Amplify Energy Corp. - Quarter Report: 2019 June (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 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

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

For the transition period from to .

Commission File Number: 001-35512

MIDSTATES PETROLEUM COMPANY, INC.

(Exact name of registrant as specified in its charter)

Delaware		45-3691816
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

321 South Boston Avenue, Suite 1000
Tulsa, Oklahoma		74103
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (918) 947-8550

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

Title of each class		Trading Symbol		Name of each exchange on which registered
Common stock, $0.01 par value		MPO		New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

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 o

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 o	Accelerated filer x
Non-accelerated filer o	Smaller reporting company x
	Emerging growth company o

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. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

The number of shares outstanding of our stock at August 1, 2019 is shown below:

Class		Number of shares outstanding
Common stock, $0.01 par value		20,415,005

DOCUMENTS INCORPORATED BY REFERENCE

None.

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MIDSTATES PETROLEUM COMPANY, INC.

QUARTERLY REPORT ON

FORM 10-Q

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2019

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		Page

Glossary of Oil and Natural Gas Terms		3

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements
Condensed Consolidated Balance Sheets at June 30, 2019 and December 31, 2018 (unaudited)		4
Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2019 and 2018 (unaudited)		5
Condensed Consolidated Statements of Changes in Stockholders’ Equity for the Three and Six Months Ended June 30, 2019 and 2018 (unaudited)		6
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2019 and 2018 (unaudited)		7

Notes to the Unaudited Interim Condensed Consolidated Financial Statements		8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		26

Item 3. Quantitative and Qualitative Disclosures About Market Risk		38

Item 4. Controls and Procedures		39

PART II — OTHER INFORMATION

Item 1. Legal Proceedings		40

Item 1A. Risk Factors		40

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		40

Item 3. Defaults Upon Senior Securities		40

Item 4. Mine Safety Disclosures		40

Item 5. Other Information		40

Item 6. Exhibits		40

EXHIBIT INDEX		41

SIGNATURES		42

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GLOSSARY OF OIL AND NATURAL GAS TERMS

Bbl: One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to oil, condensate or natural gas liquids.

Boe: Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

Boe/day: Barrels of oil equivalent per day.

Completion: The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Dry hole: A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production do not exceed production expenses and taxes.

Exploratory well: A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir.

MMBtu: One million British thermal units.

NYMEX: The New York Mercantile Exchange.

Proved reserves: Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to drill or operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Reasonable certainty: A high degree of confidence.

Recompletion: The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish, re-establishing, or increase existing production.

Reserves: Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible as of a given date by application of development projects to known accumulations.

Reservoir: A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Spud or Spudding: The commencement of drilling operations of a new well.

Wellbore: The hole drilled by the bit that is equipped for oil or 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 oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on a cash, penalty, or carried basis.

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PART I — FINANCIAL INFORMATION

MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands, except share amounts)

	June 30, 2019			December 31, 2018
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	4,797		$	11,341
Accounts receivable:
Oil and gas sales	11,920			22,165
Joint interest billing	2,099			2,474
Other	340			1,374
Commodity derivative contracts	1,659			6,940
Other current assets	1,909			1,684
Total current assets	22,724			45,978
PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of full-cost accounting
Proved properties	827,638			809,272
Unproved properties not being amortized	1,912			4,050
Other property and equipment	6,280			6,345
Less accumulated depreciation, depletion, amortization and impairment	(331,904		)	(266,198		)
Net property and equipment	503,926			553,469
OTHER NONCURRENT ASSETS
Commodity derivative contracts	108			791
Right-of-use lease assets	4,437			—
Other noncurrent assets	5,435			5,257
Total other noncurrent assets	9,980			6,048
TOTAL	$	536,630		$	605,495
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	4,061		$	6,511
Accrued liabilities	20,649			25,521
Commodity derivative contracts	329			—
Lease liabilities	1,180			—
Total current liabilities	26,219			32,032
LONG-TERM LIABILITIES:
Asset retirement obligations	8,404			8,087
Commodity derivative contracts	—			80
Long-term debt	60,559			23,059
Long-term lease liabilities	3,887			—
Other long-term liabilities	—			560
Total long-term liabilities	72,850			31,786

