s right to use an asset over the lease term. Upon adoption, we used the modified retrospective method to apply the standard as of January 1, 2019 for existing leases with terms in excess of 12 months entered into prior to January 1, 2019.

Not Yet Adopted

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses(Topic 326): Measurement of Credit Losses on Financial Instruments. This standard requires the use of a new “expected credit loss” impairment model rather than the “incurred loss” model we use today. With respect to our trade and notes receivables and certain other financial instruments, we may be required to (i) maintain and use lifetime loss information rather than annual loss data and (ii) forecast future economic conditions and quantify the effect of those conditions on future expected losses. The standard, including related amendments, which will be effective for us on January 1, 2020, also requires additional disclosures regarding the credit quality of our trade and notes receivables and other financial instruments. No determination has yet been made of the impact of this new standard on our financial position or results of operations.

In August 2018, the FASB issued ASU No. 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Topic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). The amendments in this standard align the requirements for capitalizing implementation costs incurred in a

8

hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal use software (and hosting arrangements that include an internal-use software license). Under this new standard, a customer in a hosting arrangement that is a service contract is required to follow the guidance in Subtopic 350-40 to determine which implementation costs to capitalize as a prepaid asset related to the service contract and which costs to expense. The capitalized implementation costs are to be expensed over the term of the hosting arrangement and reflected in the same line in the consolidated statement of operations as the fees associated with the hosting element of the arrangement. Similarly, capitalized implementation costs are to be presented in the statement of cash flows in the same line as payments made for fees associated with the hosting element. We will adopt this new standard no later than January 1, 2020, although early adoption is permitted. We are currently evaluating the impact of this new standard on our consolidated financial position and results of operations and have not yet determined when to adopt and whether to apply the new standard retrospectively or prospectively to implementation costs incurred after the date of adoption.

In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820) Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which modifies the disclosure requirements of fair value measurements. ASU 2018-13 is effective for us beginning January 1, 2020. Certain disclosures are required to be applied on a retrospective basis and others on a prospective basis. We do not expect the adoption of this standard to impact our financial position or results of operations.

NOTE 3 — ADOPTION OF ASU NO. 2016-02, LEASES

ASU No. 2016-02 requires us to recognize a right-of-use (“ROU”) asset and a discounted lease liability on the balance sheet for all leases with a term longer than one year. We adopted ASU No. 2016-02 and related guidance using the modified retrospective method to apply the standard as January 1, 2019, and this adoption had no effect on the earlier comparative periods presented. At adoption, we recognized operating lease ROU assets and operating lease liabilities of $15.0 million. There was no adjustment to beginning of period equity.

We lease office space, office equipment and field equipment, including compressors. Many of our leases include both lease and non-lease components which are primarily management services performed by the lessors for the underlying assets. All of our leases of office space and office equipment were classified as operating leases upon adoption. Our leases of field equipment had remaining terms of less than one year at the date of adoption and were not recognized as operating leases on our balance sheet due to our election of the short term lease practical expedient described below. Our leases do not contain any residual value guarantees or restrictive covenants. We do not sublease any of our ROU assets, although we aspire to sublease our unused office lease space.

Operating fixed lease expenses are recognized on a straight-line basis over the lease term. Variable lease payments, which cannot be determined at the lease commencement date, are not included in ROU assets or lease liabilities and are expensed as incurred.

Upon adoption, we selected the following practical expedients:

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Practical expedient package	We did not reassess whether any expired or existing contracts are, or contain, leases.
	We did not reassess the lease classification of any expired or existing leases.
	We did not reassess initial direct costs of any expired or existing leases.
Hindsight practical expedient	We did not elect to use the hindsight practical expedient which allows for the use of hindsight when determining lease term, including option periods, and impairment of operating assets.
Easement expedient	We elected to maintain the current accounting treatment of existing contracts and not reassess whether those contracts met the definition of a lease.
Combining lease and non-lease components expedient	We elected to account for lease and non-lease components as a single component.
Short-term lease expedient	We elected the short-term lease recognition exemption for all classes of underlying assets. Expense for short-term leases is recognized on a straight-line basis over the lease term. Leases with an initial term of 12 months or less and that do not include an option to purchase the underlying asset that is reasonably certain to be recognized are not recorded on the balance sheet.

As most leases do not have readily determinable implicit rates, we estimated the incremental borrowing rates for our future lease payments based on prevailing financial market conditions at the later of date of adoption or lease commencement, comparable companies and credit analysis and management judgments to determine the present values of our lease payments. We also apply the portfolio approach to account for leases with similar terms. At June 30, 2019, for our operating leases the weighted-average remaining lease terms were approximately 8.1 years and our weighted-average discount rates were 14.1%.

Lease Costs

(in thousands)	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Operating lease cost	$	776	$	1,587
Variable lease cost	473		796
Short-term lease cost	1,075		3,261
Total lease cost	$	2,324	$	5,644
Reported as:
Lease operating expense	$	1,031	$	3,326
General and administrative expense	1,293		2,318
Total lease cost	$	2,324	$	5,644

Operating Lease Liability Maturities as of June 30, 2019

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Fiscal year	(in thousands)
Remainder of 2019	$	1,470
2020	2,965
2021	2,942
2022	3,010
2023	2,718
Thereafter	12,647
Total lease payments	25,752
Less: imputed interest	(11,081		)
Present value of operating lease liabilities	$	14,671
Current portion of operating lease liabilities	$	938
Operating lease liabilities, net of current portion	13,733
Present value of operating lease liabilities	$	14,671

Operating Lease Payment Obligations as of December 31, 2018

As described further in our 2018 10-K, our minimum future contractual lease payments under ASC 840 at December 31, 2018 were $2.8 million for 2019, $2.9 million for 2020, $2.9 million for 2021, $3.1 million for 2022, $3.0 million for 2023 and $12.2 million thereafter.

Right-of-Use Asset Impairment

During the second quarter of 2019, we consolidated employees in existing leased office space in Houston, Texas and Oklahoma City, Oklahoma. We are seeking to sublease the unused office space within three buildings. We do not anticipate that we will be able to fully recover the cash due to the lessor under the existing operating lease obligations in those three buildings with proceeds from subleases. As a result, we recognized a $6.5 million impairment of our existing right-of-use lease assets in those buildings during the three months ended June 30, 2019. This impairment had no impact to our lease liability.

NOTE 4 — SUPPLEMENTAL CASH FLOW INFORMATION

	Successor						Predecessor
(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Supplemental cash flow information:
Cash paid for interest	$	25,070		$	21,216		$	1,145
Cash paid for state income taxes, net of refunds	—			6			—
Non-cash investing and financing activities:
Increase in asset retirement obligations	634			877			—
Increase (decrease) in accruals or payables for capital expenditures	(91,639		)	(27,646		)	4,896
Distribution of non-STACK assets, net of liabilities	—			—			43,482

We aggregate cash, cash equivalents and restricted cash in the statements of cash flows.  

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NOTE 5 — RECEIVABLES

Accounts Receivable

(in thousands)	June 30, 2019			December 31, 2018
Production sales	$	29,730		$	31,532
Joint interest billings	20,836			18,147
Pooling interest (1)	11,506			18,786
Allowance for doubtful accounts	(410		)	(95		)
Total accounts receivable, net	$	61,662		$	68,370

_________________

(1) Pooling interest relates to Oklahoma’s forced pooling process which permits mineral interest owners the option to participate in the drilling of proposed wells.  The pooling interest listed above represents unbilled costs for wells where the option remains pending.  Depending upon the mineral owner’s decision, these costs will be billed to them or added to oil and gas properties.

Related Party Receivables

(in thousands)	June 30, 2019			December 31, 2018
Related party receivables	$	23,037		$	33,316
Allowance for doubtful accounts	(9,888		)	(9,034		)
Related party receivables, net	13,149			24,282
Notes receivable from related parties	13,403			13,403
Allowance for doubtful accounts	(13,403		)	(13,403		)
Notes receivable from related parties, net	—			—
Total related party receivables, net	$	13,149		$	24,282

KFM Receivables

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We have entered into contracts with KFM whereby they provide midstream services, including produced water disposal, to us. During the six months ended June 30, 2019, the period February 9, 2018 through June 30, 2018, and the Predecessor Period, we incurred $30.8 million, $13.6 million, and $3.1 million, respectively, in midstream services, which we have recognized in transportation and marketing expense. Additionally, we had related party receivables from KFM which include its portion of allocated G&A, other expenditures attributable to KFM and proceeds due to us for KFM’s sale of our natural gas and NGLs reduced by the fees from midstream services that KFM provided to us totaling $4.6 million and $11.2 million at June 30, 2019 and December 31, 2018, respectively.

In addition, we sold a produced water disposal system to KFM during the fourth quarter of 2018. As of December 31, 2018, related party receivables of $8.7 million were attributable to a purchase price adjustment due from KFM. We collected this receivable during June 2019.

AMR Receivables

We incur general and administrative costs that may be partially or fully allocable to AMR. These costs are either allocated monthly or charged directly to AMR but are cash settled in arrears. As of June 30, 2019 and December 31, 2018, respectively, we have receivables from AMR for such costs totaling $8.5 million and $3.3 million, respectively.

Management Services Agreement with High Mesa

(in thousands)	June 30, 2019
High Mesa related party receivable at December 31, 2018	$	10,066
Additions	894
Payments	(1,072		)
High Mesa related party receivable at June 30, 2019	9,888
Allowance for uncollectibility(1)	(9,888		)
Balance at June 30, 2019, net	$	—

_________________

(1) $9.0 million of the allowance was recognized during the 2018 Successor Period.

Just prior to the Business Combination, we distributed the non-STACK oil and gas assets to High Mesa. High Mesa and certain of its subsidiaries agreed to indemnify and hold us harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. We also entered into a management services agreement (the “High Mesa Agreement”) with HMI with respect to the non-STACK assets. Under the High Mesa Agreement, during the 180-day period following the Closing, we agreed to provide certain administrative, management and operational services necessary to manage the business of HMI and its subsidiaries (the “Services”). Thereafter, the High Mesa Agreement automatically renewed for additional consecutive 180-day periods, unless terminated by either party upon at least 90-days written notice prior to renewal. HMI agreed to pay us each month (i) a management fee of $10,000 and (ii) an amount equal to any and all costs and expenses incurred in connection with providing the Services.

Although the automatic renewal of this agreement occurred in the third quarter of 2018, the parties subsequently agreed to terminate the High Mesa Agreement, effective January 31, 2019. Through April 1, 2019, we were obligated to take all actions that HMI reasonably requested to effect the transition of the Services to a successor service provider. During the transition period, HMI agreed to pay us (i) for all Services performed, (ii) an amount equal to our costs and expenses incurred in connection with providing the Services as provided for in the approved budget and (iii) an amount equal to our costs and expenses reimbursable pursuant to the High Mesa Agreement. As of June 30, 2019, and December 31, 2018, approximately $9.9 million and $10.1 million, respectively, were due from HMI for reimbursement of costs and expenses which are recorded as “Related party receivables, net” in the balance sheets. HMI has disputed certain of the amounts we billed. We are pursuing remedies under applicable law in connection with repayment of this receivable. There is no guarantee that HMI will pay the amounts it owes. In addition, our ability to collect these amounts or future amounts that may become due pursuant to indemnification obligations may be adversely impacted by liquidity and solvency issues at HMI. As a result of these circumstances, we have recognized an allowance for uncollectible accounts of $9.9 million and $9.0 million as of June 30, 2019 and December 31, 2018, respectively, to fully provide for the unremitted balances. We may also be subject to future contingent liabilities for the non-STACK assets for which we should have been indemnified, including liabilities associated with litigation

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relating to the non-STACK assets. As of June 30, 2019 and December 31, 2018, we have established no liabilities for contingent obligations associated with non-STACK assets owned by High Mesa.

Promissory notes receivable

In September, 2017, we entered into a $1.5 million promissory note receivable with our affiliate, Northwest Gas Processing, LLC, whose obligation was subsequently transferred to High Mesa Services, LLC (“HMS”), a subsidiary of HMI.  The promissory note bore interest, which could be paid-in-kind and added to the principal amount at a rate of 8% per annum. HMS defaulted under the terms of that promissory note when it was not paid at maturity on February 28, 2019, and HMS has failed to cure such default. We subsequently declared all amounts owed under the note immediately due and payable and we have fully reserved the promissory note balance, including interest paid-in-kind, totaling $1.7 million as of June 30, 2019 and December 31, 2018.

In addition, we have an $8.5 million note receivable from HMS which matures on December 31, 2019, and bears interest at 8% per annum, which may be paid-in-kind and added to the principal amount.  HMI disputes its obligations under the $8.5 million note. As of June 30, 2019, and December 31, 2018, the note receivable balance, including interest paid-in-kind, amounted to $11.7 million, for each respective period. This balance was fully reserved at the end of both periods.

We oppose HMI’s claims and believe HMI’s obligations under the notes to be valid assets and that the full amount is payable to us. We are pursuing remedies under applicable law in connection with repayment of the promissory notes. As a result of the potential conflict of interest from certain of AMR’s directors who are also controlling holders of HMI, AMR’s disinterested directors will address any potential conflicts of interest with respect to this matter.

NOTE 6 — PROPERTY AND EQUIPMENT

(in thousands)	June 30, 2019			December 31, 2018
Oil and gas properties
Unproved properties	$	76,665		$	74,217
Proved oil and gas properties	2,196,605			2,110,346
Accumulated depletion and impairment	(1,489,191		)	(1,421,226		)
Proved oil and gas properties, net	707,414			689,120
Total oil and gas properties, net	784,079			763,337
Other property and equipment
Land	5,059			5,059
Fresh water wells	27,372			27,366
Produced water disposal system	3,590			3,608
Office furniture, equipment and vehicles	2,825			2,840
Accumulated depreciation	(1,475		)	(726		)
Other property and equipment, net	37,371			38,147
Total property and equipment, net	$	821,450		$	801,484

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Depletion and Depreciation Expense

	Successor								Predecessor
(in thousands)	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
Oil and gas properties depletion	$	33,923	$	26,086	$	67,965	$	36,859	$	11,021
Other property and equipment depreciation	341		423		749		586		609
Total depletion and depreciation	$	34,264	$	26,509	$	68,714	$	37,445	$	11,630

Impairment

During the three months ended June 30, 2019, we evaluated the qualitative market conditions and other factors impacting our business and concluded that there were no indicators of impairment impacting our property and equipment. Therefore, we did not conduct further analysis on the recognition of additional impairment.

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NOTE 7 — DISCONTINUED OPERATIONS (Predecessor)

Alta Mesa distributed the non-STACK oil and gas assets and related liabilities to High Mesa immediately prior to the Business Combination. This distribution, including the results of operations of these assets and liabilities, is presented as discontinued operations during the Predecessor Period.

	Predecessor
(in thousands)	January 1, 2018 Through February 8, 2018
Revenue
Oil	$	1,617
Natural gas	1,023
Natural gas liquids	236
Other	16
Operating revenue	2,892
Loss on sale of assets	(1,923		)
Total revenue	969
Operating expenses
Lease operating	1,770
Transportation and marketing	83
Production taxes	167
Workovers	127
Depreciation, depletion and amortization	884
Impairment of assets	5,560
General and administrative	21
Total operating expenses	8,612
Other expense
Interest expense	(103		)
Loss from discontinued operations, net of tax	$	(7,746	)

	Predecessor
(in thousands)	January 1, 2018 Through February 8, 2018
Total operating cash flows of discontinued operations	$	2,974
Total investing cash flows of discontinued operations	(601		)

NOTE 8 — DERIVATIVES

All of our derivatives have the lenders under the Alta Mesa RBL as counterparty, and are collateralized by the security interests thereunder. We periodically monitor the creditworthiness of our counterparties. Although our counterparties provide no collateral, the agreements with each counterparty allow us to set-off unpaid amounts against the outstanding balance under the Alta Mesa RBL. The derivatives settle monthly. No derivatives have been entered into for trading or speculative purposes and none have been designated as hedges under GAAP.

The following summarizes the fair value and classification of our derivatives:

	June 30, 2019
Balance sheet location	Gross fair value of assets		Gross liabilities offset against assets in the Balance Sheet			Net fair value of assets presented in the Balance Sheet
	(in thousands)
Derivatives, current assets	$	13,855	$	(9,128	)	$	4,727
Derivatives, long-term assets	11,977		(9,469		)	2,508
Total	$	25,832	$	(18,597	)	$	7,235

Balance sheet location	Gross fair value of liabilities		Gross assets offset against liabilities in the Balance Sheet			Net fair value of liabilities presented in the Balance Sheet
	(in thousands)
Derivatives, current liabilities	$	9,968	$	(9,128	)	$	840
Derivatives, long-term liabilities	9,658		(9,469		)	189
Total	$	19,626	$	(18,597	)	$	1,029

	December 31, 2018
Balance sheet location	Gross fair value of assets		Gross liabilities offset against assets in the Balance Sheet			Net fair value of assets presented in the Balance Sheet
	(in thousands)
Derivatives, current assets	$	22,512	$	(6,089	)	$	16,423
Derivatives, long-term assets	7,910		(4,963		)	2,947
Total	$	30,422	$	(11,052	)	$	19,370

Balance sheet location	Gross fair value of liabilities		Gross assets offset against liabilities in the Balance Sheet			Net fair value of liabilities presented in the Balance Sheet
	(in thousands)
Derivatives, current liabilities	$	7,799	$	(6,089	)	$	1,710
Derivatives, long-term liabilities	5,143		(4,963		)	180
Total	$	12,942	$	(11,052	)	$	1,890

The following table summarizes the effect of our derivatives in the consolidated statements of operations (in thousands):

	Successor											Predecessor
Derivatives not designated as hedges	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018			Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Gain (loss) on derivatives -
Oil	$	5,134	$	(28,712	)	$	(16,535	)	$	(50,656	)	$	4,796
Natural gas	7,278		(507		)	5,170			(574		)	1,867
Total gain (loss) on derivatives	$	12,412	$	(29,219	)	$	(11,365	)	$	(51,230	)	$	6,663

Other receivables at June 30, 2019 and December 31, 2018 include $1.4 million and $1.3 million, respectively, of derivative positions scheduled to be settled in the ensuing month.

We had the following call and put derivatives at June 30, 2019:

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OIL

	Remaining Volume	Weighted		Range
Settlement Period and Type of Contract	in bbls	Average		High		Low
2019
Price Swap Contracts	92,000	$	63.03	$	63.03	$	63.03
Collar Contracts
Short Call Options	1,361,600	66.31		75.20		56.50
Long Put Options	1,453,600	53.80		62.00		50.00
Short Put Options	1,453,600	42.72		52.00		37.50
2020
Collar Contracts
Short Call Options	1,017,600	63.95		73.80		59.55
Long Put Options	1,566,600	56.81		62.50		50.00
Short Put Options	1,566,600	42.81		50.00		37.50
2021
Collar Contracts
Short Call Options	279,750	63.51		63.75		63.35
Long Put Options	659,850	46.94		55.00		41.00
Short Put Options	279,750	43.00		43.00		43.00

NATURAL GAS

	Remaining Volume	Weighted			Range
Settlement Period and Type of Contract	in MMBtu	Average			High			Low
2019
Price Swap Contracts	7,980,000	$	2.67		$	2.72		$	2.64
Basis Swap Contracts	9,680,000	(0.72		)	(0.49		)	(0.93		)
Collar Contracts
Short Call Options	1,525,000	3.19			3.20			3.17
Long Put Options	1,525,000	2.70			2.70			2.70
Short Put Options	1,525,000	2.20			2.20			2.20
2020
Price Swap Contracts	1,284,000	2.54			2.54			2.54
Basis Swap Contracts	910,000	(0.49		)	(0.49		)	(0.50		)
Collar Contracts
Short Call Options	3,874,500	3.19			3.69			2.77
Long Put Options	10,749,500	2.59			3.00			2.50
Short Put Options	9,696,000	2.10			2.50			2.00
2021
Collar Contracts
Short Call Options	540,000	3.25			3.25			3.25
Long Put Options	2,790,000	2.62			2.65			2.50
Short Put Options	2,250,000	2.15			2.15			2.15

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We had the following basis swaps at June 30, 2019:

Total Gas Volumes in MMBtu(1) over Remaining Term	Reference Price 1 (1)	Reference Price 2 (1)	Period			Weighted Average Spread ($ per MMBtu)
460,000	OneOK	NYMEX Henry Hub	Jul '19	—	Dec '19	$	(0.93	)
7,990,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Jul '19	—	Dec '19	(0.70		)
910,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Jan '20	—	Mar '20	(0.49		)
1,230,000	San Juan	NYMEX Henry Hub	Jul '19	—	Oct '19	(0.81		)

________________

(1) Represents short swaps that fix the basis differentials between OneOK, Tex/OKL Panhandle Eastern Pipeline (“PEPL”), San Juan and NYMEX Henry Hub.