COMMITMENTS AND CONTINGENCIES (Note 15)

STOCKHOLDERS’ EQUITY:
Preferred stock, $0.01 par value, 50,000,000 shares authorized; no shares issued or outstanding at June 30, 2019 and December 31, 2018	—			—
Warrants, 6,979,609 and 6,625,554 warrants outstanding at June 30, 2019 and December 31, 2018	37,329			37,329
Common stock, $0.01 par value, 250,000,000 shares authorized; 20,620,866 shares issued and 20,415,005 shares outstanding at June 30, 2019; 25,520,170 shares issued and 25,345,981 shares outstanding at December 31, 2018	206			255
Treasury stock	(2,723		)	(2,455		)
Additional paid-in-capital	482,867			531,911
Retained deficit	(80,118		)	(25,363		)
Total stockholders’ equity	437,561			541,677
TOTAL	$	536,630		$	605,495

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

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MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share amounts)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
REVENUES:
Oil sales	$	14,554		$	34,202		$	30,881		$	66,616
Natural gas liquids sales	4,976			11,893			11,192			22,931
Natural gas sales	3,168			6,782			9,778			15,119
Other revenue	542			795			1,230			1,850
Total revenues from contracts with customers	23,240			53,672			53,081			106,516
Gains (losses) on commodity derivative contracts—net	2,541			(11,348		)	(5,191		)	(15,287		)
Total revenues	25,781			42,324			47,890			91,229
EXPENSES:
Lease operating and workover	9,911			16,952			18,901			31,760
Gathering and transportation	63			67			82			124
Severance and other taxes	1,572			2,776			3,505			5,638
Asset retirement accretion	160			250			317			547
Depreciation, depletion, and amortization	10,873			16,484			22,667			31,697
Impairment in carrying value of oil and gas properties	33,557			—			43,210			—
General and administrative	5,238			5,190			11,676			15,047
Advisory fees	—			850			—			850
Total expenses	61,374			42,569			100,358			85,663
OPERATING INCOME (LOSS)	(35,593		)	(245		)	(52,468		)	5,566
OTHER EXPENSE:
Interest income	4			5			9			24
Interest expense—net of amounts capitalized	(1,359		)	(1,302		)	(2,296		)	(3,129		)
Total other expense	(1,355		)	(1,297		)	(2,287		)	(3,105		)
INCOME (LOSS) BEFORE TAXES	(36,948		)	(1,542		)	(54,755		)	2,461
Income tax expense	—			—			—			—
NET INCOME (LOSS)	$	(36,948	)	$	(1,542	)	$	(54,755	)	$	2,461
Participating securities—non-vested restricted stock	—			—			—			(68		)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(36,948	)	$	(1,542	)	$	(54,755	)	$	2,393
Basic and diluted net income (loss) per share attributable to common shareholders	$	(1.80	)	$	(0.06	)	$	(2.53	)	$	0.09
Basic and diluted weighted average number of common shares outstanding (Note 13)	20,512			25,332			21,668			25,316

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

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MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

(In thousands)

	Series A Preferred Stock		Common Stock			Warrants		Treasury Stock			Additional Paid-in-Capital			Retained Deficit			Total Stockholders’ Equity
Balance as of December 31, 2018	$	—	$	255		$	37,329	$	(2,455	)	$	531,911		$	(25,363	)	$	541,677
Share-based compensation	—		1			—		—			(60		)	—			(59		)
Acquisition of treasury stock	—		—			—		(50,262		)	—			—			(50,262		)
Net loss	—		—			—		—			—			(17,807		)	(17,807		)
Retirement of treasury stock	—		(50		)	—		50,000			(49,950		)	—			—
Balance as of March 31, 2019	$	—	$	206		$	37,329	$	(2,717	)	$	481,901		$	(43,170	)	$	473,549
Share-based compensation	—		—			—		—			966			—			966
Acquisition of treasury stock	—		—			—		(6		)	—			—			(6		)
Net loss	—		—			—		—			—			(36,948		)	(36,948		)
Balance as of June 30, 2019	$	—	$	206		$	37,329	$	(2,723	)	$	482,867		$	(80,118	)	$	437,561