NOTE 9 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES 

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(in thousands)	June 30, 2019		December 31, 2018
Accounts payable	$	8,871	$	20,200
Accruals for capital expenditures	18,477		101,214
Revenue and royalties payable	39,232		46,870
Accruals for operating expenses	10,701		16,355
Accrued interest	5,642		1,784
Derivative settlements	743		109
Other	8,028		10,532
Total accrued liabilities	82,823		176,864
Accounts payable and accrued liabilities	$	91,694	$	197,064

NOTE 10 — ASSET RETIREMENT OBLIGATIONS 

	Successor						Predecessor
(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Balance, beginning of period	$	11,409		$	—		$	10,469
Liabilities assumed in Business Combination	—			5,998			—
Liabilities incurred	634			877			—
Liabilities settled	(162		)	(806		)	(63		)
Liabilities transferred in sale of properties	—			(20		)	—
Revisions to estimates	(9		)	665			63
Accretion expense	465			263			40
Balance, end of period	12,337			6,977			10,509
Less: Current portion	44			538			33
Long-term portion	$	12,293		$	6,439		$	10,476

NOTE 11 — DEBT

໿

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(in thousands)	June 30, 2019		December 31, 2018
Alta Mesa RBL	$	344,500	$	161,000
2024 Notes	500,000		500,000
Unamortized premium on 2024 Notes	26,662		29,123
Total debt, net	871,162		690,123
Less: Current portion	871,162		—
Long-term debt, net	$	—	$	690,123

Alta Mesa RBL

The Alta Mesa RBL has two covenants that are tested quarterly:

• a ratio of our current assets to current liabilities, inclusive of specified adjustments, of not less than 1.0 to 1.0; and

• a ratio of our consolidated debt to our consolidated Adjusted EBITDAX (the “leverage ratio”) of not greater than 4.0 to 1.0. For the first 3 measurement periods following the Business Combination we were able to annualize cumulative Successor Period results in measuring Adjusted EBITDAX. 

Before July 2020, and possibly as soon as September 30, 2019, we do not expect to satisfy the leverage ratio. We recognize the need to obtain covenant relief or to replace the Alta Mesa RBL with debt that would allow us to meet any attendant covenant requirements.

At June 30, 2019, inclusive of $20.2 million of outstanding letters of credit, we had $5.3 million of stated borrowing capacity remaining under the Alta Mesa RBL, dependent upon the lenders’ willingness to provide such funds.

In August 2019, the lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reset to $200 million, effective August 13, 2019. Our discussion about our ability to continue as a going concern provides information about the borrowing base and deficiency payments arising from the redetermination.

2024 Notes

In connection with the Business Combination, we recorded the fair value of our $500.0 million unsecured senior notes at $533.6 million as of the acquisition date. We have estimated the fair value of our senior notes to be $193.8 million at June 30, 2019.  This estimation was based on the most recent trading values of the senior notes at or near the reporting date, which is a Level 1 determination.

Scheduled Maturities of Debt

Fiscal year	(in thousands)
2019	$	—
2020	—
2021	—
2022	—
2023	344,500
Thereafter	500,000
	$	844,500

Based upon the factors leading to the substantial unresolved doubt about our ability to continue as a going concern, we believe that it is probable that our indebtedness will accelerate prior to July 1, 2020, and earlier than the scheduled maturities shown above. We have reported all of our debt as current at June 30, 2019.

NOTE 12 — COMMITMENTS AND CONTINGENCIES 

There have been no material changes during the first six months of 2019 in our commitments and contingencies as compared to our discussion of those matters in our 2018 10-K.

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NOTE 13 — SIGNIFICANT CONCENTRATIONS 

During a portion of 2019 and throughout 2018, ARM Energy Management, LLC ("ARM") marketed our oil, gas and NGLs for a marketing fee that is deducted from sales proceeds collected by ARM from purchasers. The sales are generally made under short-term contracts with month-to-month pricing based on published regional indices, adjusted for transportation, location and quality.  In March 2019, in preparation for handling oil and NGL marketing responsibilities internally, we began receiving payments for the sale of oil and NGLs directly from purchasers and separately paying the marketing fee owed to ARM.  As of June 1, 2019, we terminated our oil and NGL marketing agreement with ARM and have begun marketing such products internally. We have extended the term of our gas marketing agreement with ARM through November 30, 2019.

Our affiliate, Kingfisher Midstream, LLC (“KFM”) is responsible for marketing our firm transportation on the ONEOK Gas Transmission, L.L.C. system, which is indirectly marketed by ARM through an asset management agreement.

ARM also provides us with strategic advice, execution and reporting services with respect to our derivatives activities.

	Successor								Predecessor
(in thousands)	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
Revenue marketed by ARM on our behalf	$	7,703	$	70,601	$	91,534	$	107,944	$	28,757
Marketing and management fees paid to ARM	$	476	$	—	$	1,137	$	—	$	—
Fees paid to ARM for derivative services	218		209		411		283		66
Total fees paid to ARM	$	694	$	209	$	1,548	$	283	$	66

Receivables from ARM for sales on our behalf were $0.2 million and $38.4 million as of June 30, 2019 and December 31, 2018, respectively, which are reflected in accounts receivable on our balance sheets.

We believe that the loss of any of our customers, or of our marketing agent ARM, would not have a material adverse effect on us because alternative purchasers are readily available. 

NOTE 14 — EQUITY-BASED COMPENSATION (Successor)

Stock compensation expense allocated to us by AMR pursuant to its equity-based compensation programs was as follows:

	Successor								Predecessor
(in thousands)	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
Stock options	$	744	$	1,606	$	1,535	$	2,628	$	—
Restricted stock awards	563		871		1,425		1,412		—
Performance-based restricted stock units	89		1,144		97		2,349		—
Total compensation expense	$	1,396	$	3,621	$	3,057	$	6,389	$	—

Performance-based restricted stock units (“PSUs”) issued in 2018 generally vest over three years at 20% during the first year (“2018 tranche”), 30% during the second year (“2019 tranche”), and 50% during the third year (“2020 tranche”). The number of PSUs vesting each year are based on achievement of annual company-specific performance goals and obligations applicable to each year of vesting. Based on achievement of those goals and objectives, the number of PSUs that can vest range from 0% to 200% of the target growth applicable to each vesting period. The performance goals set for the 2018 tranche were not attained and, therefore, the 2018 tranche was forfeited as of December 31, 2018, except with respect to separations involving employment agreements whereby the separated employee was eligible to receive the award granted.

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The performance targets for the 2019 tranche were established in March 2019 and 595,417 PSUs were deemed granted at that time. The fair value of the 2019 tranche granted was $0.27 per unit, which will be recognized as expense over the remainder of 2019, subject to continued employment.

No performance targets have yet been established for the 2020 tranche and therefore, no expense will be recognized for those awards until the specific targets have been established and probability of attainment can be measured.

NOTE 15 — RELATED PARTY TRANSACTIONS 

As of December 31, 2018, we had a payable of $2.9 million to KFM for produced water disposal services provided following the sale of the produced water system to them during the fourth quarter of 2018. Beginning in 2019, these costs are utilized to reduce the amount that KFM owes us for marketing our production, which are reported in related party receivables.

As of December 31, 2018, we had a payable to AMR of $0.5 million which was settled during the second quarter of 2019.

David Murrell, our Vice President of Land and Business Development, is the principal of David Murrell & Associates, which provided land consulting services to us until termination of our contract in December 2018. The primary employee of David Murrell & Associates was his spouse, Brigid Murrell. Services were provided at a pre-negotiated hourly rate based on actual time utilized by us. Total expenditures under this arrangement were approximately $83,000 and $28,000 for the period February 9, 2018 through June 30, 2018, and the Predecessor Period, respectively. These amounts are recorded in general and administrative expenses.

David McClure, AMR’s former Vice President of Facilities and Infrastructure, and the son-in-law of our former President and Chief Executive Officer, Harlan H. Chappelle, received total compensation of $768,860, $929,428 and $28,874 during the six months ended June 30, 2019, the period February 9, 2018 through June 30, 2018, and the Predecessor Period, respectively. These amounts are included in general and administrative expense and represent the portion that was allocated to AMH. Mr. McClure separated from the Company in February 2019.

Bayou City Agreement

In January 2016, our wholly owned subsidiary Oklahoma Energy entered into a Joint Development Agreement, as amended on June 10, 2016 and December 31, 2016, (the “JDA”), with BCE, a fund advised by Bayou City, to fund a portion of our drilling operations and to allow us to accelerate development of our STACK acreage. The JDA established a development plan of 60 wells in three tranches, and provides opportunities for an additional 20 wells. Pursuant to the JDA, BCE committed to fund 100% of our working interest up to a maximum average well cost of $3.2 million in drilling and completion costs per well for any tranche. We are responsible for any drilling and completion costs exceeding approved amounts. BCE may request refunds of certain advances from time to time if funded wells previously on the drilling schedule were subsequently removed. In exchange for funding the drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which BCE interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return. Following the completion of each joint well, we and BCE each bear our respective proportionate working interest share of all subsequent costs related to such joint well.  Mr. William McMullen, one of our directors, is founder and managing partner of BCE. The approximate dollar value of the amount involved in this transaction, or Mr. McMullen’s interests in the transaction, depends on a number of factors outside his control and is not known at this time.  During the Predecessor Period, BCE advanced us approximately $39.5 million to drill wells under the JDA. Through June 30, 2019, 61 joint wells have been drilled or spudded. At June 30, 2019 and December 31, 2018, $4.0 million and $9.8 million, respectively of revenue and net advances remaining from BCE for their working interest share of the drilling and development costs arising under the JDA were included as “Advances from related party” in our condensed consolidated balance sheets. At June 30, 2019, there were no funded horizontal wells in progress, and we do not expect any wells to be developed in 2019 pursuant to the JDA. On June 11, 2019, we received a letter from BCE noticing us of alleged defaults under the JDA. We dispute these allegations and intend to vigorously defend ourselves.

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. 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

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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 gas prices, production timing and volumes, our ability to continue as a going concern, estimates of proved reserves, operating costs and capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed in “Cautionary Statement Regarding Forward-Looking Statements” at the beginning of this Quarterly Report and in the sections titled “Risk Factors” in this Quarterly Report and in our 2018 10-K, 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 are an exploration and production company focused on the acquisition, development, exploration and exploitation of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma. Our activities are primarily directed at the horizontal development of an oil and liquids-rich resource play in an area of the basin commonly referred to as the STACK. We generate revenue principally by the production and sale of oil, natural gas and NGLs. We maintain operational control of the majority of our properties, either through directly operating them or through operating arrangements with other interest owners.

As a result of the Business Combination, our identifiable assets acquired and liabilities assumed by our parent company were recorded at their estimated fair values at February 9, 2018 and were pushed down to us.  As a result, our financial statements and certain footnote presentations separate our presentations into two distinct periods, the period before the consummation of the Business Combination (“Predecessor”) and the period after that date (“Successor”), to indicate the application of the different basis of accounting between the periods presented. Accordingly, the period January 1, 2018 to February 8, 2018 is referred to as the Predecessor Period.

We distributed our non-STACK oil and gas assets and liabilities to High Mesa in connection with the closing of the Business Combination. We report the non-STACK oil and gas assets and liabilities as discontinued operations during the Predecessor Period.

As of June 30, 2019, we have a highly contiguous position of approximately 130,000 net acres in the up-dip, naturally-fractured oil portion of the STACK primarily in eastern Kingfisher and south-eastern Major counties in Oklahoma. Our drilling locations primarily target the Osage, Meramec and Oswego formations. After the Business Combination, we conducted development activities using a spacing array of 6 to 10 wells per section and running up to 9 rigs at the peak activity level. In late 2018, our production across the acreage evidenced that the well spacing was not delivering the well level production that we expected. During January 2019, we suspended our development program to allow our new management team to conduct a full operational and economic review. We restarted our development program in March 2019 with a less dense spacing pattern of up to five wells per section. In addition, we have worked to improve our economic returns by reducing well costs, general and administrative expense and other operating expense.

We have operated 2 rigs since restarting the program, however following the redetermination of the borrowing base of the Alta Mesa RBL in August 2019, we have decided to operate 1 rig starting in September. We will continue to evaluate how much, if any, development is appropriate going forward.

Outlook, Market Conditions and Commodity Prices

Our revenue, profitability and future growth rate depend on many factors, particularly the prices of oil, gas and NGLs, which are beyond our control.  The success of our business is significantly affected by the price of oil due to its weighting in our production profile. 

Factors affecting oil prices include worldwide economic conditions; geopolitical activities in various regions of the world; worldwide supply and demand conditions; weather conditions; actions taken by the Organization of Petroleum Exporting Countries; and the value of the U.S. dollar in international currency markets. Commodity prices remain unpredictable and we cannot accurately predict future commodity prices and, therefore, cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital expenditures, production volumes or revenues.  In the event that oil, gas and NGLs prices significantly decrease, such decreases 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 the borrowing capacity under the Alta Mesa RBL.

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Key performance indicators

During 2019, our board of directors has established the following operating measures as key performance indicators for executive management compensation and the Company as a whole:

• Production;

• General and administrative costs (excluding strategic costs);

• Lease operating expense;

• Well drilling and completion costs; and

• Adjusted EBITDAX.

We will focus on measuring our performance against baseline and prior year comparable periods during this and future filings.

The Company’s management believes Adjusted EBITDAX is useful because it allows users to more effectively evaluate our operating performance, compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure and because it highlights trends in our business that may not otherwise be apparent when relying solely on GAAP measures. Adjusted EBITDAX should not be considered as an alternative to our net income (loss), operating income (loss) or other performance measures derived in accordance with GAAP and may not be comparable to similarly titled measures in other companies’ reports.

Going concern

Our present level of indebtedness and the current commodity price environment present challenges to our ability to comply with the covenants under our debt agreements. As a result of our updated forecasted production levels and pressures created by lower commodity prices, in the absence of one or more deleveraging transactions, we do not anticipate maintaining compliance with the consolidated total leverage ratio covenant in the Alta Mesa RBL as early as the measurement date of September 30, 2019. Also, in August 2019 the lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reduced to $200 million. As such, we are required to repay the $162.4 million of combined excess of our borrowings and letters of credit outstanding ratably over five months in $32.5 million installments, which will have an adverse impact on our liquidity. The first payment is due in September 2019. If we are unable to make repayment of this amount, we will be in default under the Alta Mesa RBL. As a consequence of both reduced operating cash flow and a reduced borrowing base, we may have limited ability to obtain the capital necessary to conduct our operations at desired levels. Our general partner’s board of directors and our parent’s board of directors and its financial advisors are evaluating the available financial alternatives, waivers to the covenants or other provisions of our indebtedness, raising new capital from the private or public markets or taking other actions to address our capital structure. If we are unable to reach an agreement with our lenders or find acceptable alternative financing, it may lead to an event of default under the Alta Mesa RBL. If an event of default occurs and the Alta Mesa RBL lenders were to accelerate repayment, it may result in an acceleration of the 2024 Notes. We have concluded that these and other circumstances create substantial doubt regarding our ability to continue as a going concern. We currently anticipate that our indebtedness will accelerate prior to July 1, 2020 and therefore, have reported all of our debt as current at June 30 2019.

If an agreement is reached with our creditors and we pursue a restructuring, it may be necessary for us to file a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code in order to implement the agreement through the confirmation and consummation of a plan of reorganization approved by the bankruptcy court. We may also conclude it is necessary to initiate Chapter 11 proceedings to implement a restructuring of our obligations even if we are otherwise unable to reach an agreement with our creditors. If a plan of reorganization is implemented in a bankruptcy proceeding, it is possible that holders of claims, including our secured and unsecured creditors, will receive substantially less than the amount of their claims. Our Risk Factors described in our 2018 10-K contain important information.

Derivatives

The objective of our hedging program is to produce, over time, relative revenue stability. However, in the short-term, both settlements and fair value changes in our derivatives can significantly impact our results of operations, and we expect these gains and losses to continue to reflect the impact of changes in oil and gas prices. Our derivatives are reported at fair value and are sensitive to changes in the price of oil and gas. Changes in derivatives are reported as gain (loss) on derivatives, which include both the unrealized increase and decrease in their fair value, as well as the effect of realized settlements during the period. For the six months ended June 30, 2019, we recognized a net loss on our derivatives of $11.4 million, which includes $0.9 million in cash received upon derivative settlements.

Impairments

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In late fourth quarter of 2018, the combination of depressed prevailing oil and gas prices, changes to assumed spacing in conjunction with evolving views on the viability of multiple benches and reduced individual well expectations resulted in impairment charges of $2.0 billion to our proved and unproved oil and gas properties during the quarter ended December 31, 2018. Individual well expectations were impacted by reductions in estimated reserve recovery of original oil and gas in place. In the future, we may recognize further impairments of proved and unproved oil and gas properties if commodity prices decline from current levels, incremental downward revisions to production forecasts occur or operating costs increase. Prolonged low commodity prices may also result in additional impairments of other assets and could cause us to delay or abandon anticipated development activities.

Factors affecting future performance

The primary factors affecting our production levels, which may be interrelated, are current commodity prices, capital availability, the effectiveness and efficiency of our production operations, the success of our drilling program and our inventory of drilling prospects. In addition, our wells have significant natural production declines. We attempt to overcome this natural decline primarily through development of our existing undeveloped resources, well recompletions and other enhanced recovery methods. Sustaining our production levels or our future growth will depend on our ability to continue to develop reserves, including our ability to fund such development. Our ability to add reserves through drilling and other development techniques is dependent on current market conditions and 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 revenue and, as a result, our cash flow from operations.

Results of Operations

For the Three Months Ended June 30, 2019 (“Second Quarter 2019”) Compared to the Three Months Ended June 30, 2018 (“Second Quarter 2018”).

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Revenue

Our oil, gas and NGLs revenue varies as a result of changes in commodity prices and production volumes.  The following table summarizes our revenue and production data for the periods presented:

(in thousands, except per unit data)	Second Quarter 2019			Second Quarter 2018
Net production:
Oil (Mbbls)	1,545			1,123
Natural gas (MMcf)	6,283			3,944
NGLs (Mbbls)	819			554
Total (MBoe)	3,411			2,334
Average net daily production volumes:
Oil (Mbblsd)	17.0			12.3
Natural gas (MMcfd)	69.0			43.3
NGLs (Mbblsd)	9.0			6.1
Total (MBoed)	37.5			25.6
Average sales prices:
Oil (per bbl)	$	58.67		$	67.09
Effect of realized derivatives settlements (per bbl)	0.12			(12.80		)
Oil, after hedging (per bbl)	$	58.79		$	54.29
Percentage of unhedged realized oil price to NYMEX oil price	97		%	99		%
Natural gas (per Mcf)	$	1.97		$	2.02
Effect of realized derivatives settlements (per Mcf)	0.06			—
Natural gas, after hedging (per Mcf)	$	2.03		$	2.02
NGLs (per bbl)	$	12.52		$	18.47
Effect of realized derivatives settlements (per bbl)	—			—
NGLs, after hedging (per bbl)	$	12.52		$	18.47
Revenue
Oil sales	$	90,668		$	75,291
Natural gas sales	12,384			7,980
NGL sales	10,251			10,241
Total sales revenue	$	113,303		$	93,512

Oil sales for the Second Quarter 2019increased due to increased production, partially offset by lower average sales prices before hedging. The increase in production was due to the extensive development program conducted following the Business Combination.

Natural gas sales for the Second Quarter 2019increased primarily due to increased production as a result of the extensive development program conducted following the Business Combination.

NGL sales for the Second Quarter 2019increased modestly due to increased 2019 production, mostly offset by lower average prices. The increase in production volume was primarily due to the impact of our development activities after the Business Combination. 

Derivatives

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(in thousands)	Second Quarter 2019		Second Quarter 2018
Gain (loss) on derivatives:
Oil	$	191	$	(14,362	)
Natural gas	353		3
Total realized gains (losses)	544		(14,359		)
Unrealized gains (losses)	11,868		(14,860		)
Total gain (loss) on derivatives	$	12,412	$	(29,219	)

Decreases and increases in future commodity prices during each period compared to futures prices in effect at the time of execution of our outstanding derivatives resulted in the gains and losses recognized, respectively, during each quarter.

Operating Expenses

(in thousands, except per unit data)	Second Quarter 2019		Second Quarter 2018
Operating expenses:
Lease operating	$	19,123	$	12,679
Transportation and marketing	19,614		11,206
Production taxes	5,117		2,606
Workovers	412		333
Exploration	3,289		8,083
Depreciation, depletion and amortization	34,504		26,670
Impairment of assets	6,500		—
General and administrative	15,723		17,811
Total operating expense	$	104,282	$	79,388
Operating expenses per BOE:
Lease operating	$	5.61	$	5.43
Transportation and marketing	5.75		4.80
Production taxes	1.50		1.12
Workovers	0.12		0.14
Depreciation, depletion and amortization	10.12		11.43

Lease operating expense for the Second Quarter 2019increased due to higher production and the impact of additional costs associated with the sale of our produced water assets to our affiliate KFM in the fourth quarter of 2018.

Transportation and marketing expense for the Second Quarter 2019increased due to higher volumes. The fee we pay per unit reflects the firm processing capacity at the plant, as well as firm transport for our residue gas at the tailgate of the plant. The amount for the Second Quarter 2019 also reflects a more significant expense due to an increase in committed capacity which went unused.

Production taxes for the Second Quarter 2019increased due to the increase in oil and NGL revenue and an increase in the Oklahoma severance tax rate from 2% to 5%, effective in the third quarter of 2018, for wells in their first 3 years of production.