	Series A Preferred Stock		Common Stock		Warrants		Treasury Stock			Additional Paid-in-Capital		Retained Deficit			Total Stockholders’ Equity
Balance as of December 31, 2017	$	—	$	253	$	37,329	$	(1,603	)	$	524,755	$	(75,147	)	$	485,587
Share-based compensation	—		1		—		—			2,795		—			2,796
Acquisition of treasury stock	—		—		—		(459		)	—		—			(459		)
Net income	—		—		—		—			—		4,003			4,003
Balance as of March 31, 2018	$	—	$	254	$	37,329	$	(2,062	)	$	527,550	$	(71,144	)	$	491,927
Share-based compensation	—		—		—		—			1,625		—			1,625
Acquisition of treasury stock	—		—		—		(19		)	—		—			(19		)
Net loss	—		—		—		—			—		(1,542		)	(1,542		)
Balance as of June 30, 2018	$	—	$	254	$	37,329	$	(2,081	)	$	529,175	$	(72,686	)	$	491,991

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

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MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	For the Six Months Ended June 30,
	2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(54,755	)	$	2,461
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Losses on commodity derivative contracts—net	5,191			15,287
Net cash received (paid) for commodity derivative contracts not designated as hedging instruments	1,022			(3,677		)
Asset retirement accretion	317			547
Depreciation, depletion, and amortization	22,667			31,697
Impairment in carrying value of oil and gas properties	43,210			—
Share-based compensation, net of amounts capitalized to oil and gas properties	1,880			3,425
Amortization of deferred financing costs	348			216
Change in operating assets and liabilities:
Accounts receivable—oil and gas sales	7,670			1,437
Accounts receivable—JIB and other	1,834			(1,713		)
Other current and noncurrent assets	(750		)	(754		)
Accounts payable	1,487			2,301
Accrued liabilities	(4,803		)	(1,921		)
Other	—			(14		)
Net cash provided by operating activities	$	25,318		$	49,292
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment	$	(19,094	)	$	(65,843	)
Proceeds from the sale of oil and gas properties	—			54,432
Proceeds from the sale of oil and gas equipment	—			355
Net cash used in investing activities	$	(19,094	)	$	(11,056	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of revolving credit facility	$	(3,000	)	$	(100,000	)
Proceeds from revolving credit facility	40,500			—
Repurchase of restricted stock for tax withholdings	(268		)	(478		)
Common stock repurchased and retired	(50,000		)	—
Net cash used in financing activities	$	(12,768	)	$	(100,478	)
NET DECREASE IN CASH AND CASH EQUIVALENTS	$	(6,544	)	$	(62,242	)
Cash and cash equivalents, beginning of period	$	11,341		$	68,498
Cash and cash equivalents, end of period	$	4,797		$	6,256

SUPPLEMENTAL INFORMATION:
Non-cash transactions — investments in property and equipment accrued — not paid	$	4,712		$	23,219
Cash paid for interest, net of capitalized interest of $0.1 million and $0.2 million, respectively	$	1,885		$	3,010
Right-of-use assets obtained in exchange for operating lease liabilities	$	4,857		$	—

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

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Interim Condensed Consolidated Financial Statements

1. Organization and Business

Midstates Petroleum Company, Inc. engages in the business of exploring and drilling for, and the production of, oil, natural gas liquids (“NGLs”) and natural gas. Midstates Petroleum Company, Inc. was incorporated pursuant to the laws of the State of Delaware on October 25, 2011 to become a holding company for Midstates Petroleum Company LLC (“Midstates Sub”). The terms “Company,” “we,” “us,” “our,” and similar terms refer to Midstates Petroleum Company, Inc. and its subsidiary.