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(in thousands)	Second Quarter 2019		Second Quarter 2018
Exploration expense:
Geological and geophysical costs	$	366	$	1,139
Other exploration expense, including expired leases	2,909		6,579
ARO settlements in excess of recorded liabilities	14		365
Total exploration expense	$	3,289	$	8,083

Exploration expense during the Second Quarter 2019decreased compared to the Second Quarter 2018 largely due to $3.7 million of lower expired lease costs.

Depreciation, depletion and amortization was lower on a per BOE basis during the Second Quarter 2019 largely due to the amount of impairment taken on our oil and gas properties during the fourth quarter of 2018, which reduced the depletable base.

During the Second Quarter 2019, we recognized a $6.5 million impairment of our operating lease right-of-use assets.

(in thousands)	Second Quarter 2019		Second Quarter 2018
General and administrative expense:
Employee-related costs	$	6,649	$	6,126
Equity-based compensation	1,396		3,621
Professional fees	126		3,843
Strategic costs	4,061		—
Business Combination	—		443
Severance costs	609		—
Information technology	946		2,146
Operating leases	1,293		995
Provision for uncollectible receivables	298		—
Other	345		637
Total general and administrative expense	$	15,723	$	17,811

General and administrative expenses during the Second Quarter 2019decreased due mainly to lower costs associated with equity-based compensation expense and information technology costs associated with the change in control. General and administrative expense during the Second Quarter 2019 also included costs for legal and financial advisory services associated with financial structuring activities, including negotiations with representatives of our lenders and other third parties.

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Below is a reconciliation of our income (loss) from continuing operations before income taxes to our Adjusted EBITDAX:

(in thousands)	Second Quarter 2019			Second Quarter 2018
Income (loss) from continuing operations before income taxes	$	7,746		$	(22,470	)
Interest expense	14,071			10,361
Depreciation, depletion and amortization	34,504			26,670
Exploration	3,289			8,083
Loss (gain) on unrealized hedges	(11,868		)	14,860
Impairment of assets	6,500			—
Equity-based compensation	1,396			3,621
Severance costs	609			—
Strategic costs	4,061			—
Business Combination	—			443
Adjusted EBITDAX	$	60,308		$	41,568

Other (Income) Expense

(in thousands)	Second Quarter 2019			Second Quarter 2018
Alta Mesa RBL	$	5,204		$	—
2024 Notes	9,844			9,844
Bond premium amortization	(1,231		)	(1,231		)
Deferred financing cost amortization	94			80
Other	160			1,668
Total interest expense	14,071			10,361
Interest income and other	(54		)	(820		)
Total other expense, net	$	14,017		$	9,541

Interest expense for the Second Quarter 2019 increased due primarily to increased levels of borrowings under the Alta Mesa RBL. Other interest expense includes commitment fees and interest expense related to our joint development agreement with BCE.

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For the Six Months Ended June 30, 2019 (“2019 Period”) Compared to the Periods February 9, 2018 Through June 30, 2018 (Successor) and January 1, 2018 Through February 8, 2018 (Predecessor)

The tables included below set forth financial information for the Successor Periods and Predecessor Period, which are distinct reporting periods.  The Predecessor Period amounts below exclude operating results related to discontinued operations. For simplicity, in our discussion below, we refer to the combined periods February 9, 2018 through June 30, 2018 and January 1, 2018 through February 8, 2018 as the “2018 period”.

Revenue

Our oil, gas and NGLs revenue varies as a result of changes in commodity prices and production volumes.  The following table summarizes our revenue and production data for the periods presented:

	Successor						Predecessor
(in thousands, except per unit data)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Net production:
Oil (Mbbls)	3,164			1,774			494
Natural gas (MMcf)	12,114			6,192			1,609
NGLs (Mbbls)	1,614			777			151
Total (MBoe)	6,797			3,583			914
Average net daily production volumes:
Oil (Mbblsd)	17.5			12.5			12.7
Natural gas (MMcfd)	66.9			43.6			41.2
NGLs (Mbblsd)	8.9			5.5			3.9
Total (MBoed)	37.6			25.2			23.4
Average sales prices:
Oil (per bbl)	$	55.94		$	65.16		$	62.68
Effect of realized derivatives settlements (per bbl)	0.61			(11.01		)	(6.44		)
Oil, after hedging (per bbl)	$	56.55		$	54.15		$	56.24
Percentage of unhedged realized oil price to NYMEX oil price	97		%	99		%	99		%
Natural gas (per Mcf)	$	2.55		$	2.13		$	2.66
Effect of realized derivatives settlements (per Mcf)	(0.08		)	0.09			0.94
Natural gas, after hedging (per Mcf)	$	2.47		$	2.22		$	3.60
NGLs (per bbl)	$	13.30		$	19.25		$	26.41
Effect of realized derivatives settlements (per bbl)	—			—			—
NGLs, after hedging (per bbl)	$	13.30		$	19.25		$	26.41
Revenue
Oil sales	$	177,031		$	115,569		$	30,972
Natural gas sales	30,834			13,190			4,276
NGL sales	21,467			14,955			4,000
Total sales revenue	$	229,332		$	143,714		$	39,248

28

Oil sales for the 2019 periodincreased due to increased production, partially offset by lower average sales prices before hedging. The increase in production was due to the extensive development program conducted following the Business Combination.

Natural gas sales for the 2019 periodincreased due to both an increase in production as a result of the extensive development program conducted following the Business Combination and higher prevailing market prices.

NGL sales for the 2019 periodincreased due to increased production, significantly offset by lower average prices. The increase in production volume was primarily due to the impact of our extensive 2018 development activities following the Business Combination.

Gain (loss) on sale of assets for the 2019 period included a gain from the sale of seismic data totaling $1.5 million compared to a similar gain of $5.9 million during the 2018 period.

Derivatives

	Successor						Predecessor
(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Gain (loss) on derivatives:
Oil	$	1,936		$	(18,892	)	$	(3,819	)
Natural gas	(1,027		)	558			1,523
Total realized gains (losses)	909			(18,334		)	(2,296		)
Unrealized gains (losses)	(12,274		)	(32,896		)	8,959
Total gain (loss) on derivatives	$	(11,365	)	$	(51,230	)	$	6,663

Decreases and increases in future commodity prices during each period compared to futures prices in effect at the time of execution of our outstanding derivatives resulted in the gains and losses recognized, respectively, during each six month period.

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Operating Expenses

	Successor				Predecessor
(in thousands, except per unit data)	Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
Operating expenses:
Lease operating	$	44,231	$	20,996	$	4,408
Transportation and marketing	37,375		16,788		3,725
Production taxes	10,600		4,021		953
Workovers	609		1,578		423
Exploration	5,343		9,668		7,003
Depreciation, depletion and amortization	69,179		37,708		11,670
Impairment of assets	6,500		—		—
General and administrative	36,670		52,465		21,234
Total operating expense	$	210,507	$	143,224	$	49,416
Operating expenses per BOE:
Lease operating	$	6.51	$	5.86	$	4.82
Transportation and marketing	5.50		4.69		4.08
Production taxes	1.56		1.12		1.04
Workovers	0.09		0.44		0.46
Depreciation, depletion and amortization	10.18		10.52		12.77

Lease operating expense for the 2019 periodincreased primarily due to higher production and the impact of additional costs associated with the sale of our produced water assets to our affiliate KFM in the fourth quarter of 2018.

Transportation and marketing expense for the 2019 periodincreased primarily due to higher volumes. The fee we pay per unit reflects the firm processing capacity at the plant, as well as firm transport for our residue gas at the tailgate of the plant.  The 2019 period also reflects a more significant expense due to an increase in committed capacity which went unused.

Production taxes for the 2019 periodincreased primarily due to the increase in oil and NGL revenue and an increase in the Oklahoma severance tax rate from 2% to 5%, effective in the third quarter of 2018, for wells in their first 3 years of production. 

Workovers are associated with maintenance and other efforts to increase production. During the 2019 period, these costs decreased due to minimal workover projects being undertaken.

	Successor				Predecessor
(in thousands)	Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
Exploration expense:
Geological and geophysical costs	$	678	$	1,590	$	2,440
Other exploration expense, including expired leases	4,604		7,412		4,504
ARO settlements in excess of recorded liabilities	61		666		59
Total exploration expense	$	5,343	$	9,668	$	7,003

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Exploration expense for the 2019 perioddecreased primarily due to our cost reduction efforts, including a reduced number of employees in the geology department, and a decrease in expenses relating to expired or expiring leaseholds.

During the 2019 period, we recognized a $6.5 million impairment of our operating lease right-of-use assets.

	Successor				Predecessor
(in thousands)	Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
General and administrative expense:
Employee-related costs	$	14,957	$	12,646	$	1,032
Equity-based compensation	3,057		6,389		—
Professional fees	3,723		5,083		1,019
Strategic costs	4,061		—		—
Business Combination	10		23,717		17,040
Severance costs	4,584		—		—
Information technology	1,980		2,649		—
Operating leases	2,317		1,486		208
Provision for uncollectible receivables	1,177		—		—
Other	804		495		1,935
Total general and administrative expense	$	36,670	$	52,465	$	21,234

General and administrative expense for the 2019 perioddecreased compared to the 2018 period primarily due to nonrecurring Business Combination costs and other professional fees incurred in the 2018 period for advisors helping to value and integrate the acquired business. General and administrative expense during the 2019 period also included costs for legal and financial advisory services associated with financial structuring activities, including negotiations with representatives of our lenders and other third parties.

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Below is a reconciliation of our income (loss) from continuing operations before income taxes to our Adjusted EBITDAX:

	Successor						Predecessor
(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Income (loss) from continuing operations before income taxes	$	(16,979	)	$	(57,071	)	$	(7,116	)
Interest expense	26,901			15,557			5,511
Depreciation, depletion and amortization	69,179			37,708			11,670
Exploration	5,343			9,668			7,003
Loss (gain) on unrealized hedges	12,274			32,896			(8,959		)
Loss on sale of property and equipment	—			63			—
Impairment of assets	6,500			—			—
Equity-based compensation	3,057			6,389			—
Severance costs	4,584			—			—
Strategic costs	4,061			—			—
Business Combination	10			23,717			17,040
Adjusted EBITDAX	$	114,930		$	68,927		$	25,149

Other (Income) Expense

	Successor						Predecessor
(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Alta Mesa RBL	$	8,783		$	252		$	815
2024 Notes	19,688			16,406			3,281
Bond premium amortization	(2,462		)	(2,051		)	—
Deferred financing cost amortization	139			80			171
Other	753			870			1,244
Total interest expense	26,901			15,557			5,511
Interest income and other	(81		)	(1,366		)	(172		)
Total other expense, net	$	26,820		$	14,191		$	5,339

Interest expense for the 2019 periodincreased primarily due to increased levels of borrowing under the Alta Mesa RBL. Other interest expense includes commitment fees and interest expense related to our joint development agreement with BCE.

Liquidity and Capital Resources

Our principal requirements for capital are to fund our day-to-day operations, development activities and to satisfy our contractual obligations related to servicing our debt and hedges. During 2019, our main sources of liquidity and capital resources have come from operating cash flow and borrowings under the Alta Mesa RBL, including a $66.5 million draw in April 2019.

During April 2019, our borrowing base was reduced from $400.0 million to $370.0 million as part of the semi-annual redetermination. At June 30, 2019, we had outstanding borrowings of approximately $344.5 million and outstanding letters of credit of $20.2 million, leaving us $5.3 million of remaining borrowing capacity. We held $78.3 million of cash and cash equivalents on hand at June 30, 2019. We do not anticipate maintaining compliance with the consolidated total leverage ratio

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covenant in the Alta Mesa RBL as early as the measurement date of September 30, 2019. Also, in August 2019 the lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reduced to $200 million. As such, we are required to repay the $162.4 million of combined excess of our borrowings and letters of credit outstanding ratably over five months in $32.5 million installments, which will have an adverse impact on our liquidity. The first payment is due in September 2019. If we are unable to make repayment of this amount, we will be in default under the Alta Mesa RBL. As a consequence of both reduced operating cash flow and a reduced borrowing base, we may have limited ability to obtain the capital necessary to conduct our operations at desired levels. Our general partner’s board of directors and our parent’s board of directors and its financial advisors are evaluating the available financial alternatives, waivers to the covenants or other provisions of our indebtedness, raising new capital from the private or public markets or taking other actions to address our capital structure. If we are unable to reach an agreement with our lenders or find acceptable alternative financing, it may lead to an event of default under the Alta Mesa RBL. If an event of default occurs and the Alta Mesa RBL lenders were to accelerate repayment, it may result in an acceleration of the 2024 Notes. We have concluded that these and other circumstances create substantial doubt regarding our ability to continue as a going concern. We currently anticipate that our indebtedness will accelerate prior to July 1, 2020 and therefore, have reported all of our debt as current at June 30 2019.

Our future drilling plans and capital budgets are subject to change based upon various factors, some of which are beyond our control, including drilling results, oil and gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, midstream availability, other working interest owner participation and regulatory matters. Any deferral of planned capital expenditures, particularly with respect to bringing new wells onto production, could reduce our anticipated production, revenue and cash flow, and may result in the expiry of certain leases. However, because a large percentage of our acreage is held by production, we can alter our drilling program to minimize the risk of losing significant acreage. 

Although we are currently capitally constrained, we strive to maintain financial flexibility and, if available on terms we find acceptable, we may access the capital markets to facilitate our development program, to selectively expand our acreage position or to redesign our capital structure. If our operating cash flow is materially less than anticipated and other sources of capital are not available on acceptable terms, we may decide to curtail our capital spending which would have an adverse impact on our ability to develop our acreage as we would have otherwise planned. 

With our $370.0 million borrowing base, we expected to operate 2 rigs during the remainder of 2019 to develop our assets, particularly to focus on testing the spacing patterns we believe to be optimal, and to continue executing our cost reduction strategies begun earlier in 2019. Prior to the August 2019 redetermination, we anticipated drilling and bringing online approximately 60 to 65 wells during 2019 while incurring approximately $140.0 million to $155.0 million of capital expenditures under a 2-rig program. We also expected that an additional $20.0 million to $30.0 million could be incurred for other non-operated projects, leasehold costs and capitalized workover activity. Following the redetermined borrowing base of $200 million in August 2019, we decided to operate 1 rig starting in September. We will continue to evaluate how much, if any, development is appropriate going forward. We do not expect our 2019 operating cash flow alone to provide sufficient proceeds to meet our 2019 capital expenditure levels and we would be required to utilize existing cash on hand.

As we execute our business strategy, we will monitor the capital resources available to meet future financial obligations and planned capital expenditures. We cannot provide assurance that operations and other needed capital will be available on acceptable terms, or at all, and our development pace may need to change based on our evolving liquidity profile.

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Cash Flow Analysis

	Successor						Predecessor
(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Cash from operating activities	$	61,818		$	(45,489	)	$	26,336
Cash from investing activities	(180,138		)	(307,743		)	(37,913		)
Cash from financing activities	183,500			417,913			16,932
Net increase in cash, cash equivalents and restricted cash	$	65,180		$	64,681		$	5,355

Cash flow from operating activities

During the 2019 period, cash-based items of net income (loss), including revenue (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense totaled $73.9 million compared to $29.2 million during the 2018 period, due largely to higher revenues associated with increased production and the lack of costs associated with the Business Combination that were incurred in 2018. Approximately $12.0 million of cash was used to increase working capital during the six months ended June 30, 2019. During the 2018 period, cash totaling $48.4 million was used to increase working capital primarily due to increases in trade receivables and amounts due from related parties for administrative services provided, including certain other transactions, and to reduce liabilities arising prior to or as a result of the Business Combination.

Cash flow from investing activities

	Successor						Predecessor
(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Cash provided by (used for)
Capital expenditures	$	(180,138	)	$	(319,042	)	$	(36,695	)
Acquisition of acreage	—			—			(1,218		)
Proceeds from sale of property and equipment	—			11,299			—
Cash from investing activities	$	(180,138	)	$	(307,743	)	$	(37,913	)

During the 2019 period, capital expenditures included $91.6 million for additions to property and equipment that occurred prior to December 31, 2018. Capital spending during 2019 has decreased significantly from 2018 as a result of the reassessment of our current drilling plans due to the results obtained from our 2018 drilling program and our existing liquidity concerns. We ran as many as 9 rigs during the 2018 period.

Cash flow from financing activities

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	Successor					Predecessor
(in thousands)	Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Cash provided by (used for)
Proceeds from long-term debt borrowings	$	183,500	$	—		$	60,000
Repayments of long-term debt	—		(134,065		)	(43,000		)
Capital contributions (distributions), net	—		553,344			(68		)
Other	—		(1,366		)	—
Cash from financing activities	$	183,500	$	417,913		$	16,932

During the 2019 period, our outstanding balance owed under the Alta Mesa RBL increased by $183.5 million from December 31, 2018, largely related to borrowings to fund of our capital expenditures, including those expenditures incurred in 2018.

Immediately following the Business Combination on February 9, 2018, we received a capital contribution from our immediate parent, SRII Opco, of $560.3 million, a portion of which was used to fund additional capital expenditures.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to certain market risks that are inherent in our financial statements that arise in the normal course of business. We may enter into derivatives to manage or reduce market risk, but we do not enter into derivatives for speculative purposes. We do not designate derivatives as hedges for accounting purposes.

Commodity Price Risk and Hedges

Our major market risk exposure is to prices for oil, gas and NGLs, which have historically been volatile. As such, future results are subject to change due to changes in these prices. Realized prices are primarily driven by the prevailing worldwide price for oil and regional prices for gas. We have used, and expect to continue to use, derivatives to reduce our exposure to the risks of price changes. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against low prices and price volatility associated with developed and undeveloped reserves.

Forecasted production from proved reserves is estimated in our December 31, 2018 reserve report using prices, costs and other assumptions required by SEC rules. Our actual production will vary from the amounts estimated in the report, perhaps materially. Our Risk Factors in our 2018 10-K contain discussions of significant matters related to future production.

The fair value of our oil and gas derivatives and basis swaps at June 30, 2019 was a net asset of $6.2 million. A 10% increase or decrease in oil and gas prices (with all other factors held constant) would result in an unrealized loss or gain in the fair value of our oil and gas derivatives for the six months ended June 30, 2019 of $7.7 million and $18.9 million, respectively.

Counterparty and Customer Credit Risk

Our derivatives expose us to credit risk in the event of nonperformance by counterparties. While we do not require them to post collateral, we do monitor the credit standing of such counterparties, all of which have investment grade ratings, and are lenders under the Alta Mesa RBL.

Our principal ongoing exposures to credit risk are from joint interest receivables and receivables from the sale of our oil and gas production. The inability or failure of our customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit quality of our purchasers of production and other working interest owners is high.

During a portion of 2019 and throughout 2018, ARM Energy Management, LLC ("ARM") marketed our oil, gas and NGLs for a marketing fee that is deducted from sales proceeds collected by ARM from purchasers. The sales are generally made under short-term contracts with month-to-month pricing based on published regional indices, adjusted for transportation, location and quality.  In March 2019, in preparation for handling oil and NGL marketing responsibilities internally, we began receiving

35

payments for the sale of oil and NGLs directly from purchasers and separately paying the marketing fee owed to ARM.  As of June 1, 2019, we terminated our oil and NGL marketing agreement with ARM and have begun marketing such products internally. We have extended the term of our gas marketing agreement with ARM through November 30, 2019.

For the six months ended June 30, 2019, ARM marketed $91.5 million, or 39.8% of our operating revenue for the period.

Joint operations receivables arise from billings to entities that own interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells.

Interest Rates

We are subject to interest rate risk under the Alta Mesa RBL. We currently have no open interest rate derivatives. A 100 basis point increase in interest rates would increase annual interest expense on the Alta Mesa RBL by approximately $3.4 million, based on the balance outstanding at June 30, 2019.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the 2019 period.  Although the impact of inflation has been insignificant in recent years, it could cause future upward pressure on the cost of oilfield services, equipment and general and administrative expenses. 

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rules 13a-15 and 15d-15 of the Exchange Act, our management, with the participation of our principal executive officer and principal financial officer, performed an evaluation of our disclosure controls and procedures. Our controls and procedures are designed to ensure that information required to be disclosed by the Company in reports it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC, and that the information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

As described further in our 2018 10-K, we concluded that our disclosure controls and procedures were not effective as of December 31, 2018, due to existence of material weakness in our internal control over financial reporting (“ICFR”). Apart from the controls and procedures relating to accounting for business combinations, several of the material weaknesses in our ICFR continued to exist during the 2019 period. These material weaknesses include:

• establishment of formal policies and procedures;

• ineffective monitoring activities that span the Company to ensure that internal controls processes are functioning properly;

• ineffective controls over the financial statement close and disclosure process; and

• over-reliance on and ineffective controls over access to and changes involving critical worksheets.

Changes in Internal Control Over Financial Reporting (ICFR)

While we have made progress in multiple areas to improve ICFR, management is continuing to implement the remediation plan described in our 2018 10-K and continues to work to make changes in controls and procedures in a manner consistent with the size, complexity and scale of operations subsequent to the Business Combination.

During the Second Quarter 2019, we have made access changes to payroll, production accounting, and reserves systems to address material weaknesses identified during 2018. Testing to be conducted later in 2019 will determine whether these changes to system access will prove effective in remediating the underlying material weakness.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings

We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business. The outcomes cannot be reasonably estimated. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, we may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. There have been no significant changes during the 2019 period to the matters described in Legal Proceedings in our 2018 10-K.

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. There have been no material changes during the 2019 period to the risk factors described under Risk Factors in our 2018 10-K.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits

Exhibit Number	Description of Exhibit
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 to Exhibit 2.1 to Alta Mesa Holdings, LP’s Form 8-K filed with the SEC on August 17, 2017 (File No. 333-173751))
3.1	Articles of Organization of Alta Mesa Holdings GP, LLC, dated September 26, 2005 (incorporated by reference from Exhibit 3.1 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011 (File No. 333-173751)).
3.2	Sixth Amended and Restated Limited Liability Company Agreement of Alta Mesa Holdings GP, LLC, dated February 9, 2018 (incorporated by reference from Exhibit 3.2 to Alta Mesa Holdings, LP’s current report on Form 8-K filed with the SEC on February 14, 2018 (File No. 333-173751)).
3.3	Certificate of Limited Partnership of Alta Mesa Holdings, LP, dated September 26, 2005 (incorporated by reference from Exhibit 3.3 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011 (File No. 333-173751)).
3.4	Seventh Amended and Restated Agreement of Limited Partnership of Alta Mesa Holdings, LP, dated as of February 9, 2018 (incorporated by reference from Exhibit 3.1 to Alta Mesa Holdings, LP’s current report on Form 8-K filed with the SEC on February 14, 2018 (File No. 333-173751)).
3.5	Certificate of Incorporation of Alta Mesa Finance Services Corp., dated September 27, 2010 (incorporated by reference from Exhibit 3.7 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011 (File No. 333-173751)).
3.6	Bylaws of Alta Mesa Finance Services Corp., dated September 27, 2010 (incorporated by reference from Exhibit 3.8 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011 (File No. 333-173751)).
4.1	Indenture, dated December 8, 2016, by and among Alta Mesa Holdings, LP, Alta Mesa Finance Services Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as Trustee (incorporated by reference from Exhibit 4.1 to Alta Mesa Holdings, LP’s current report on Form 8-K filed with the SEC on December 8, 2016 (File No. 333-173751)).
4.2	Registration Rights Agreement, dated December 8, 2016, by and among Alta Mesa Holdings, LP, Alta Mesa Finance Services Corp., the Guarantors named therein and Wells Fargo Securities, LLC, as representative of the Initial Purchasers (incorporated by reference from Exhibit 4.2 to Alta Mesa Holdings, LP’s current report on Form 8-K filed with the SEC on December 8, 2016 (File No. 333-173751)).
10.1	Separation Agreement dated as of July 2, 2019 by and between Ronald J. Smith and Alta Mesa Services, LP (incorporated by reference from exhibit 10.1 to Alta Mesa Holdings, LP’s current report on Form 8-K filed with the SEC on July 8, 2019 (File No. 333-173751)).
10.4	Independent Manager Agreement, dated June 12, 2019, between Alta Mesa Holdings GP, LLC and Patrick J. Bartels Jr. (incorporated by reference from Exhibit 10.4 to Alta Mesa Holdings, LP’s Quarterly Report on Form 10-Q filed with the SEC on June 13, 2019.)
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
		By: Alta Mesa Holdings GP, LLC
		Its general partner
		(Registrant)
By	/s/ John C. Regan
	John C. Regan
	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
Dated	August 27, 2019

39

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, James T. Hackett, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Alta Mesa Holdings, LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of Alta Mesa Holdings, LP as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for Alta Mesa Holdings, LP and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to Alta Mesa Holdings, LP, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of Alta Mesa Holdings, LP’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in Alta Mesa Holdings, LP’s internal control over financial reporting that occurred during Alta Mesa Holdings, LP’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, Alta Mesa Holdings, LP’s internal control over financial reporting;

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to Alta Mesa Holdings, LP’s auditors and the audit committee of Alta Mesa Holdings, LP’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect Alta Mesa Holdings, LP’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in Alta Mesa Holdings, LP’s internal control over financial reporting.

Date: August 27, 2019

/s/ James T. Hackett

James T. Hackett

Interim Chief Executive Officer

Alta Mesa Holdings GP, LLC

(as general partner of Alta Mesa Holdings, LP)

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, John C. Regan, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Alta Mesa Holdings, LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of Alta Mesa Holdings, LP as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for Alta Mesa Holdings, LP and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to Alta Mesa Holdings, LP, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of Alta Mesa Holdings, LP’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in Alta Mesa Holdings, LP’s internal control over financial reporting that occurred during Alta Mesa Holdings, LP’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, Alta Mesa Holdings, LP’s internal control over financial reporting;

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to Alta Mesa Holdings, LP’s auditors and the audit committee of Alta Mesa Holdings, LP’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect Alta Mesa Holdings, LP’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in Alta Mesa Holdings, LP’s internal control over financial reporting.

Date: August 27, 2019

/s/ John C. Regan

John C. Regan

Chief Financial Officer

Alta Mesa Holdings GP, LLC

(as general partner of Alta Mesa Holdings, LP)

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF

CHIEF EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

I, James T. Hackett, Interim Chief Executive Officer of Alta Mesa Holdings, GP, LLC, the general partner of Alta Mesa Holdings, LP (the “Company”), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that, to the best of my knowledge:

1. The Quarterly Report on Form 10-Q of the Company for the period ended June 30, 2019 (the “Report”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 (15 U.S.C. 78m); and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: August 27, 2019

/s/ James T. Hackett

James T. Hackett

Interim Chief Executive Officer

Alta Mesa Holdings GP, LLC

(as general partner of Alta Mesa Holdings, LP)

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

EXHIBIT 32.2

CERTIFICATION OF

CHIEF FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

I, John C. Regan, Chief Financial Officer of Alta Mesa Holdings, GP, LLC, the general partner of Alta Mesa Holdings, LP (the “Company”), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that, to the best of my knowledge:

1. The Quarterly Report on Form 10-Q of the Company for the period ended June 30, 2019 (the “Report”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 (15 U.S.C. 78m); and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: August 27, 2019

/s/ John C. Regan

John C. Regan

Chief Financial Officer

Alta Mesa Holdings GP, LLC

(as general partner of Alta Mesa Holdings, LP)

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Document And Entity Information	6 Months Ended
	Jun. 30, 2019 shares
Document And Entity Information [Abstract]
Entity Registrant Name	Alta Mesa Holdings, LP
Entity Central Index Key	0001518403
Document Type	10-Q
Document Period End Date	Jun. 30, 2019
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	true
Entity Ex Transition Period	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)	0
Entity Current Reporting Status	No
Entity Interactive Data Current	Yes

XML

Condensed Consolidated Statements Of Operations (Unaudited) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		5 Months Ended	6 Months Ended
	Feb. 08, 2018	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2018
Revenue
Operating revenue		$ 113,633	$ 95,741	$ 146,498	$ 230,230
Gain (loss) on sale of assets		0	(63)	5,076	1,483
Gain (loss) on derivatives		12,412	(29,219)	(51,230)	(11,365)
Total revenue		126,045	66,459	100,344	220,348
Operating expenses
Lease operating		19,123	12,679	20,996	44,231
Transportation and marketing		19,614	11,206	16,788	37,375
Production taxes		5,117	2,606	4,021	10,600
Workovers		412	333	1,578	609
Exploration		3,289	8,083	9,668	5,343
Depreciation, depletion and amortization		34,504	26,670	37,708	69,179
Impairment of assets		6,500	0	0	6,500
General and administrative		15,723	17,811	52,465	36,670
Total operating expenses		104,282	79,388	143,224	210,507
Operating income		21,763	(12,929)	(42,880)	9,841
Other income (expense)
Interest expense		(14,071)	(10,361)	(15,557)	(26,901)
Interest income and other		54	820	1,366	81
Total other expense, net		(14,017)	(9,541)	(14,191)	(26,820)
Income (loss) from continuing operations before income taxes		7,746	(22,470)	(57,071)	(16,979)
Income tax provision (benefit)		0	7	7	0
Income (loss) from continuing operations		7,746	(22,477)	(57,078)	(16,979)
Loss from discontinued operations, net of tax		0	0	0	0
Net income (loss)		7,746	(22,477)	(57,078)	(16,979)
Oil
Revenue
Operating revenue		90,668	75,291	115,569	177,031
Natural gas
Revenue
Operating revenue		12,384	7,980	13,190	30,834
Natural gas liquids
Revenue
Operating revenue		10,251	10,241	14,955	21,467
Other
Revenue
Operating revenue		$ 330	$ 2,229	$ 2,784	$ 898
Predecessor
Revenue
Operating revenue	$ 40,136
Gain (loss) on sale of assets	840
Gain (loss) on derivatives	6,663
Total revenue	47,639
Operating expenses
Lease operating	4,408
Transportation and marketing	3,725
Production taxes	953
Workovers	423
Exploration	7,003
Depreciation, depletion and amortization	11,670
Impairment of assets	0
General and administrative	21,234
Total operating expenses	49,416
Operating income	(1,777)
Other income (expense)
Interest expense	(5,511)
Interest income and other	172
Total other expense, net	(5,339)
Income (loss) from continuing operations before income taxes	(7,116)
Income tax provision (benefit)	0
Income (loss) from continuing operations	(7,116)
Loss from discontinued operations, net of tax	(7,746)
Net income (loss)	(14,862)
Predecessor | Oil
Revenue
Operating revenue	30,972
Predecessor | Natural gas
Revenue
Operating revenue	4,276
Predecessor | Natural gas liquids
Revenue
Operating revenue	4,000
Predecessor | Other
Revenue
Operating revenue	$ 888

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Current assets
Cash and cash equivalents	$ 78,275	$ 12,984
Restricted cash	890	1,001
Accounts receivable, net	61,662	68,370
Other receivables	3,530	6,267
Related party receivables, net	13,149	24,282
Notes receivable from related parties, net	0	0
Prepaid expenses and other current assets	4,623	747
Derivatives	4,727	16,423
Total current assets	166,856	130,074
Property and equipment, net
Oil and gas properties, successful efforts method	784,079	763,337
Other property and equipment	37,371	38,147
Total property and equipment	821,450	801,484
Other assets
Operating lease right-of-use assets, net	7,871
Deferred financing costs, net	1,021	1,151
Deposits and other long-term assets	38	63
Derivatives	2,508	2,947
Total other assets	11,438	4,161
Total assets	999,744	935,719
Current liabilities
Current portion of debt	871,162	0
Accounts payable and accrued liabilities	91,694	197,064
Accounts payable - related party	222	3,425
Advances from non-operators	1,755	5,193
Advances from related party	4,003	9,822
Asset retirement obligations	44	2,079
Current operating lease liability	938
Derivatives	840	1,710
Total current liabilities	970,658	219,293
Long-term liabilities
Asset retirement obligations, net of current portion	12,293	9,330
Long-term debt, net	0	690,123
Operating lease liabilities, net of current portion	13,733
Derivatives	189	180
Total long-term liabilities	26,215	699,633
Total liabilities	996,873	918,926
Commitments and contingencies
Partners’ capital	2,871	16,793
Total liabilities and partners’ capital	$ 999,744	$ 935,719

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Condensed Consolidated Statements Of Changes In Partners' Capital (Unaudited) $ in Thousands	USD ($)
BALANCE, BEGINNING (Predecessor) at Dec. 31, 2017	$ 154,445
Distribution of non-STACK oil and gas assets, net of associated liabilities, and Contributions | Predecessor	43,482
Net loss | Predecessor	(14,862)
BALANCE, ENDING (Predecessor) at Feb. 08, 2018	183,065
BALANCE, ENDING at Feb. 08, 2018	1,535,891
BALANCE, BEGINNING (Predecessor) at Dec. 31, 2017	154,445
Net loss	(16,979)
BALANCE, ENDING at Jun. 30, 2018	2,048,013
BALANCE, BEGINNING (Predecessor) at Feb. 08, 2018	183,065
BALANCE, BEGINNING at Feb. 08, 2018	1,535,891
Distribution of non-STACK oil and gas assets, net of associated liabilities, and Contributions	560,344
Equity-based compensation expense	2,768
Net loss	(34,601)
BALANCE, ENDING at Mar. 31, 2018	2,064,402
BALANCE, BEGINNING (Predecessor) at Feb. 08, 2018	183,065
BALANCE, BEGINNING at Feb. 08, 2018	1,535,891
Net loss	(57,078)
BALANCE, ENDING at Jun. 30, 2018	2,048,013
BALANCE, BEGINNING at Mar. 31, 2018	2,064,402
Issuance of additional purchase consideration	9,467
Equity-based compensation expense	3,621
Distributions	(7,000)
Net loss	(22,477)
BALANCE, ENDING at Jun. 30, 2018	2,048,013
BALANCE, BEGINNING at Dec. 31, 2018	16,793
Equity-based compensation expense	1,661
Net loss	(24,725)
BALANCE, ENDING at Mar. 31, 2019	(6,271)
BALANCE, BEGINNING at Dec. 31, 2018	16,793
Net loss	(16,979)
BALANCE, ENDING at Jun. 30, 2019	2,871
BALANCE, BEGINNING at Mar. 31, 2019	(6,271)
Equity-based compensation expense	1,396
Net loss	7,746
BALANCE, ENDING at Jun. 30, 2019	$ 2,871

XML

Condensed Consolidated Statements Of Cash Flows (Unaudited) - USD ($) $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended			5 Months Ended	6 Months Ended		12 Months Ended
	Feb. 08, 2018	Mar. 31, 2018	Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Cash flows from operating activities:
Net loss		$ (34,601)	$ 7,746	$ (24,725)	$ (22,477)	$ (57,078)	$ (16,979)	$ (16,979)
Adjustments to reconcile net loss to cash from operating activities:
Depreciation, depletion, amortization and accretion						37,708	69,179
Non-cash lease expense						0	1,587
Provision for uncollectible receivables						0	1,177
Impairment of assets						0	6,500
Amortization of deferred financing costs						80	139
Amortization of debt (premium) discount						(2,051)	(2,462)
Equity-based compensation expense			1,396		3,621	6,389	3,057
Non-cash exploration expense						10,658	388
(Gain) loss on derivatives			(12,412)		29,219	51,230	11,365	11,365
Cash settlements of derivatives						18,334	(909)
Premium paid on derivatives						0	(1,000)
Interest converted into debt						0	0
Interest added to notes receivable from affiliate						(417)	0
Loss on sale of fixed assets						63	0
Impact on cash from changes in:
Accounts receivable						(2,923)	6,384
Other receivables						1,426	2,737
Receivables from related parties						(18,494)	10,280
Prepaid expenses and other non-current assets						7,810	(3,853)
Advances from related party						(10,371)	(5,819)
Settlement of asset retirement obligations						(806)	0
Accounts payable to related party						(4,994)	(3,203)
Accounts payable, accrued liabilities and other liabilities						(45,385)	(17,281)
Operating lease obligations						0	(1,287)
Cash from operating activities						(45,489)	61,818
Cash flows from investing activities:
Capital expenditures						(319,042)	(180,138)
Acquisitions, net of cash acquired						0	0
Proceeds from sale of assets						11,299	0
Cash from investing activities						(307,743)	(180,138)
Cash flows from financing activities:
Proceeds from long-term debt borrowings						0	183,500
Repayments of long-term debt						(134,065)	0
Deferred financing costs paid						(1,366)	0
Capital distributions						(7,000)	0
Capital contributions						560,344	0
Cash from financing activities						417,913	183,500
Net increase in cash, cash equivalents and restricted cash						64,681	65,180
Cash, cash equivalents and restricted cash, beginning of period		10,345		$ 13,985		10,345	13,985
Cash, cash equivalents and restricted cash, end of period	$ 10,345		$ 79,165		$ 75,026	75,026	$ 79,165	75,026	$ 13,985
Predecessor
Cash flows from operating activities:
Net loss	(14,862)
Adjustments to reconcile net loss to cash from operating activities:
Depreciation, depletion, amortization and accretion	12,554
Non-cash lease expense	0
Provision for uncollectible receivables	0
Impairment of assets	5,560
Amortization of deferred financing costs	171
Amortization of debt (premium) discount	0
Equity-based compensation expense	0
Non-cash exploration expense	4,575
(Gain) loss on derivatives	(6,663)
Cash settlements of derivatives	2,296
Premium paid on derivatives									0
Interest converted into debt	103
Interest added to notes receivable from affiliate	(85)
Loss on sale of fixed assets	1,923
Impact on cash from changes in:
Accounts receivable	(21,184)
Other receivables	(662)
Receivables from related parties	(117)
Prepaid expenses and other non-current assets	(591)
Advances from related party	24,116
Settlement of asset retirement obligations	(63)
Accounts payable to related party	0
Accounts payable, accrued liabilities and other liabilities	23,857
Operating lease obligations	0
Cash from operating activities	26,336
Cash flows from investing activities:
Capital expenditures	(36,695)
Acquisitions, net of cash acquired	(1,218)
Proceeds from sale of assets									0
Cash from investing activities	(37,913)
Cash flows from financing activities:
Proceeds from long-term debt borrowings	60,000
Repayments of long-term debt	(43,000)
Deferred financing costs paid	0
Capital distributions	(68)
Capital contributions	0
Cash from financing activities	16,932
Net increase in cash, cash equivalents and restricted cash	5,355
Cash, cash equivalents and restricted cash, beginning of period	4,990	$ 10,345				$ 10,345		$ 4,990	$ 4,990
Cash, cash equivalents and restricted cash, end of period	$ 10,345

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Description of Business and Basis of Presentation

6 Months Ended

Jun. 30, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Description of Business and Basis of Presentation

DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

Alta Mesa Holdings, LP (“Alta Mesa” or “the Company”) is an exploration and production company focused on the acquisition, development, exploration and exploitation of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma commonly referred to as the STACK. Our operations prior to February 9, 2018, also included other oil and natural gas interests in Texas, Idaho, Louisiana and Florida. In connection with our acquisition by Alta Mesa Resources, Inc. (“AMR”), on February 9, 2018 (“the Business Combination”), we distributed the non-STACK oil and gas assets and liabilities to our prior owner, High Mesa Holdings, LP (“High Mesa”), and completed our transition from a diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource unconventional play in the STACK.  Prior to the closing of the Business Combination, we were controlled by High Mesa Inc. (“HMI”). The 2018 10-K contains substantially more information about our operations and the Business Combination.

All intercompany transactions and accounts have been eliminated. These interim condensed consolidated financial statements are unaudited, but we believe these statements reflect all adjustments necessary for a fair presentation for the periods reported. All such adjustments are of a normal, recurring nature unless otherwise disclosed. These financial statements and disclosures have been prepared in accordance with the SEC’s rules for interim financial statements and do not include all the information and disclosures required by generally accepted accounting principles (“GAAP”). These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our 2018 10-K. The results for the three and six months ended June 30, 2019, are not necessarily indicative of the results to be expected for the full year. We have no items of other comprehensive income during any period presented.

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Summary Of Significant Accounting Policies

6 Months Ended

Jun. 30, 2019

Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Going Concern

We are required to evaluate our ability to continue as a going concern for a period of one year following the date of issuance of our financial statements. As part of that evaluation, we took into consideration the following factors:

• Market prices for crude oil have declined since the Business Combination. This negatively impacted our future operating cash flow and lowers our expected future economic results from our assets compared with the time of the Business Combination.

• Our 2018 drilling program, much of which involved the drilling of additional wells in close proximity to existing wells, did not meet our expectations for production and recovery and reduces the number of wells we expect to develop in the future compared with the time of the Business Combination. We also experienced an increasing gas-to-oil ratio as a well’s production ages, which has contributed to a lowering of the expected economics of our properties.

• Although our well costs for our 2019 capital program have averaged less than $3.0 million per well, we still expect our operating cash flow to be less than our 2019 capital spending. Future well costs are expected to increase as we move into higher cost areas of our acreage which have less infrastructure in place and that may require more intense completions.

• On April 1, 2019, our borrowing base under the Alta Mesa RBL was reduced to $370.0 million and we had no meaningful remaining capacity available thereunder at June 30, 2019. Without additional capital, we will only be able to utilize the cash on hand, which at July 31, 2019 was $79.7 million, to fund development and meet our financial obligations. We may be unable to obtain covenant relief or to replace the Alta Mesa RBL with debt that would allow us to meet any attendant covenant requirements. Also, the lack of sufficient capital may prevent us from maintaining our current levels of production, which could negatively impact our ability over time to service our debt and meet our other obligations. In August 2019, the lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reset to $200 million, effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceed the new borrowing base amount by $162.4 million, we have five months to make ratable payments of $32.5 million to cause utilization to be less than or equal to the borrowing base. The first payment is due in September 2019. If we are unable to make this repayment, we will be in default under the Alta Mesa RBL. There is a risk that future redeterminations could reduce the borrowing base further. Our decreased borrowing base could cause us to reduce or abandon our development activities.

• We do not anticipate meeting our existing leverage covenants through June 2020 without relief from our lenders and currently expect not to be able to satisfy the consolidated total leverage ratio covenant in the Alta Mesa RBL as early as the measurement date of September 30, 2019.