The Company currently conducts oil and gas operations and owns and operates oil and natural gas properties in Oklahoma. The Company operates nearly all of its oil and natural gas properties. The Company’s management evaluates performance based on one reportable segment as all of its operations are located in the United States and, therefore, it maintains one cost center.

2. Summary of Significant Accounting Policies

Basis of Presentation

These unaudited interim condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, these financial statements do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“US GAAP”) for complete consolidated financial statements, and should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2018, included in the Company’s Annual Report on Form 10-K as filed with the SEC on March 14, 2019.

All intercompany transactions have been eliminated in consolidation. In the opinion of the Company’s management, the accompanying unaudited interim condensed consolidated financial statements include all adjustments, consisting of normal recurring adjustments, necessary to fairly present the financial position as of, and the results of operations for, all periods presented. In preparing the accompanying unaudited interim condensed consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the unaudited interim condensed consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

Definitive Merger Agreement

On May 6, 2019, the Company entered into a definitive merger agreement (“Merger Agreement”) pursuant to which Amplify Energy Corp. (“Amplify”) will merge with a subsidiary of the Company in an all-stock merger-of-equals. Under the terms of the Merger Agreement, Amplify stockholders will receive 0.933 shares of newly issued Company common stock for each Amplify share of common stock. The merger is expected to close on August 6, 2019, at which time Amplify and the Company’s stockholders will each own 50% of the outstanding shares of the combined entity.

The transaction is subject to the terms and conditions set forth in the Merger Agreement, including holders of a majority of the Company’s stock present at the special meeting having voted in favor of the stock issuance, holders of a majority of Amplify stock having voted in favor of the merger, the waiting period under the U.S. Hart-Scott-Rodino Act having expired or been terminated early, the Company’s stock being issued to Amplify stockholders in connection with the merger being listed on the NYSE and other customary conditions. All such conditions were satisfied as of August 5, 2019.

The transactions contemplated by the Merger Agreement will be treated as a “change in control” as of the effective date for purposes of all Parent Benefit Plans (as defined in the Merger Agreement), including the Parent Stock Plans (as defined in the Merger Agreement) and all applicable employment agreements in effect prior to the effective date to which any employee of the Company is a party. The Company has agreed to satisfy promptly all applicable severance, retention and change in control payments and benefits owing to its employees, directors and other service providers under the Parent Benefit Plans. Without limiting the foregoing, (i) with respect to any employee of the Company whose employment is terminated without “cause” (as such term is defined in the applicable Parent Benefit Plan, but also including certain employees who are deemed to be terminated without cause pursuant to the Merger Agreement) on or within one year after the closing of the merger, (A) all Parent Stock Options (as defined in the Merger Agreement) held by such employee shall become fully vested, (B) all Parent RSUs (as defined in the Merger Agreement) held by such employee shall become fully vested and shall be settled promptly upon termination, (C) all Parent PSUs (as defined in the Merger Agreement) that are subject to the achievement of the Company’s specific stock price levels shall be deemed earned at the level specified in the applicable award agreement and shall become vested and settled promptly upon termination, (D) all Parent PSUs that are not described in the foregoing clause (C) shall be deemed earned at the target level of such award and shall become vested and settled promptly upon termination, and (E) all cash amounts pursuant to the “Share Buyback Equalization Program” approved by the board of directors of the Company on December 21, 2018 (the “Equalization Program”) that are owing to such employee(s) shall be paid

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promptly upon termination, (ii) all Parent RSUs held by members of the board of directors shall become fully vested and shall be settled promptly upon the closing of the merger, and (iii) all cash amounts pursuant to the Equalization Program that are owing to non-employee directors of the Company shall be paid promptly upon the closing of the merger.

The Company estimates that between 500,000 and 800,000 unvested stock awards (including stock options) will vest upon closing and between $8.5 million to $11.5 million in severance payments will be made. The number of unvested stock awards and severance payments are estimated and the final amount has not yet been determined.