• We have $500.0 million of unsecured debt in the form of our 2024 Notes, with an interest payment of approximately $20.0 million due in December 2019, which could become an event of default if unpaid before January 14, 2020. The 2024 Notes trade substantially below par value.

• The Class A common stock of our parent company, AMR, has been trading below $1.00 per share since February 22, 2019. On April 3, 2019, AMR was notified by NASDAQ that it was not in compliance with the minimum bid price requirement. Continued trading at these levels may limit its and our ability to raise additional capital in the equity markets.

• Our ability to collect receivables due from High Mesa and its affiliates

The above factors raise substantial doubt about our and our parent’s ability to continue as a going concern. To address this, we have:

• retained financial advisors to assist in evaluating financial alternatives;

• engaged in discussions with the advisors for the Alta Mesa RBL lenders about obtaining covenant relief to address the future expected inability to satisfy the leverage requirement. To date we have been unable to reach an accord on any such relief and do not expect that the lenders would grant any extended period of covenant relief;

• considered seeking new sources of financing, however, such efforts do not appear to present a substantive solution; and

• engaged in discussions with and provided requested information to financial and legal advisors for a group of holders of Alta Mesa’s 2024 Notes, but we cannot predict what will result from the discussions or whether they will yield a constructive deal.

Regardless of whether we are able to reach an agreement with our creditors, it may be necessary for us to file a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code. In light of these factors, we believe substantial unresolved doubt exists regarding our ability to continue as a going concern for the 12 months following the issuance of these financial statements. Based on the foregoing, we believe that it is probable that our indebtedness will accelerate before July 2020 and, therefore, have reported all of our debt as current.

Recently Issued Accounting Standards Applicable to Us

Adopted

Effective January 1, 2019, we adopted ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which requires that lessees recognize a lease liability, which is a lessee’s discounted obligation to make payments under a lease and a right-of-use asset, arising from a lessee’s right to use an asset over the lease term. Upon adoption, we used the modified retrospective method to apply the standard as of January 1, 2019 for existing leases with terms in excess of 12 months entered into prior to January 1, 2019.

Not Yet Adopted

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses(Topic 326): Measurement of Credit Losses on Financial Instruments. This standard requires the use of a new “expected credit loss” impairment model rather than the “incurred loss” model we use today. With respect to our trade and notes receivables and certain other financial instruments, we may be required to (i) maintain and use lifetime loss information rather than annual loss data and (ii) forecast future economic conditions and quantify the effect of those conditions on future expected losses. The standard, including related amendments, which will be effective for us on January 1, 2020, also requires additional disclosures regarding the credit quality of our trade and notes receivables and other financial instruments. No determination has yet been made of the impact of this new standard on our financial position or results of operations.

In August 2018, the FASB issued ASU No. 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Topic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). The amendments in this standard align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal use software (and hosting arrangements that include an internal-use software license). Under this new standard, a customer in a hosting arrangement that is a service contract is required to follow the guidance in Subtopic 350-40 to determine which implementation costs to capitalize as a prepaid asset related to the service contract and which costs to expense. The capitalized implementation costs are to be expensed over the term of the hosting arrangement and reflected in the same line in the consolidated statement of operations as the fees associated with the hosting element of the arrangement. Similarly, capitalized implementation costs are to be presented in the statement of cash flows in the same line as payments made for fees associated with the hosting element. We will adopt this new standard no later than January 1, 2020, although early adoption is permitted. We are currently evaluating the impact of this new standard on our consolidated financial position and results of operations and have not yet determined when to adopt and whether to apply the new standard retrospectively or prospectively to implementation costs incurred after the date of adoption.

In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820) Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which modifies the disclosure requirements of fair value measurements. ASU 2018-13 is effective for us beginning January 1, 2020. Certain disclosures are required to be applied on a retrospective basis and others on a prospective basis. We do not expect the adoption of this standard to impact our financial position or results of operations.

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Adoption of ASU No. 2016-02, Leases

6 Months Ended

Jun. 30, 2019

Leases [Abstract]

Adoption of ASU No. 2016-02, Leases

ADOPTION OF ASU NO. 2016-02, LEASES

ASU No. 2016-02 requires us to recognize a right-of-use (“ROU”) asset and a discounted lease liability on the balance sheet for all leases with a term longer than one year. We adopted ASU No. 2016-02 and related guidance using the modified retrospective method to apply the standard as January 1, 2019, and this adoption had no effect on the earlier comparative periods presented. At adoption, we recognized operating lease ROU assets and operating lease liabilities of $15.0 million. There was no adjustment to beginning of period equity.

We lease office space, office equipment and field equipment, including compressors. Many of our leases include both lease and non-lease components which are primarily management services performed by the lessors for the underlying assets. All of our leases of office space and office equipment were classified as operating leases upon adoption. Our leases of field equipment had remaining terms of less than one year at the date of adoption and were not recognized as operating leases on our balance sheet due to our election of the short term lease practical expedient described below. Our leases do not contain any residual value guarantees or restrictive covenants. We do not sublease any of our ROU assets, although we aspire to sublease our unused office lease space.

Operating fixed lease expenses are recognized on a straight-line basis over the lease term. Variable lease payments, which cannot be determined at the lease commencement date, are not included in ROU assets or lease liabilities and are expensed as incurred.

Upon adoption, we selected the following practical expedients:

Practical expedient package	We did not reassess whether any expired or existing contracts are, or contain, leases.
	We did not reassess the lease classification of any expired or existing leases.
	We did not reassess initial direct costs of any expired or existing leases.
Hindsight practical expedient	We did not elect to use the hindsight practical expedient which allows for the use of hindsight when determining lease term, including option periods, and impairment of operating assets.
Easement expedient	We elected to maintain the current accounting treatment of existing contracts and not reassess whether those contracts met the definition of a lease.
Combining lease and non-lease components expedient	We elected to account for lease and non-lease components as a single component.
Short-term lease expedient	We elected the short-term lease recognition exemption for all classes of underlying assets. Expense for short-term leases is recognized on a straight-line basis over the lease term. Leases with an initial term of 12 months or less and that do not include an option to purchase the underlying asset that is reasonably certain to be recognized are not recorded on the balance sheet.

As most leases do not have readily determinable implicit rates, we estimated the incremental borrowing rates for our future lease payments based on prevailing financial market conditions at the later of date of adoption or lease commencement, comparable companies and credit analysis and management judgments to determine the present values of our lease payments. We also apply the portfolio approach to account for leases with similar terms. At June 30, 2019, for our operating leases the weighted-average remaining lease terms were approximately 8.1 years and our weighted-average discount rates were 14.1%.

Lease Costs

(in thousands)	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Operating lease cost	$	776	$	1,587
Variable lease cost	473		796
Short-term lease cost	1,075		3,261
Total lease cost	$	2,324	$	5,644
Reported as:
Lease operating expense	$	1,031	$	3,326
General and administrative expense	1,293		2,318
Total lease cost	$	2,324	$	5,644

Operating Lease Liability Maturities as of June 30, 2019

Fiscal year	(in thousands)
Remainder of 2019	$	1,470
2020	2,965
2021	2,942
2022	3,010
2023	2,718
Thereafter	12,647
Total lease payments	25,752
Less: imputed interest	(11,081		)
Present value of operating lease liabilities	$	14,671
Current portion of operating lease liabilities	$	938
Operating lease liabilities, net of current portion	13,733
Present value of operating lease liabilities	$	14,671

Operating Lease Payment Obligations as of December 31, 2018

As described further in our 2018 10-K, our minimum future contractual lease payments under ASC 840 at December 31, 2018 were $2.8 million for 2019, $2.9 million for 2020, $2.9 million for 2021, $3.1 million for 2022, $3.0 million for 2023 and $12.2 million thereafter.

Right-of-Use Asset Impairment

During the second quarter of 2019, we consolidated employees in existing leased office space in Houston, Texas and Oklahoma City, Oklahoma. We are seeking to sublease the unused office space within three buildings. We do not anticipate that we will be able to fully recover the cash due to the lessor under the existing operating lease obligations in those three buildings with proceeds from subleases. As a result, we recognized a $6.5 million impairment of our existing right-of-use lease assets in those buildings during the three months ended June 30, 2019. This impairment had no impact to our lease liability.

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Supplemental Cash Flow Information

6 Months Ended

Jun. 30, 2019

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

SUPPLEMENTAL CASH FLOW INFORMATION

	Successor						Predecessor
(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Supplemental cash flow information:
Cash paid for interest	$	25,070		$	21,216		$	1,145
Cash paid for state income taxes, net of refunds	—			6			—
Non-cash investing and financing activities:
Increase in asset retirement obligations	634			877			—
Increase (decrease) in accruals or payables for capital expenditures	(91,639		)	(27,646		)	4,896
Distribution of non-STACK assets, net of liabilities	—			—			43,482

We aggregate cash, cash equivalents and restricted cash in the statements of cash flows.  

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Receivables

6 Months Ended

Jun. 30, 2019

Receivables [Abstract]

Receivables

RECEIVABLES

Accounts Receivable

(in thousands)	June 30, 2019			December 31, 2018
Production sales	$	29,730		$	31,532
Joint interest billings	20,836			18,147
Pooling interest (1)	11,506			18,786
Allowance for doubtful accounts	(410		)	(95		)
Total accounts receivable, net	$	61,662		$	68,370

_________________

(1) Pooling interest relates to Oklahoma’s forced pooling process which permits mineral interest owners the option to participate in the drilling of proposed wells.  The pooling interest listed above represents unbilled costs for wells where the option remains pending.  Depending upon the mineral owner’s decision, these costs will be billed to them or added to oil and gas properties.

Related Party Receivables

(in thousands)	June 30, 2019			December 31, 2018
Related party receivables	$	23,037		$	33,316
Allowance for doubtful accounts	(9,888		)	(9,034		)
Related party receivables, net	13,149			24,282
Notes receivable from related parties	13,403			13,403
Allowance for doubtful accounts	(13,403		)	(13,403		)
Notes receivable from related parties, net	—			—
Total related party receivables, net	$	13,149		$	24,282

KFM Receivables

We have entered into contracts with KFM whereby they provide midstream services, including produced water disposal, to us. During the six months ended June 30, 2019, the period February 9, 2018 through June 30, 2018, and the Predecessor Period, we incurred $30.8 million, $13.6 million, and $3.1 million, respectively, in midstream services, which we have recognized in transportation and marketing expense. Additionally, we had related party receivables from KFM which include its portion of allocated G&A, other expenditures attributable to KFM and proceeds due to us for KFM’s sale of our natural gas and NGLs reduced by the fees from midstream services that KFM provided to us totaling $4.6 million and $11.2 million at June 30, 2019 and December 31, 2018, respectively.

In addition, we sold a produced water disposal system to KFM during the fourth quarter of 2018. As of December 31, 2018, related party receivables of $8.7 million were attributable to a purchase price adjustment due from KFM. We collected this receivable during June 2019.

AMR Receivables

We incur general and administrative costs that may be partially or fully allocable to AMR. These costs are either allocated monthly or charged directly to AMR but are cash settled in arrears. As of June 30, 2019 and December 31, 2018, respectively, we have receivables from AMR for such costs totaling $8.5 million and $3.3 million, respectively.

Management Services Agreement with High Mesa

(in thousands)	June 30, 2019
High Mesa related party receivable at December 31, 2018	$	10,066
Additions	894
Payments	(1,072		)
High Mesa related party receivable at June 30, 2019	9,888
Allowance for uncollectibility(1)	(9,888		)
Balance at June 30, 2019, net	$	—

_________________

(1) $9.0 million of the allowance was recognized during the 2018 Successor Period.

Just prior to the Business Combination, we distributed the non-STACK oil and gas assets to High Mesa. High Mesa and certain of its subsidiaries agreed to indemnify and hold us harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. We also entered into a management services agreement (the “High Mesa Agreement”) with HMI with respect to the non-STACK assets. Under the High Mesa Agreement, during the 180-day period following the Closing, we agreed to provide certain administrative, management and operational services necessary to manage the business of HMI and its subsidiaries (the “Services”). Thereafter, the High Mesa Agreement automatically renewed for additional consecutive 180-day periods, unless terminated by either party upon at least 90-days written notice prior to renewal. HMI agreed to pay us each month (i) a management fee of $10,000 and (ii) an amount equal to any and all costs and expenses incurred in connection with providing the Services.

Although the automatic renewal of this agreement occurred in the third quarter of 2018, the parties subsequently agreed to terminate the High Mesa Agreement, effective January 31, 2019. Through April 1, 2019, we were obligated to take all actions that HMI reasonably requested to effect the transition of the Services to a successor service provider. During the transition period, HMI agreed to pay us (i) for all Services performed, (ii) an amount equal to our costs and expenses incurred in connection with providing the Services as provided for in the approved budget and (iii) an amount equal to our costs and expenses reimbursable pursuant to the High Mesa Agreement. As of June 30, 2019, and December 31, 2018, approximately $9.9 million and $10.1 million, respectively, were due from HMI for reimbursement of costs and expenses which are recorded as “Related party receivables, net” in the balance sheets. HMI has disputed certain of the amounts we billed. We are pursuing remedies under applicable law in connection with repayment of this receivable. There is no guarantee that HMI will pay the amounts it owes. In addition, our ability to collect these amounts or future amounts that may become due pursuant to indemnification obligations may be adversely impacted by liquidity and solvency issues at HMI. As a result of these circumstances, we have recognized an allowance for uncollectible accounts of $9.9 million and $9.0 million as of June 30, 2019 and December 31, 2018, respectively, to fully provide for the unremitted balances. We may also be subject to future contingent liabilities for the non-STACK assets for which we should have been indemnified, including liabilities associated with litigation relating to the non-STACK assets. As of June 30, 2019 and December 31, 2018, we have established no liabilities for contingent obligations associated with non-STACK assets owned by High Mesa.

Promissory notes receivable

In September, 2017, we entered into a $1.5 million promissory note receivable with our affiliate, Northwest Gas Processing, LLC, whose obligation was subsequently transferred to High Mesa Services, LLC (“HMS”), a subsidiary of HMI.  The promissory note bore interest, which could be paid-in-kind and added to the principal amount at a rate of 8% per annum. HMS defaulted under the terms of that promissory note when it was not paid at maturity on February 28, 2019, and HMS has failed to cure such default. We subsequently declared all amounts owed under the note immediately due and payable and we have fully reserved the promissory note balance, including interest paid-in-kind, totaling $1.7 million as of June 30, 2019 and December 31, 2018.

In addition, we have an $8.5 million note receivable from HMS which matures on December 31, 2019, and bears interest at 8% per annum, which may be paid-in-kind and added to the principal amount.  HMI disputes its obligations under the $8.5 million note. As of June 30, 2019, and December 31, 2018, the note receivable balance, including interest paid-in-kind, amounted to $11.7 million, for each respective period. This balance was fully reserved at the end of both periods.

We oppose HMI’s claims and believe HMI’s obligations under the notes to be valid assets and that the full amount is payable to us. We are pursuing remedies under applicable law in connection with repayment of the promissory notes. As a result of the potential conflict of interest from certain of AMR’s directors who are also controlling holders of HMI, AMR’s disinterested directors will address any potential conflicts of interest with respect to this matter.

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Property And Equipment

6 Months Ended

Jun. 30, 2019

Property, Plant and Equipment [Abstract]

Property And Equipment

PROPERTY AND EQUIPMENT

(in thousands)	June 30, 2019			December 31, 2018
Oil and gas properties
Unproved properties	$	76,665		$	74,217
Proved oil and gas properties	2,196,605			2,110,346
Accumulated depletion and impairment	(1,489,191		)	(1,421,226		)
Proved oil and gas properties, net	707,414			689,120
Total oil and gas properties, net	784,079			763,337
Other property and equipment
Land	5,059			5,059
Fresh water wells	27,372			27,366
Produced water disposal system	3,590			3,608
Office furniture, equipment and vehicles	2,825			2,840
Accumulated depreciation	(1,475		)	(726		)
Other property and equipment, net	37,371			38,147
Total property and equipment, net	$	821,450		$	801,484

Depletion and Depreciation Expense

	Successor								Predecessor
(in thousands)	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
Oil and gas properties depletion	$	33,923	$	26,086	$	67,965	$	36,859	$	11,021
Other property and equipment depreciation	341		423		749		586		609
Total depletion and depreciation	$	34,264	$	26,509	$	68,714	$	37,445	$	11,630

Impairment

During the three months ended June 30, 2019, we evaluated the qualitative market conditions and other factors impacting our business and concluded that there were no indicators of impairment impacting our property and equipment. Therefore, we did not conduct further analysis on the recognition of additional impairment.

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Discontinued Operations

6 Months Ended

Jun. 30, 2019

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations

DISCONTINUED OPERATIONS (Predecessor)

Alta Mesa distributed the non-STACK oil and gas assets and related liabilities to High Mesa immediately prior to the Business Combination. This distribution, including the results of operations of these assets and liabilities, is presented as discontinued operations during the Predecessor Period.

	Predecessor
(in thousands)	January 1, 2018 Through February 8, 2018
Revenue
Oil	$	1,617
Natural gas	1,023
Natural gas liquids	236
Other	16
Operating revenue	2,892
Loss on sale of assets	(1,923		)
Total revenue	969
Operating expenses
Lease operating	1,770
Transportation and marketing	83
Production taxes	167
Workovers	127
Depreciation, depletion and amortization	884
Impairment of assets	5,560
General and administrative	21
Total operating expenses	8,612
Other expense
Interest expense	(103		)
Loss from discontinued operations, net of tax	$	(7,746	)

	Predecessor
(in thousands)	January 1, 2018 Through February 8, 2018
Total operating cash flows of discontinued operations	$	2,974
Total investing cash flows of discontinued operations	(601		)

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Derivatives

6 Months Ended

Jun. 30, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

DERIVATIVES

All of our derivatives have the lenders under the Alta Mesa RBL as counterparty, and are collateralized by the security interests thereunder. We periodically monitor the creditworthiness of our counterparties. Although our counterparties provide no collateral, the agreements with each counterparty allow us to set-off unpaid amounts against the outstanding balance under the Alta Mesa RBL. The derivatives settle monthly. No derivatives have been entered into for trading or speculative purposes and none have been designated as hedges under GAAP.

The following summarizes the fair value and classification of our derivatives:

	June 30, 2019
Balance sheet location	Gross fair value of assets		Gross liabilities offset against assets in the Balance Sheet			Net fair value of assets presented in the Balance Sheet
	(in thousands)
Derivatives, current assets	$	13,855	$	(9,128	)	$	4,727
Derivatives, long-term assets	11,977		(9,469		)	2,508
Total	$	25,832	$	(18,597	)	$	7,235

Balance sheet location	Gross fair value of liabilities		Gross assets offset against liabilities in the Balance Sheet			Net fair value of liabilities presented in the Balance Sheet
	(in thousands)
Derivatives, current liabilities	$	9,968	$	(9,128	)	$	840
Derivatives, long-term liabilities	9,658		(9,469		)	189
Total	$	19,626	$	(18,597	)	$	1,029

	December 31, 2018
Balance sheet location	Gross fair value of assets		Gross liabilities offset against assets in the Balance Sheet			Net fair value of assets presented in the Balance Sheet
	(in thousands)
Derivatives, current assets	$	22,512	$	(6,089	)	$	16,423
Derivatives, long-term assets	7,910		(4,963		)	2,947
Total	$	30,422	$	(11,052	)	$	19,370

Balance sheet location	Gross fair value of liabilities		Gross assets offset against liabilities in the Balance Sheet			Net fair value of liabilities presented in the Balance Sheet
	(in thousands)
Derivatives, current liabilities	$	7,799	$	(6,089	)	$	1,710
Derivatives, long-term liabilities	5,143		(4,963		)	180
Total	$	12,942	$	(11,052	)	$	1,890

The following table summarizes the effect of our derivatives in the consolidated statements of operations (in thousands):

	Successor											Predecessor
Derivatives not designated as hedges	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018			Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Gain (loss) on derivatives -
Oil	$	5,134	$	(28,712	)	$	(16,535	)	$	(50,656	)	$	4,796
Natural gas	7,278		(507		)	5,170			(574		)	1,867
Total gain (loss) on derivatives	$	12,412	$	(29,219	)	$	(11,365	)	$	(51,230	)	$	6,663

Other receivables at June 30, 2019 and December 31, 2018 include $1.4 million and $1.3 million, respectively, of derivative positions scheduled to be settled in the ensuing month.

We had the following call and put derivatives at June 30, 2019:

OIL

	Remaining Volume	Weighted		Range
Settlement Period and Type of Contract	in bbls	Average		High		Low
2019
Price Swap Contracts	92,000	$	63.03	$	63.03	$	63.03
Collar Contracts
Short Call Options	1,361,600	66.31		75.20		56.50
Long Put Options	1,453,600	53.80		62.00		50.00
Short Put Options	1,453,600	42.72		52.00		37.50
2020
Collar Contracts
Short Call Options	1,017,600	63.95		73.80		59.55
Long Put Options	1,566,600	56.81		62.50		50.00
Short Put Options	1,566,600	42.81		50.00		37.50
2021
Collar Contracts
Short Call Options	279,750	63.51		63.75		63.35
Long Put Options	659,850	46.94		55.00		41.00
Short Put Options	279,750	43.00		43.00		43.00

NATURAL GAS

	Remaining Volume	Weighted			Range
Settlement Period and Type of Contract	in MMBtu	Average			High			Low
2019
Price Swap Contracts	7,980,000	$	2.67		$	2.72		$	2.64
Basis Swap Contracts	9,680,000	(0.72		)	(0.49		)	(0.93		)
Collar Contracts
Short Call Options	1,525,000	3.19			3.20			3.17
Long Put Options	1,525,000	2.70			2.70			2.70
Short Put Options	1,525,000	2.20			2.20			2.20
2020
Price Swap Contracts	1,284,000	2.54			2.54			2.54
Basis Swap Contracts	910,000	(0.49		)	(0.49		)	(0.50		)
Collar Contracts
Short Call Options	3,874,500	3.19			3.69			2.77
Long Put Options	10,749,500	2.59			3.00			2.50
Short Put Options	9,696,000	2.10			2.50			2.00
2021
Collar Contracts
Short Call Options	540,000	3.25			3.25			3.25
Long Put Options	2,790,000	2.62			2.65			2.50
Short Put Options	2,250,000	2.15			2.15			2.15

We had the following basis swaps at June 30, 2019:

Total Gas Volumes in MMBtu(1) over Remaining Term	Reference Price 1 (1)	Reference Price 2 (1)	Period			Weighted Average Spread ($ per MMBtu)
460,000	OneOK	NYMEX Henry Hub	Jul '19	—	Dec '19	$	(0.93	)
7,990,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Jul '19	—	Dec '19	(0.70		)
910,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Jan '20	—	Mar '20	(0.49		)
1,230,000	San Juan	NYMEX Henry Hub	Jul '19	—	Oct '19	(0.81		)

________________

(1) Represents short swaps that fix the basis differentials between OneOK, Tex/OKL Panhandle Eastern Pipeline (“PEPL”), San Juan and NYMEX Henry Hub.

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Accounts Payable And Accrued Liabilities

6 Months Ended

Jun. 30, 2019

Payables and Accruals [Abstract]

Accounts Payable And Accrued Liabilities

ACCOUNTS PAYABLE AND ACCRUED LIABILITIES 

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(in thousands)	June 30, 2019		December 31, 2018
Accounts payable	$	8,871	$	20,200
Accruals for capital expenditures	18,477		101,214
Revenue and royalties payable	39,232		46,870
Accruals for operating expenses	10,701		16,355
Accrued interest	5,642		1,784
Derivative settlements	743		109
Other	8,028		10,532
Total accrued liabilities	82,823		176,864
Accounts payable and accrued liabilities	$	91,694	$	197,064

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Asset Retirement Obligations

6 Months Ended

Jun. 30, 2019

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS 

	Successor						Predecessor
(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Balance, beginning of period	$	11,409		$	—		$	10,469
Liabilities assumed in Business Combination	—			5,998			—
Liabilities incurred	634			877			—
Liabilities settled	(162		)	(806		)	(63		)
Liabilities transferred in sale of properties	—			(20		)	—
Revisions to estimates	(9		)	665			63
Accretion expense	465			263			40
Balance, end of period	12,337			6,977			10,509
Less: Current portion	44			538			33
Long-term portion	$	12,293		$	6,439		$	10,476

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Debt

6 Months Ended

Jun. 30, 2019

Debt Disclosure [Abstract]

Debt

DEBT

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(in thousands)	June 30, 2019		December 31, 2018
Alta Mesa RBL	$	344,500	$	161,000
2024 Notes	500,000		500,000
Unamortized premium on 2024 Notes	26,662		29,123
Total debt, net	871,162		690,123
Less: Current portion	871,162		—
Long-term debt, net	$	—	$	690,123

Alta Mesa RBL

The Alta Mesa RBL has two covenants that are tested quarterly:

• a ratio of our current assets to current liabilities, inclusive of specified adjustments, of not less than 1.0 to 1.0; and

• a ratio of our consolidated debt to our consolidated Adjusted EBITDAX (the “leverage ratio”) of not greater than 4.0 to 1.0. For the first 3 measurement periods following the Business Combination we were able to annualize cumulative Successor Period results in measuring Adjusted EBITDAX. 

Before July 2020, and possibly as soon as September 30, 2019, we do not expect to satisfy the leverage ratio. We recognize the need to obtain covenant relief or to replace the Alta Mesa RBL with debt that would allow us to meet any attendant covenant requirements.

At June 30, 2019, inclusive of $20.2 million of outstanding letters of credit, we had $5.3 million of stated borrowing capacity remaining under the Alta Mesa RBL, dependent upon the lenders’ willingness to provide such funds.

In August 2019, the lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reset to $200 million, effective August 13, 2019. Our discussion about our ability to continue as a going concern provides information about the borrowing base and deficiency payments arising from the redetermination.

2024 Notes

In connection with the Business Combination, we recorded the fair value of our $500.0 million unsecured senior notes at $533.6 million as of the acquisition date. We have estimated the fair value of our senior notes to be $193.8 million at June 30, 2019.  This estimation was based on the most recent trading values of the senior notes at or near the reporting date, which is a Level 1 determination.

Scheduled Maturities of Debt

Fiscal year	(in thousands)
2019	$	—
2020	—
2021	—
2022	—
2023	344,500
Thereafter	500,000
	$	844,500

Based upon the factors leading to the substantial unresolved doubt about our ability to continue as a going concern, we believe that it is probable that our indebtedness will accelerate prior to July 1, 2020, and earlier than the scheduled maturities shown above. We have reported all of our debt as current at June 30, 2019.

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Commitments And Contingencies

6 Months Ended

Jun. 30, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments And Contingencies

COMMITMENTS AND CONTINGENCIES 

There have been no material changes during the first six months of 2019 in our commitments and contingencies as compared to our discussion of those matters in our 2018 10-K.

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Significant Concentrations

6 Months Ended

Jun. 30, 2019

Significant Concentrations [Abstract]

Significant Concentrations

SIGNIFICANT CONCENTRATIONS 

During a portion of 2019 and throughout 2018, ARM Energy Management, LLC ("ARM") marketed our oil, gas and NGLs for a marketing fee that is deducted from sales proceeds collected by ARM from purchasers. The sales are generally made under short-term contracts with month-to-month pricing based on published regional indices, adjusted for transportation, location and quality.  In March 2019, in preparation for handling oil and NGL marketing responsibilities internally, we began receiving payments for the sale of oil and NGLs directly from purchasers and separately paying the marketing fee owed to ARM.  As of June 1, 2019, we terminated our oil and NGL marketing agreement with ARM and have begun marketing such products internally. We have extended the term of our gas marketing agreement with ARM through November 30, 2019.

Our affiliate, Kingfisher Midstream, LLC (“KFM”) is responsible for marketing our firm transportation on the ONEOK Gas Transmission, L.L.C. system, which is indirectly marketed by ARM through an asset management agreement.

ARM also provides us with strategic advice, execution and reporting services with respect to our derivatives activities.

	Successor								Predecessor
(in thousands)	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
Revenue marketed by ARM on our behalf	$	7,703	$	70,601	$	91,534	$	107,944	$	28,757
Marketing and management fees paid to ARM	$	476	$	—	$	1,137	$	—	$	—
Fees paid to ARM for derivative services	218		209		411		283		66
Total fees paid to ARM	$	694	$	209	$	1,548	$	283	$	66

Receivables from ARM for sales on our behalf were $0.2 million and $38.4 million as of June 30, 2019 and December 31, 2018, respectively, which are reflected in accounts receivable on our balance sheets.

We believe that the loss of any of our customers, or of our marketing agent ARM, would not have a material adverse effect on us because alternative purchasers are readily available.

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Equity-Based Compensation (Successor)

6 Months Ended

Jun. 30, 2019

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Equity-Based Compensation (Successor)

EQUITY-BASED COMPENSATION (Successor)

Stock compensation expense allocated to us by AMR pursuant to its equity-based compensation programs was as follows:

	Successor								Predecessor
(in thousands)	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
Stock options	$	744	$	1,606	$	1,535	$	2,628	$	—
Restricted stock awards	563		871		1,425		1,412		—
Performance-based restricted stock units	89		1,144		97		2,349		—
Total compensation expense	$	1,396	$	3,621	$	3,057	$	6,389	$	—

Performance-based restricted stock units (“PSUs”) issued in 2018 generally vest over three years at 20% during the first year (“2018 tranche”), 30% during the second year (“2019 tranche”), and 50% during the third year (“2020 tranche”). The number of PSUs vesting each year are based on achievement of annual company-specific performance goals and obligations applicable to each year of vesting. Based on achievement of those goals and objectives, the number of PSUs that can vest range from 0% to 200% of the target growth applicable to each vesting period. The performance goals set for the 2018 tranche were not attained and, therefore, the 2018 tranche was forfeited as of December 31, 2018, except with respect to separations involving employment agreements whereby the separated employee was eligible to receive the award granted.

The performance targets for the 2019 tranche were established in March 2019 and 595,417 PSUs were deemed granted at that time. The fair value of the 2019 tranche granted was $0.27 per unit, which will be recognized as expense over the remainder of 2019, subject to continued employment.

No performance targets have yet been established for the 2020 tranche and therefore, no expense will be recognized for those awards until the specific targets have been established and probability of attainment can be measured.

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Related Party Transactions

6 Months Ended

Jun. 30, 2019

Related Party Transactions [Abstract]

Related Party Transactions

NOTE 15 — RELATED PARTY TRANSACTIONS 

As of December 31, 2018, we had a payable of $2.9 million to KFM for produced water disposal services provided following the sale of the produced water system to them during the fourth quarter of 2018. Beginning in 2019, these costs are utilized to reduce the amount that KFM owes us for marketing our production, which are reported in related party receivables.

As of December 31, 2018, we had a payable to AMR of $0.5 million which was settled during the second quarter of 2019.

David Murrell, our Vice President of Land and Business Development, is the principal of David Murrell & Associates, which provided land consulting services to us until termination of our contract in December 2018. The primary employee of David Murrell & Associates was his spouse, Brigid Murrell. Services were provided at a pre-negotiated hourly rate based on actual time utilized by us. Total expenditures under this arrangement were approximately $83,000 and $28,000 for the period February 9, 2018 through June 30, 2018, and the Predecessor Period, respectively. These amounts are recorded in general and administrative expenses.

David McClure, AMR’s former Vice President of Facilities and Infrastructure, and the son-in-law of our former President and Chief Executive Officer, Harlan H. Chappelle, received total compensation of $768,860, $929,428 and $28,874 during the six months ended June 30, 2019, the period February 9, 2018 through June 30, 2018, and the Predecessor Period, respectively. These amounts are included in general and administrative expense and represent the portion that was allocated to AMH. Mr. McClure separated from the Company in February 2019.

Bayou City Agreement

In January 2016, our wholly owned subsidiary Oklahoma Energy entered into a Joint Development Agreement, as amended on June 10, 2016 and December 31, 2016, (the “JDA”), with BCE, a fund advised by Bayou City, to fund a portion of our drilling operations and to allow us to accelerate development of our STACK acreage. The JDA established a development plan of 60 wells in three tranches, and provides opportunities for an additional 20 wells. Pursuant to the JDA, BCE committed to fund 100% of our working interest up to a maximum average well cost of $3.2 million in drilling and completion costs per well for any tranche. We are responsible for any drilling and completion costs exceeding approved amounts. BCE may request refunds of certain advances from time to time if funded wells previously on the drilling schedule were subsequently removed. In exchange for funding the drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which BCE interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return. Following the completion of each joint well, we and BCE each bear our respective proportionate working interest share of all subsequent costs related to such joint well.  Mr. William McMullen, one of our directors, is founder and managing partner of BCE. The approximate dollar value of the amount involved in this transaction, or Mr. McMullen’s interests in the transaction, depends on a number of factors outside his control and is not known at this time.  During the Predecessor Period, BCE advanced us approximately $39.5 million to drill wells under the JDA. Through June 30, 2019, 61 joint wells have been drilled or spudded. At June 30, 2019 and December 31, 2018, $4.0 million and $9.8 million, respectively of revenue and net advances remaining from BCE for their working interest share of the drilling and development costs arising under the JDA were included as “Advances from related party” in our condensed consolidated balance sheets. At June 30, 2019, there were no funded horizontal wells in progress, and we do not expect any wells to be developed in 2019 pursuant to the JDA. On June 11, 2019, we received a letter from BCE noticing us of alleged defaults under the JDA. We dispute these allegations and intend to vigorously defend ourselves.

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Summary Of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2019

Accounting Policies [Abstract]

Going Concern

Going Concern

We are required to evaluate our ability to continue as a going concern for a period of one year following the date of issuance of our financial statements. As part of that evaluation, we took into consideration the following factors:

• Market prices for crude oil have declined since the Business Combination. This negatively impacted our future operating cash flow and lowers our expected future economic results from our assets compared with the time of the Business Combination.

• Our 2018 drilling program, much of which involved the drilling of additional wells in close proximity to existing wells, did not meet our expectations for production and recovery and reduces the number of wells we expect to develop in the future compared with the time of the Business Combination. We also experienced an increasing gas-to-oil ratio as a well’s production ages, which has contributed to a lowering of the expected economics of our properties.

• Although our well costs for our 2019 capital program have averaged less than $3.0 million per well, we still expect our operating cash flow to be less than our 2019 capital spending. Future well costs are expected to increase as we move into higher cost areas of our acreage which have less infrastructure in place and that may require more intense completions.

• On April 1, 2019, our borrowing base under the Alta Mesa RBL was reduced to $370.0 million and we had no meaningful remaining capacity available thereunder at June 30, 2019. Without additional capital, we will only be able to utilize the cash on hand, which at July 31, 2019 was $79.7 million, to fund development and meet our financial obligations. We may be unable to obtain covenant relief or to replace the Alta Mesa RBL with debt that would allow us to meet any attendant covenant requirements. Also, the lack of sufficient capital may prevent us from maintaining our current levels of production, which could negatively impact our ability over time to service our debt and meet our other obligations. In August 2019, the lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reset to $200 million, effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceed the new borrowing base amount by $162.4 million, we have five months to make ratable payments of $32.5 million to cause utilization to be less than or equal to the borrowing base. The first payment is due in September 2019. If we are unable to make this repayment, we will be in default under the Alta Mesa RBL. There is a risk that future redeterminations could reduce the borrowing base further. Our decreased borrowing base could cause us to reduce or abandon our development activities.

• We do not anticipate meeting our existing leverage covenants through June 2020 without relief from our lenders and currently expect not to be able to satisfy the consolidated total leverage ratio covenant in the Alta Mesa RBL as early as the measurement date of September 30, 2019.

• We have $500.0 million of unsecured debt in the form of our 2024 Notes, with an interest payment of approximately $20.0 million due in December 2019, which could become an event of default if unpaid before January 14, 2020. The 2024 Notes trade substantially below par value.

• The Class A common stock of our parent company, AMR, has been trading below $1.00 per share since February 22, 2019. On April 3, 2019, AMR was notified by NASDAQ that it was not in compliance with the minimum bid price requirement. Continued trading at these levels may limit its and our ability to raise additional capital in the equity markets.

• Our ability to collect receivables due from High Mesa and its affiliates

The above factors raise substantial doubt about our and our parent’s ability to continue as a going concern. To address this, we have:

• retained financial advisors to assist in evaluating financial alternatives;

• engaged in discussions with the advisors for the Alta Mesa RBL lenders about obtaining covenant relief to address the future expected inability to satisfy the leverage requirement. To date we have been unable to reach an accord on any such relief and do not expect that the lenders would grant any extended period of covenant relief;

• considered seeking new sources of financing, however, such efforts do not appear to present a substantive solution; and

• engaged in discussions with and provided requested information to financial and legal advisors for a group of holders of Alta Mesa’s 2024 Notes, but we cannot predict what will result from the discussions or whether they will yield a constructive deal.

Regardless of whether we are able to reach an agreement with our creditors, it may be necessary for us to file a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code. In light of these factors, we believe substantial unresolved doubt exists regarding our ability to continue as a going concern for the 12 months following the issuance of these financial statements. Based on the foregoing, we believe that it is probable that our indebtedness will accelerate before July 2020 and, therefore, have reported all of our debt as current.

Recently Issue

Recently Issued and Applicable Accounting Standards

Recently Issued Accounting Standards Applicable to Us

Adopted

Effective January 1, 2019, we adopted ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which requires that lessees recognize a lease liability, which is a lessee’s discounted obligation to make payments under a lease and a right-of-use asset, arising from a lessee’s right to use an asset over the lease term. Upon adoption, we used the modified retrospective method to apply the standard as of January 1, 2019 for existing leases with terms in excess of 12 months entered into prior to January 1, 2019.

Not Yet Adopted

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses(Topic 326): Measurement of Credit Losses on Financial Instruments. This standard requires the use of a new “expected credit loss” impairment model rather than the “incurred loss” model we use today. With respect to our trade and notes receivables and certain other financial instruments, we may be required to (i) maintain and use lifetime loss information rather than annual loss data and (ii) forecast future economic conditions and quantify the effect of those conditions on future expected losses. The standard, including related amendments, which will be effective for us on January 1, 2020, also requires additional disclosures regarding the credit quality of our trade and notes receivables and other financial instruments. No determination has yet been made of the impact of this new standard on our financial position or results of operations.

In August 2018, the FASB issued ASU No. 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Topic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). The amendments in this standard align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal use software (and hosting arrangements that include an internal-use software license). Under this new standard, a customer in a hosting arrangement that is a service contract is required to follow the guidance in Subtopic 350-40 to determine which implementation costs to capitalize as a prepaid asset related to the service contract and which costs to expense. The capitalized implementation costs are to be expensed over the term of the hosting arrangement and reflected in the same line in the consolidated statement of operations as the fees associated with the hosting element of the arrangement. Similarly, capitalized implementation costs are to be presented in the statement of cash flows in the same line as payments made for fees associated with the hosting element. We will adopt this new standard no later than January 1, 2020, although early adoption is permitted. We are currently evaluating the impact of this new standard on our consolidated financial position and results of operations and have not yet determined when to adopt and whether to apply the new standard retrospectively or prospectively to implementation costs incurred after the date of adoption.

In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820) Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which modifies the disclosure requirements of fair value measurements. ASU 2018-13 is effective for us beginning January 1, 2020. Certain disclosures are required to be applied on a retrospective basis and others on a prospective basis. We do not expect the adoption of this standard to impact our financial position or results of operations.

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Adoption of ASU No. 2016-02, Leases (Tables)

6 Months Ended

Jun. 30, 2019

Leases [Abstract]

Schedule of Practical Expedients

Upon adoption, we selected the following practical expedients:

Practical expedient package	We did not reassess whether any expired or existing contracts are, or contain, leases.
	We did not reassess the lease classification of any expired or existing leases.
	We did not reassess initial direct costs of any expired or existing leases.
Hindsight practical expedient	We did not elect to use the hindsight practical expedient which allows for the use of hindsight when determining lease term, including option periods, and impairment of operating assets.
Easement expedient	We elected to maintain the current accounting treatment of existing contracts and not reassess whether those contracts met the definition of a lease.
Combining lease and non-lease components expedient	We elected to account for lease and non-lease components as a single component.
Short-term lease expedient	We elected the short-term lease recognition exemption for all classes of underlying assets. Expense for short-term leases is recognized on a straight-line basis over the lease term. Leases with an initial term of 12 months or less and that do not include an option to purchase the underlying asset that is reasonably certain to be recognized are not recorded on the balance sheet.

Lease Cost

Lease Costs

(in thousands)	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Operating lease cost	$	776	$	1,587
Variable lease cost	473		796
Short-term lease cost	1,075		3,261
Total lease cost	$	2,324	$	5,644
Reported as:
Lease operating expense	$	1,031	$	3,326
General and administrative expense	1,293		2,318
Total lease cost	$	2,324	$	5,644

Maturities of Operating Lease Liabilities

Operating Lease Liability Maturities as of June 30, 2019

Fiscal year	(in thousands)
Remainder of 2019	$	1,470
2020	2,965
2021	2,942
2022	3,010
2023	2,718
Thereafter	12,647
Total lease payments	25,752
Less: imputed interest	(11,081		)
Present value of operating lease liabilities	$	14,671
Current portion of operating lease liabilities	$	938
Operating lease liabilities, net of current portion	13,733
Present value of operating lease liabilities	$	14,671

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Supplemental Cash Flow Information (Tables)

6 Months Ended

Jun. 30, 2019

Supplemental Cash Flow Information [Abstract]

Supplemental Disclosures To The Consolidated Statements Of Cash Flows

	Successor						Predecessor
(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Supplemental cash flow information:
Cash paid for interest	$	25,070		$	21,216		$	1,145
Cash paid for state income taxes, net of refunds	—			6			—
Non-cash investing and financing activities:
Increase in asset retirement obligations	634			877			—
Increase (decrease) in accruals or payables for capital expenditures	(91,639		)	(27,646		)	4,896
Distribution of non-STACK assets, net of liabilities	—			—			43,482

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Receivables (Tables)

6 Months Ended

Jun. 30, 2019

Receivables [Abstract]

Schedule of Accounts Receivable

Accounts Receivable

(in thousands)	June 30, 2019			December 31, 2018
Production sales	$	29,730		$	31,532
Joint interest billings	20,836			18,147
Pooling interest (1)	11,506			18,786
Allowance for doubtful accounts	(410		)	(95		)
Total accounts receivable, net	$	61,662		$	68,370

_________________

(1) Pooling interest relates to Oklahoma’s forced pooling process which permits mineral interest owners the option to participate in the drilling of proposed wells.  The pooling interest listed above represents unbilled costs for wells where the option remains pending.  Depending upon the mineral owner’s decision, these costs will be billed to them or added to oil and gas properties.

Related Party Receivables

(in thousands)	June 30, 2019			December 31, 2018
Related party receivables	$	23,037		$	33,316
Allowance for doubtful accounts	(9,888		)	(9,034		)
Related party receivables, net	13,149			24,282
Notes receivable from related parties	13,403			13,403
Allowance for doubtful accounts	(13,403		)	(13,403		)
Notes receivable from related parties, net	—			—
Total related party receivables, net	$	13,149		$	24,282

Management Services Agreement with High Mesa

(in thousands)	June 30, 2019
High Mesa related party receivable at December 31, 2018	$	10,066
Additions	894
Payments	(1,072		)
High Mesa related party receivable at June 30, 2019	9,888
Allowance for uncollectibility(1)	(9,888		)
Balance at June 30, 2019, net	$	—

_________________

(1) $9.0 million of the allowance was recognized during the 2018 Successor Period.

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Property And Equipment (Tables)

6 Months Ended

Jun. 30, 2019

Property, Plant and Equipment [Abstract]

Summary Of Property And Equipment

	Successor								Predecessor
(in thousands)	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
Oil and gas properties depletion	$	33,923	$	26,086	$	67,965	$	36,859	$	11,021
Other property and equipment depreciation	341		423		749		586		609
Total depletion and depreciation	$	34,264	$	26,509	$	68,714	$	37,445	$	11,630

(in thousands)	June 30, 2019			December 31, 2018
Oil and gas properties
Unproved properties	$	76,665		$	74,217
Proved oil and gas properties	2,196,605			2,110,346
Accumulated depletion and impairment	(1,489,191		)	(1,421,226		)
Proved oil and gas properties, net	707,414			689,120
Total oil and gas properties, net	784,079			763,337
Other property and equipment
Land	5,059			5,059
Fresh water wells	27,372			27,366
Produced water disposal system	3,590			3,608
Office furniture, equipment and vehicles	2,825			2,840
Accumulated depreciation	(1,475		)	(726		)
Other property and equipment, net	37,371			38,147
Total property and equipment, net	$	821,450		$	801,484

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Discontinued Operations (Tables)

6 Months Ended

Jun. 30, 2019

Disposed of by Sale

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Schedule Of Discontinued Operations

	Predecessor
(in thousands)	January 1, 2018 Through February 8, 2018
Revenue
Oil	$	1,617
Natural gas	1,023
Natural gas liquids	236
Other	16
Operating revenue	2,892
Loss on sale of assets	(1,923		)
Total revenue	969
Operating expenses
Lease operating	1,770
Transportation and marketing	83
Production taxes	167
Workovers	127
Depreciation, depletion and amortization	884
Impairment of assets	5,560
General and administrative	21
Total operating expenses	8,612
Other expense
Interest expense	(103		)
Loss from discontinued operations, net of tax	$	(7,746	)

	Predecessor
(in thousands)	January 1, 2018 Through February 8, 2018
Total operating cash flows of discontinued operations	$	2,974
Total investing cash flows of discontinued operations	(601		)

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Derivatives (Tables)

6 Months Ended

Jun. 30, 2019

Derivative [Line Items]

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

The following summarizes the fair value and classification of our derivatives:

	June 30, 2019
Balance sheet location	Gross fair value of assets		Gross liabilities offset against assets in the Balance Sheet			Net fair value of assets presented in the Balance Sheet
	(in thousands)
Derivatives, current assets	$	13,855	$	(9,128	)	$	4,727
Derivatives, long-term assets	11,977		(9,469		)	2,508
Total	$	25,832	$	(18,597	)	$	7,235

Balance sheet location	Gross fair value of liabilities		Gross assets offset against liabilities in the Balance Sheet			Net fair value of liabilities presented in the Balance Sheet
	(in thousands)
Derivatives, current liabilities	$	9,968	$	(9,128	)	$	840
Derivatives, long-term liabilities	9,658		(9,469		)	189
Total	$	19,626	$	(18,597	)	$	1,029

	December 31, 2018
Balance sheet location	Gross fair value of assets		Gross liabilities offset against assets in the Balance Sheet			Net fair value of assets presented in the Balance Sheet
	(in thousands)
Derivatives, current assets	$	22,512	$	(6,089	)	$	16,423
Derivatives, long-term assets	7,910		(4,963		)	2,947
Total	$	30,422	$	(11,052	)	$	19,370

Balance sheet location	Gross fair value of liabilities		Gross assets offset against liabilities in the Balance Sheet			Net fair value of liabilities presented in the Balance Sheet
	(in thousands)
Derivatives, current liabilities	$	7,799	$	(6,089	)	$	1,710
Derivatives, long-term liabilities	5,143		(4,963		)	180
Total	$	12,942	$	(11,052	)	$	1,890

Effect Of Derivative Instruments In The Consolidated Statements Of Operations

The following table summarizes the effect of our derivatives in the consolidated statements of operations (in thousands):

	Successor											Predecessor
Derivatives not designated as hedges	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018			Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Gain (loss) on derivatives -
Oil	$	5,134	$	(28,712	)	$	(16,535	)	$	(50,656	)	$	4,796
Natural gas	7,278		(507		)	5,170			(574		)	1,867
Total gain (loss) on derivatives	$	12,412	$	(29,219	)	$	(11,365	)	$	(51,230	)	$	6,663

Oil Derivative Contracts

Derivative [Line Items]

Open Derivative Contracts

	Remaining Volume	Weighted		Range
Settlement Period and Type of Contract	in bbls	Average		High		Low
2019
Price Swap Contracts	92,000	$	63.03	$	63.03	$	63.03
Collar Contracts
Short Call Options	1,361,600	66.31		75.20		56.50
Long Put Options	1,453,600	53.80		62.00		50.00
Short Put Options	1,453,600	42.72		52.00		37.50
2020
Collar Contracts
Short Call Options	1,017,600	63.95		73.80		59.55
Long Put Options	1,566,600	56.81		62.50		50.00
Short Put Options	1,566,600	42.81		50.00		37.50
2021
Collar Contracts
Short Call Options	279,750	63.51		63.75		63.35
Long Put Options	659,850	46.94		55.00		41.00
Short Put Options	279,750	43.00		43.00		43.00

Natural Gas Derivative Contract

Derivative [Line Items]

Open Derivative Contracts

	Remaining Volume	Weighted			Range
Settlement Period and Type of Contract	in MMBtu	Average			High			Low
2019
Price Swap Contracts	7,980,000	$	2.67		$	2.72		$	2.64
Basis Swap Contracts	9,680,000	(0.72		)	(0.49		)	(0.93		)
Collar Contracts
Short Call Options	1,525,000	3.19			3.20			3.17
Long Put Options	1,525,000	2.70			2.70			2.70
Short Put Options	1,525,000	2.20			2.20			2.20
2020
Price Swap Contracts	1,284,000	2.54			2.54			2.54
Basis Swap Contracts	910,000	(0.49		)	(0.49		)	(0.50		)
Collar Contracts
Short Call Options	3,874,500	3.19			3.69			2.77
Long Put Options	10,749,500	2.59			3.00			2.50
Short Put Options	9,696,000	2.10			2.50			2.00
2021
Collar Contracts
Short Call Options	540,000	3.25			3.25			3.25
Long Put Options	2,790,000	2.62			2.65			2.50
Short Put Options	2,250,000	2.15			2.15			2.15

Basis Swap Derivative Contract

Derivative [Line Items]

Natural Gas Basis Swap Contracts

We had the following basis swaps at June 30, 2019:

Total Gas Volumes in MMBtu(1) over Remaining Term	Reference Price 1 (1)	Reference Price 2 (1)	Period			Weighted Average Spread ($ per MMBtu)
460,000	OneOK	NYMEX Henry Hub	Jul '19	—	Dec '19	$	(0.93	)
7,990,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Jul '19	—	Dec '19	(0.70		)
910,000	Tex/OKL Panhandle Eastern Pipeline	NYMEX Henry Hub	Jan '20	—	Mar '20	(0.49		)
1,230,000	San Juan	NYMEX Henry Hub	Jul '19	—	Oct '19	(0.81		)

________________

(1) Represents short swaps that fix the basis differentials between OneOK, Tex/OKL Panhandle Eastern Pipeline (“PEPL”), San Juan and NYMEX Henry Hub.

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Accounts Payable And Accrued Liabilities (Tables)

6 Months Ended

Jun. 30, 2019

Payables and Accruals [Abstract]

Detail Of Accounts Payable And Accrued Liabilities

(in thousands)	June 30, 2019		December 31, 2018
Accounts payable	$	8,871	$	20,200
Accruals for capital expenditures	18,477		101,214
Revenue and royalties payable	39,232		46,870
Accruals for operating expenses	10,701		16,355
Accrued interest	5,642		1,784
Derivative settlements	743		109
Other	8,028		10,532
Total accrued liabilities	82,823		176,864
Accounts payable and accrued liabilities	$	91,694	$	197,064

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Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2019

Asset Retirement Obligation Disclosure [Abstract]

Summary Of Changes In Asset Retirement Obligations

	Successor						Predecessor
(in thousands)	Six Months Ended June 30, 2019			February 9, 2018 Through June 30, 2018			January 1, 2018 Through February 8, 2018
Balance, beginning of period	$	11,409		$	—		$	10,469
Liabilities assumed in Business Combination	—			5,998			—
Liabilities incurred	634			877			—
Liabilities settled	(162		)	(806		)	(63		)
Liabilities transferred in sale of properties	—			(20		)	—
Revisions to estimates	(9		)	665			63
Accretion expense	465			263			40
Balance, end of period	12,337			6,977			10,509
Less: Current portion	44			538			33
Long-term portion	$	12,293		$	6,439		$	10,476

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Debt (Tables)

6 Months Ended

Jun. 30, 2019

Debt Disclosure [Abstract]

Long-Term Debt, Net And Notes Payable To Founder

(in thousands)	June 30, 2019		December 31, 2018
Alta Mesa RBL	$	344,500	$	161,000
2024 Notes	500,000		500,000
Unamortized premium on 2024 Notes	26,662		29,123
Total debt, net	871,162		690,123
Less: Current portion	871,162		—
Long-term debt, net	$	—	$	690,123

Summary Of Future Maturities Of Long-Term Debt

Fiscal year	(in thousands)
2019	$	—
2020	—
2021	—
2022	—
2023	344,500
Thereafter	500,000
	$	844,500

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Significant Concentrations (Tables)

6 Months Ended

Jun. 30, 2019

Significant Concentrations [Abstract]

Schedule of Significant Concentrations

ARM also provides us with strategic advice, execution and reporting services with respect to our derivatives activities.

	Successor								Predecessor
(in thousands)	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
Revenue marketed by ARM on our behalf	$	7,703	$	70,601	$	91,534	$	107,944	$	28,757
Marketing and management fees paid to ARM	$	476	$	—	$	1,137	$	—	$	—
Fees paid to ARM for derivative services	218		209		411		283		66
Total fees paid to ARM	$	694	$	209	$	1,548	$	283	$	66

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Equity-Based Compensation (Successor) (Tables)

6 Months Ended

Jun. 30, 2019

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock compensation expense recognized

Stock compensation expense allocated to us by AMR pursuant to its equity-based compensation programs was as follows:

	Successor								Predecessor
(in thousands)	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		February 9, 2018 Through June 30, 2018		January 1, 2018 Through February 8, 2018
Stock options	$	744	$	1,606	$	1,535	$	2,628	$	—
Restricted stock awards	563		871		1,425		1,412		—
Performance-based restricted stock units	89		1,144		97		2,349		—
Total compensation expense	$	1,396	$	3,621	$	3,057	$	6,389	$	—

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Summary Of Significant Accounting Policies (Details) - USD ($)		12 Months Ended
	Aug. 13, 2019	Dec. 31, 2019	Jul. 31, 2019	Jun. 30, 2019	Apr. 01, 2019	Feb. 22, 2019	Dec. 31, 2018	Feb. 09, 2018
Summary Of Significant Accounting Policies [Line Items]
Capital program well costs				$ 3,000,000
2024 Notes								$ 533,600,000
2024 Notes
Summary Of Significant Accounting Policies [Line Items]
2024 Notes				$ 500,000,000			$ 500,000,000
Parent Company | Common Class A
Summary Of Significant Accounting Policies [Line Items]
Common stock par value (in dollars per share)						$ 1.00
Alta Mesa Credit Facility
Summary Of Significant Accounting Policies [Line Items]
Current borrowing capacity					$ 370,000,000
Subsequent Event | Alta Mesa Credit Facility
Summary Of Significant Accounting Policies [Line Items]
Current borrowing capacity	$ 200,000,000
Cash			$ 79,700,000
Amount exceeding borrowing base	162,400,000.0
Monthly payments	$ 32,500,000
Scenario, Forecast
Summary Of Significant Accounting Policies [Line Items]
Interest payment		$ 20,000,000

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Adoption of ASU No. 2016-02, Leases (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended		5 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2018	Jan. 01, 2019	Dec. 31, 2018
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease, right of use asset recognized	$ 7,871
Weighted-average remaining lease term (in years)	8 years 1 month 18 days
Weighted-average discount rate	14.10%
Lease payment under ASC 840, due 2019						$ 2,800
Lease payment under ASC 840, due 2020						2,900
Lease payment under ASC 840, due 2021						2,900
Lease payment under ASC 840, due 2022						3,100
Lease payment under ASC 840, due 2023						3,000
Lease payment under ASC 840, due thereafter						$ 12,200
Impairment loss	$ 6,500	$ 0	$ 0	$ 6,500
Accounting Standards Update 2016-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease, right of use asset recognized					$ 15,000

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Adoption of ASU No. 2016-02, Leases (Lease Costs) (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019
Lessee, Lease, Description [Line Items]
Operating lease cost	$ 776	$ 1,587
Variable lease cost	473	796
Short-term lease cost	1,075	3,261
Total lease cost	2,324	5,644
Lease operating expense
Lessee, Lease, Description [Line Items]
Total lease cost	1,031	3,326
General and administrative
Lessee, Lease, Description [Line Items]
Total lease cost	$ 1,293	$ 2,318

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Adoption of ASU No. 2016-02, Leases (Operating Lease Liability Maturities) (Details) $ in Thousands	Jun. 30, 2019 USD ($)
Leases [Abstract]
Remainder of 2019	$ 1,470
2020	2,965
2021	2,942
2022	3,010
2023	2,718
Thereafter	12,647
Total lease payments	25,752
Less: imputed interest	(11,081)
Present value of operating lease liability	14,671
Current portion of operating lease liabilities	938
Operating lease liabilities, net of current portion	13,733
Operating lease liability recognized	$ 14,671

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Supplemental Cash Flow Information (Supplemental Disclosures To The Consolidated Statements Of Cash Flows) (Details) - USD ($) $ in Thousands	1 Months Ended	5 Months Ended	6 Months Ended
	Feb. 08, 2018	Jun. 30, 2018	Jun. 30, 2019
Supplemental cash flow information:
Cash paid for interest		$ 21,216	$ 25,070
Cash paid for state income taxes, net of refunds		6	0
Non-cash investing and financing activities:
Increase in asset retirement obligations		877	634
Increase (decrease) in accruals or payables for capital expenditures		(27,646)	(91,639)
Distribution of non-STACK assets, net of liabilities		$ 0	$ 0
Predecessor
Supplemental cash flow information:
Cash paid for interest	$ 1,145
Cash paid for state income taxes, net of refunds	0
Non-cash investing and financing activities:
Increase in asset retirement obligations	0
Increase (decrease) in accruals or payables for capital expenditures	4,896
Distribution of non-STACK assets, net of liabilities	$ 43,482

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Receivables (Schedule of Accounts Receivable) (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Receivables [Abstract]
Production sales	$ 29,730	$ 31,532
Joint interest billings	20,836	18,147
Pooling interest	11,506	18,786
Allowance for doubtful accounts	(410)	(95)
Total related party receivables, net	$ 61,662	$ 68,370

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Receivables (Schedule of Related Party Receivables) (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Receivables [Abstract]
Related party receivables	$ 23,037	$ 33,316
Allowance for doubtful accounts	(9,888)	(9,034)
Related party receivables, net	13,149	24,282
Notes receivable from related parties	13,403	13,403
Allowance for doubtful accounts	(13,403)	(13,403)
Notes receivable from related parties, net	0	0
Total related party receivables, net	$ 13,149	$ 24,282

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Receivables Receivables (Narrative) (Details) - USD ($)	1 Months Ended	3 Months Ended	5 Months Ended	6 Months Ended	12 Months Ended
	Feb. 08, 2018	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Dec. 31, 2018	Sep. 29, 2017
Accounts, Notes, Loans and Financing Receivable [Line Items]
Notes receivable from related parties, net		$ 0		$ 0	$ 0
Related party receivables, net		13,149,000		13,149,000	24,282,000
Northwest Gas Processing
Accounts, Notes, Loans and Financing Receivable [Line Items]
Promissory note						$ 1,500,000
Debt Instrument, Interest Rate, Stated Percentage						8.00%
Notes receivable from related parties, net		1,700,000		1,700,000	1,700,000
Alta Mesa Resources
Accounts, Notes, Loans and Financing Receivable [Line Items]
Related party receivables		$ 8,500,000		8,500,000	3,300,000
High Mesa Agreement | Affiliated Entity
Accounts, Notes, Loans and Financing Receivable [Line Items]
Initial agreement term		180 days
Automatic renewal period		180 days
Notice period to terminate agreement		90 days
Management fee					10,000
Balance of note receivable		$ 9,900,000		9,900,000	10,100,000
Allowance for uncollectible accounts					9,000,000
Unamortized premium on 2024 Notes | High Mesa Services LLC
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance of note receivable		$ 11,700,000		$ 11,700,000	11,700,000
Debt Instrument, Interest Rate, Stated Percentage		8.00%		8.00%
Related party receivables, net		$ 8,500,000		$ 8,500,000
Kingfisher
Accounts, Notes, Loans and Financing Receivable [Line Items]
Transportation and marketing expense			$ 13,600,000	30,800,000
Related party receivables		$ 4,600,000		$ 4,600,000	11,200,000
Kingfisher | High Mesa Agreement
Accounts, Notes, Loans and Financing Receivable [Line Items]
Related party receivables					$ 8,700,000
Predecessor | Kingfisher
Accounts, Notes, Loans and Financing Receivable [Line Items]
Transportation and marketing expense	$ 3,100,000

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Receivables (Management Services Agreement with High Mesa) (Details) - USD ($) $ in Thousands	2 Months Ended	5 Months Ended	6 Months Ended
	Mar. 31, 2018	Jun. 30, 2018	Jun. 30, 2019	Dec. 31, 2018
Allowance for Doubtful Accounts Receivable [Roll Forward]
Related party receivables, beginning of period			$ 33,316
Related party receivables, end of period			23,037
Allowance for uncollectibility			(9,888)	$ (9,034)
Related party receivables, net			13,149	$ 24,282
Provision for uncollectible receivables		$ 0	1,177
High Mesa Agreement
Allowance for Doubtful Accounts Receivable [Roll Forward]
Related party receivables, beginning of period			10,066
Additions			894
Payments			(1,072)
Related party receivables, end of period			9,888
Allowance for uncollectibility			(9,888)
Related party receivables, net			$ 0
Provision for uncollectible receivables	$ 9,000

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Property And Equipment (Summary Of Property And Equipment) (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Unproved properties	$ 76,665	$ 74,217
Proved oil and gas properties	2,196,605	2,110,346
Accumulated depletion and impairment	(1,489,191)	(1,421,226)
Proved oil and gas properties, net	707,414	689,120
Total oil and gas properties, net	784,079	763,337
Land	5,059	5,059
Fresh water wells	27,372	27,366
Produced water disposal system	3,590	3,608
Office furniture, equipment and vehicles	2,825	2,840
Accumulated depreciation	(1,475)	(726)
Other property and equipment, net	37,371	38,147
Total property and equipment, net	$ 821,450	$ 801,484

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Property And Equipment (Depreciation and Depletion Expense) (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		5 Months Ended	6 Months Ended
	Feb. 08, 2018	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2019
Property, Plant and Equipment [Line Items]
Oil and gas properties depletion		$ 33,923	$ 26,086	$ 36,859	$ 67,965
Other property and equipment depreciation		341	423	586	749
Total depletion and depreciation		$ 34,264	$ 26,509	$ 37,445	$ 68,714
Predecessor
Property, Plant and Equipment [Line Items]
Oil and gas properties depletion	$ 11,021
Other property and equipment depreciation	609
Total depletion and depreciation	$ 11,630

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Discontinued Operations (Schedule Of Operations And Other Items Reclassified In Discontinued Operations) (Details) - USD ($) $ in Thousands	1 Months Ended	5 Months Ended	6 Months Ended
	Feb. 08, 2018	Jun. 30, 2018	Jun. 30, 2019
Operating expenses
Interest expense		$ 0	$ 0
Predecessor
Operating expenses
Interest expense	$ (103)
Predecessor | Weeks Island Field, Louisiana | Non Stack Assets | Disposed of by Sale
Revenue
Oil	1,617
Natural gas	1,023
Natural gas liquids	236
Other	16
Operating revenue	2,892
Loss on sale of assets	(1,923)
Total revenue	969
Operating expenses
Lease operating	1,770
Transportation and marketing	83
Production taxes	167
Workovers	127
Depreciation, depletion and amortization	884
Impairment of assets	5,560
General and administrative	21
Total operating expenses	8,612
Interest expense	(103)
Loss from discontinued operations, net of tax	$ (7,746)

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Discontinued Operations (Total Operating And Investing Cash Flows Of Discontinued Operations) (Details) - Predecessor - Weeks Island Field, Louisiana - Disposed of by Sale $ in Thousands	1 Months Ended
	Feb. 08, 2018 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total operating cash flows of discontinued operations	$ 2,974
Total investing cash flows of discontinued operations	$ (601)

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Derivatives (Fair Values Of Derivative Contracts) (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Gross fair value of assets	$ 25,832	$ 30,422
Gross liabilities offset against assets in the Balance Sheet	(18,597)	(11,052)
Net fair value of assets presented in the Balance Sheet	7,235	19,370
Gross fair value of liabilities	19,626	12,942
Gross assets offset against liabilities in the Balance Sheet	(18,597)	(11,052)
Net fair value of liabilities presented in the Balance Sheet	1,029	1,890
Derivatives, current assets
Derivatives, Fair Value [Line Items]
Gross fair value of assets	13,855	22,512
Gross liabilities offset against assets in the Balance Sheet	(9,128)	(6,089)
Net fair value of assets presented in the Balance Sheet	4,727	16,423
Derivatives, long-term assets
Derivatives, Fair Value [Line Items]
Gross fair value of assets	11,977	7,910
Gross liabilities offset against assets in the Balance Sheet	(9,469)	(4,963)
Net fair value of assets presented in the Balance Sheet	2,508	2,947
Derivatives, current liabilities
Derivatives, Fair Value [Line Items]
Gross fair value of liabilities	9,968	7,799
Gross assets offset against liabilities in the Balance Sheet	(9,128)	(6,089)
Net fair value of liabilities presented in the Balance Sheet	840	1,710
Derivatives, long-term liabilities
Derivatives, Fair Value [Line Items]
Gross fair value of liabilities	9,658	5,143
Gross assets offset against liabilities in the Balance Sheet	(9,469)	(4,963)
Net fair value of liabilities presented in the Balance Sheet	$ 189	$ 180

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Derivatives (Effect Of Derivative Instruments In The Consolidated Statements Of Operations) (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		5 Months Ended	6 Months Ended
	Feb. 08, 2018	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (loss) on derivative contracts		$ 12,412	$ (29,219)	$ (51,230)	$ (11,365)	$ (11,365)
Predecessor
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (loss) on derivative contracts	$ 6,663
Derivatives Not Designated As Hedging
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (loss) on derivative contracts		12,412	(29,219)	(51,230)	(11,365)
Derivatives Not Designated As Hedging | Oil
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (loss) on derivative contracts		5,134	(28,712)	(50,656)	(16,535)
Derivatives Not Designated As Hedging | Natural gas
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (loss) on derivative contracts		$ 7,278	$ (507)	$ (574)	$ 5,170
Derivatives Not Designated As Hedging | Predecessor
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (loss) on derivative contracts	6,663
Derivatives Not Designated As Hedging | Predecessor | Oil
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (loss) on derivative contracts	4,796
Derivatives Not Designated As Hedging | Predecessor | Natural gas
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (loss) on derivative contracts	$ 1,867

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Derivatives (Additional Information) (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Contracts To be Settled January 2019
Derivative [Line Items]
Derivative contracts	$ 1.4	$ 1.3

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Derivatives (Oil Derivative Contracts) (Details) - Oil Derivative Contracts	6 Months Ended
	Jun. 30, 2019 $ / bbl bbl
Price Swap Contracts | 2019
Derivative [Line Items]
Volume in Bbls | bbl	92,000
Weighted Average Swap Price (USD per unit)	63.03
Price Swap Contracts | 2019 | High
Derivative [Line Items]
Swap Price (USD per unit)	63.03
Price Swap Contracts | 2019 | Low
Derivative [Line Items]
Swap Price (USD per unit)	63.03
Short Call Options | 2019
Derivative [Line Items]
Volume in Bbls | bbl	1,361,600
Weighted Average Option Price (USD per unit)	66.31
Short Call Options | 2019 | High
Derivative [Line Items]
Option Price (USD per unit)	75.20
Short Call Options | 2019 | Low
Derivative [Line Items]
Option Price (USD per unit)	56.50
Short Call Options | 2020
Derivative [Line Items]
Volume in Bbls | bbl	1,017,600
Weighted Average Option Price (USD per unit)	63.95
Short Call Options | 2020 | High
Derivative [Line Items]
Option Price (USD per unit)	73.80
Short Call Options | 2020 | Low
Derivative [Line Items]
Option Price (USD per unit)	59.55
Short Call Options | 2021
Derivative [Line Items]
Volume in Bbls | bbl	279,750
Weighted Average Option Price (USD per unit)	63.51
Short Call Options | 2021 | High
Derivative [Line Items]
Option Price (USD per unit)	63.75
Short Call Options | 2021 | Low
Derivative [Line Items]
Option Price (USD per unit)	63.35
Long Put Options | 2019
Derivative [Line Items]
Volume in Bbls | bbl	1,453,600
Weighted Average Option Price (USD per unit)	53.80
Long Put Options | 2019 | High
Derivative [Line Items]
Option Price (USD per unit)	62.00
Long Put Options | 2019 | Low
Derivative [Line Items]
Option Price (USD per unit)	50.00
Long Put Options | 2020
Derivative [Line Items]
Volume in Bbls | bbl	1,566,600
Weighted Average Option Price (USD per unit)	56.81
Long Put Options | 2020 | High
Derivative [Line Items]
Option Price (USD per unit)	62.50
Long Put Options | 2020 | Low
Derivative [Line Items]
Option Price (USD per unit)	50.00
Long Put Options | 2021
Derivative [Line Items]
Volume in Bbls | bbl	659,850
Weighted Average Option Price (USD per unit)	46.94
Long Put Options | 2021 | High
Derivative [Line Items]
Option Price (USD per unit)	55.00
Long Put Options | 2021 | Low
Derivative [Line Items]
Option Price (USD per unit)	41.00
Short Put Options | 2019
Derivative [Line Items]
Volume in Bbls | bbl	1,453,600
Weighted Average Option Price (USD per unit)	42.72
Short Put Options | 2019 | High
Derivative [Line Items]
Option Price (USD per unit)	52.00
Short Put Options | 2019 | Low
Derivative [Line Items]
Option Price (USD per unit)	37.50
Short Put Options | 2020
Derivative [Line Items]
Volume in Bbls | bbl	1,566,600
Weighted Average Option Price (USD per unit)	42.81
Short Put Options | 2020 | High
Derivative [Line Items]
Option Price (USD per unit)	50.00
Short Put Options | 2020 | Low
Derivative [Line Items]
Option Price (USD per unit)	37.50
Short Put Options | 2021
Derivative [Line Items]
Volume in Bbls | bbl	279,750
Weighted Average Option Price (USD per unit)	43.00
Short Put Options | 2021 | High
Derivative [Line Items]
Option Price (USD per unit)	43.00
Short Put Options | 2021 | Low
Derivative [Line Items]
Option Price (USD per unit)	43.00

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Derivatives (Natural Gas Derivative Contracts) (Details) - Natural Gas Derivative Contract	6 Months Ended
	Jun. 30, 2019 MMBTU $ / MMBTU
2019 | Price Swap Contracts
Derivative [Line Items]
Volume in MMbtu | MMBTU	7,980,000
Weighted Average Swap Price (USD per unit)	2.67
2019 | Price Swap Contracts | High
Derivative [Line Items]
Swap Price (USD per unit)	2.72
2019 | Price Swap Contracts | Low
Derivative [Line Items]
Swap Price (USD per unit)	2.64
2019 | Basis Swap Contracts
Derivative [Line Items]
Volume in MMbtu | MMBTU	9,680,000
Weighted Average Swap Price (USD per unit)	(0.72)
2019 | Basis Swap Contracts | High
Derivative [Line Items]
Swap Price (USD per unit)	(0.49)
2019 | Basis Swap Contracts | Low
Derivative [Line Items]
Swap Price (USD per unit)	(0.93)
2019 | Short Call Options
Derivative [Line Items]
Volume in MMbtu | MMBTU	1,525,000
Weighted Average Option Price (USD per unit)	3.19
2019 | Short Call Options | High
Derivative [Line Items]
Option Price (USD per unit)	3.20
2019 | Short Call Options | Low
Derivative [Line Items]
Option Price (USD per unit)	3.17
2019 | Long Put Options
Derivative [Line Items]
Volume in MMbtu | MMBTU	1,525,000
Weighted Average Option Price (USD per unit)	2.70
2019 | Long Put Options | High
Derivative [Line Items]
Option Price (USD per unit)	2.70
2019 | Long Put Options | Low
Derivative [Line Items]
Option Price (USD per unit)	2.70
2019 | Short Put Options
Derivative [Line Items]
Volume in MMbtu | MMBTU	1,525,000
Weighted Average Option Price (USD per unit)	2.20
2019 | Short Put Options | High
Derivative [Line Items]
Option Price (USD per unit)	2.20
2019 | Short Put Options | Low
Derivative [Line Items]
Option Price (USD per unit)	2.20
2020 | Price Swap Contracts
Derivative [Line Items]
Volume in MMbtu | MMBTU	1,284,000
Weighted Average Swap Price (USD per unit)	2.54
2020 | Price Swap Contracts | High
Derivative [Line Items]
Swap Price (USD per unit)	2.54
2020 | Price Swap Contracts | Low
Derivative [Line Items]
Swap Price (USD per unit)	2.54
2020 | Basis Swap Contracts
Derivative [Line Items]
Volume in MMbtu | MMBTU	910,000
Weighted Average Swap Price (USD per unit)	(0.49)
2020 | Basis Swap Contracts | High
Derivative [Line Items]
Swap Price (USD per unit)	(0.49)
2020 | Basis Swap Contracts | Low
Derivative [Line Items]
Swap Price (USD per unit)	(0.50)
2020 | Short Call Options
Derivative [Line Items]
Volume in MMbtu | MMBTU	3,874,500
Weighted Average Option Price (USD per unit)	3.19
2020 | Short Call Options | High
Derivative [Line Items]
Option Price (USD per unit)	3.69
2020 | Short Call Options | Low
Derivative [Line Items]
Option Price (USD per unit)	2.77
2020 | Long Put Options
Derivative [Line Items]
Volume in MMbtu | MMBTU	10,749,500
Weighted Average Option Price (USD per unit)	2.59
2020 | Long Put Options | High
Derivative [Line Items]
Option Price (USD per unit)	3.00
2020 | Long Put Options | Low
Derivative [Line Items]
Option Price (USD per unit)	2.50
2020 | Short Put Options
Derivative [Line Items]
Volume in MMbtu | MMBTU	9,696,000
Weighted Average Option Price (USD per unit)	2.10
2020 | Short Put Options | High
Derivative [Line Items]
Option Price (USD per unit)	2.50
2020 | Short Put Options | Low
Derivative [Line Items]
Option Price (USD per unit)	2.00
2021 | Short Call Options
Derivative [Line Items]
Volume in MMbtu | MMBTU	540,000
Weighted Average Option Price (USD per unit)	3.25
2021 | Short Call Options | High
Derivative [Line Items]
Option Price (USD per unit)	3.25
2021 | Short Call Options | Low
Derivative [Line Items]
Option Price (USD per unit)	3.25
2021 | Long Put Options
Derivative [Line Items]
Volume in MMbtu | MMBTU	2,790,000
Weighted Average Option Price (USD per unit)	2.62
2021 | Long Put Options | High
Derivative [Line Items]
Option Price (USD per unit)	2.65
2021 | Long Put Options | Low
Derivative [Line Items]
Option Price (USD per unit)	2.50
2021 | Short Put Options
Derivative [Line Items]
Volume in MMbtu | MMBTU	2,250,000
Weighted Average Option Price (USD per unit)	2.15
2021 | Short Put Options | High
Derivative [Line Items]
Option Price (USD per unit)	2.15
2021 | Short Put Options | Low
Derivative [Line Items]
Option Price (USD per unit)	2.15

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Derivatives (Basis Swap Derivative Contracts) (Details) - Natural Gas Basis Swap Derivative Contracts	6 Months Ended
	Jun. 30, 2019 MMBTU $ / MMBTU
Jul 19 - Dec 19
Derivative [Line Items]
Volume in MMbtu | MMBTU	460,000
Weighted average spread | $ / MMBTU	(0.93)
Jan 19 - Dec 19
Derivative [Line Items]
Volume in MMbtu | MMBTU	7,990,000
Weighted average spread | $ / MMBTU	(0.70)
Jan 20 - Mar 20
Derivative [Line Items]
Volume in MMbtu | MMBTU	910,000
Weighted average spread | $ / MMBTU	(0.49)
Jan 19 - Oct 19
Derivative [Line Items]
Volume in MMbtu | MMBTU	1,230,000
Weighted average spread | $ / MMBTU	(0.81)

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Accounts Payable And Accrued Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Payables and Accruals [Abstract]
Accounts payable	$ 8,871	$ 20,200
Accruals for capital expenditures	18,477	101,214
Revenue and royalties payable	39,232	46,870
Accruals for operating expenses	10,701	16,355
Accrued interest	5,642	1,784
Derivative settlements	743	109
Other	8,028	10,532
Total accrued liabilities	82,823	176,864
Accounts payable and accrued liabilities	$ 91,694	$ 197,064

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Asset Retirement Obligations (Details) - USD ($) $ in Thousands	1 Months Ended	5 Months Ended	6 Months Ended
	Feb. 08, 2018	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2019	Dec. 31, 2018	Jun. 30, 2018	Feb. 08, 2018
Asset Retirement Obligation [Line Items]
Balance, beginning of period		$ 0	$ 11,409
Liabilities assumed in Business Combination		5,998	0
Liabilities incurred		877	634
Liabilities settled		(806)	(162)
Liabilities transferred in sale of properties		(20)	0
Revisions to estimates		665	(9)
Accretion expense		263	465
Balance, end of period		0	$ 11,409	$ 12,337	$ 11,409	$ 6,977	$ 0
Less: Current portion				44	2,079	538
Long-term portion				$ 12,293	$ 9,330	$ 6,439
Predecessor
Asset Retirement Obligation [Line Items]
Balance, beginning of period	$ 10,469	10,509
Liabilities assumed in Business Combination	0
Liabilities incurred	0
Liabilities settled	(63)
Liabilities transferred in sale of properties	0
Revisions to estimates	63
Accretion expense	40
Balance, end of period	$ 10,469	$ 10,509					10,509
Less: Current portion							33
Long-term portion							$ 10,476

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Debt (Schedule of Long-Term Debt, Net) (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018	Feb. 09, 2018
Debt Instrument [Line Items]
2024 Notes			$ 533,600
Total debt, net	$ 871,162	$ 690,123
Less: Current portion	871,162	0
Long-term debt, net	0	690,123
2024 Notes
Debt Instrument [Line Items]
2024 Notes	500,000	500,000
Unamortized premium on 2024 Notes
Debt Instrument [Line Items]
Unamortized premium on 2024 Notes	26,662	29,123
Alta Mesa RBL
Debt Instrument [Line Items]
Alta Mesa RBL	20,200
Alta Mesa RBL | Alta Mesa RBL
Debt Instrument [Line Items]
Alta Mesa RBL	$ 344,500	$ 161,000

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Debt (Narrative) (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2019 USD ($)	Aug. 13, 2019 USD ($)	Apr. 01, 2019 USD ($)	Dec. 31, 2018 USD ($)	Feb. 09, 2018 USD ($)
Debt Instrument [Line Items]
2024 Notes					$ 533,600
2024 Notes
Debt Instrument [Line Items]
2024 Notes	$ 500,000			$ 500,000
Alta Mesa Credit Facility
Debt Instrument [Line Items]
Debt covenant, current ratio, minimum required	1.0
Maximum leverage ratio	4
Current borrowing capacity			$ 370,000
Alta Mesa RBL
Debt Instrument [Line Items]
Alta Mesa RBL	$ 20,200
Remaining borrowing capacity	5,300
Alta Mesa RBL | 2024 Notes
Debt Instrument [Line Items]
Notes Payable, Fair Value Disclosure	$ 193,800
Subsequent Event | Alta Mesa Credit Facility
Debt Instrument [Line Items]
Current borrowing capacity		$ 200,000

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Debt (Summary Of Future Maturities Of Long-Term Debt) (Details) $ in Thousands	Jun. 30, 2019 USD ($)
Summary of future maturities of long-term debt
2019	$ 0
2020	0
2021	0
2022	0
2023	344,500
Thereafter	500,000
Total long-term debt	$ 844,500

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Significant Concentrations (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		5 Months Ended	6 Months Ended
	Feb. 08, 2018	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Concentration Risk [Line Items]
Revenues		$ 126,045	$ 66,459	$ 100,344		$ 220,348
AEM
Concentration Risk [Line Items]
Revenues		7,703	70,601	107,944	$ 91,534
Fees paid		218	209	283	411
Total fees paid to ARM		694	209	283	1,548
Accounts receivable		200			200		$ 38,400
Marketing fees | AEM
Concentration Risk [Line Items]
Fees paid		$ 476	$ 0	$ 0	$ 1,137
Predecessor
Concentration Risk [Line Items]
Revenues	$ 47,639
Predecessor | AEM
Concentration Risk [Line Items]
Revenues	28,757
Fees paid	66
Total fees paid to ARM	66
Predecessor | Marketing fees | AEM
Concentration Risk [Line Items]
Fees paid	$ 0

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Equity-Based Compensation (Successor) (Stock Compensation Expense) (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		5 Months Ended	6 Months Ended
	Feb. 08, 2018	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense		$ 1,396	$ 3,621	$ 6,389	$ 3,057
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense		744	1,606	2,628	1,535
Restricted stock awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense		563	871	1,412	1,425
Performance-based restricted stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense		$ 89	$ 1,144	$ 2,349	$ 97
Predecessor
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 0
Predecessor | Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	0
Predecessor | Restricted stock awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	0
Predecessor | Performance-based restricted stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 0

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Equity-Based Compensation (Successor) (Narrative) (Details) - Performance-based restricted stock units - $ / shares	6 Months Ended	11 Months Ended
	Jun. 30, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		3 years
Awards deemed granted (in shares)	595,417
Fair value of tranche granted (in USD per share)	$ 0.27
Tranche one
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rate		20.00%
Tranche two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rate		30.00%
Tranche three
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rate		50.00%
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of shares that may be earned		0.00%
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of shares that may be earned		200.00%

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Related Party Transactions (Details)			2 Months Ended	3 Months Ended	12 Months Ended
	Feb. 08, 2018 USD ($)	Dec. 31, 2016	Mar. 31, 2018 USD ($)	Jun. 30, 2019 USD ($) well	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Jan. 13, 2016 well
Related Party Transaction [Line Items]
Advances from related party				$ 4,003,000	$ 9,822,000
BCE
Related Party Transaction [Line Items]
Advances from related party				4,000,000	9,800,000
Land consulting services | Vice President | David Murrell, VP of Land and Business Development
Related Party Transaction [Line Items]
Total fees paid to ARM			$ 83,000
Land consulting services | Predecessor | Vice President | David Murrell, VP of Land and Business Development
Related Party Transaction [Line Items]
Total fees paid to ARM	$ 28,000
Compensation to related party | Vice President | David Mcclure Vp of Facilities and Infrastructure
Related Party Transaction [Line Items]
Total compensation			$ 929,428	768,860
Compensation to related party | Predecessor | Vice President | David Mcclure Vp of Facilities and Infrastructure
Related Party Transaction [Line Items]
Total compensation					28,874
KFM | Affiliated Entity
Related Party Transaction [Line Items]
Advances from related party					2,900,000
AMR | Affiliated Entity
Related Party Transaction [Line Items]
Advances from related party					$ 500,000
Joint Development Agreement
Related Party Transaction [Line Items]
Number of wells to be drilled in three tranches | well							60
Number of additional wells to be drilled | well							20
Reduced interest (percent)		12.50%
Internal rate of return		25.00%
Joint Development Agreement | BCE
Related Party Transaction [Line Items]
Percent committed to fund		100.00%
Drilling and completion costs (maximum)						$ 3,200,000
Working interest received (percent)		80.00%
Reduced interest (percent)		20.00%
Internal rate of return		15.00%
Advances from related party				$ 39,500,000
Number of wells drilled | well				61