Recent Accounting Pronouncements Adopted During the Period

In July 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2017-11, “Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480), and Derivatives and Hedging (Topic 815)” (“ASU 2017-11”). ASU 2017-11 changes the classification analysis of certain equity-linked financial instruments (or embedded features) with down round features. The amendments require entities that present earnings per share (“EPS”) in accordance with Topic 260 to recognize the effect of the down round feature when triggered with the effect treated as a dividend and as a reduction of income available to common shareholders in basic EPS. The new standard is effective for the Company for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The adoption of ASU 2017-11 did not have a material impact on its financial position, results of operations or cash flows.

In June 2018, the FASB issued Accounting Standards Update 2018-07, “Compensation - Stock Compensation (Topic 718) — Improvements to Nonemployee Share-Based Payment Accounting” (“ASU 2018-07”). ASU 2018-07 expands the scope of Topic 718 to include share-based payments issued to non-employees for goods and services. Consequently, the accounting for share-based payments to non-employees and employees will be substantially aligned. The new standard is effective for the Company for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The adoption of ASU 2018-07 did not have a material impact on its financial position, results of operations or cash flows.

In February 2016, the FASB issued Accounting Standards Update 2016-02, “Leases (Topic 842)” (“ASU 2016-02”). ASU 2016-02 establishes a right-of-use (“ROU”) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. The Company adopted ASU 2016-02 using the modified retrospective transition approach. See “—Note 3. Impact of ASC 842 Adoption” below for further details.

Recent Accounting Pronouncements Issued But Not Yet Adopted

In June 2016, the FASB issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (“ASU 2016-13”). ASU 2016-13 replaces the incurred loss model with an expected loss model, which is referred to as the current expected credit loss (“CECL”) model. The CECL model is applicable to the measurement of credit losses on financial assets measured at amortized cost, including but not limited to trade receivables. ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. The Company is still performing its evaluation of ASU 2016-13, but does not believe it will have a material impact on its consolidated financial statements at this time.

3. Impact of ASC 842 Adoption

In February 2016, the FASB issued ASU 2016-02, which establishes a ROU model that requires a lessee to record a ROU asset and lease liability on the balance sheet for all leases with terms longer than 12 months. All leases create an asset and a liability for the lessee and therefore recognition of those lease assets and lease liabilities is required by ASU 2016-02. When measuring lease assets and liabilities, payments to be made for optional extension periods should be included if the lessee is reasonably certain to exercise the option. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. ASU 2016-02 does not impact the accounting or financial presentation of mineral leases and does not apply to leases to explore for or use oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained.

In January 2018, the FASB issued ASU 2018-01, “Leases (Topic 842)-Land Easement Practical Expedient for Transition to Topic 842” (“ASU 2018-01”). ASU 2018-01 permits an entity to elect an optional transition practical expedient to not evaluate land easements that exist or expired prior to a company’s adoption of ASU 2016-02 and that were not accounted for as leases under previous lease guidance. Additionally, in July 2018, the FASB issued ASU 2018-11, “Leases (Topic 842): Targeted Improvements” (“ASU 2018-11”), which included the option to implement the standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings, as opposed to the modified retrospective transition method required when ASU 2016-02 was issued. The new standard was effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years.

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The Company has analyzed and categorized its contracts to determine if they meet the definition of a lease under ASU 2016-02 and has adopted the new standard using the simplified transition method described in ASU 2018-11 as of January 1, 2019. Consequently, financial information will not be updated, and the disclosures required under the new standard will not be provided for the dates and periods before January 1, 2019. Additionally, the Company has elected the package of practical expedients within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases or (iii) initial direct costs for any existing leases, but have not elected the practical expedient of hindsight when determining the lease term of existing contracts at the effective date. The Company also elected the practical expedient under ASU 2018-01 and has not evaluated existing or expired land easements not previously accounted for as leases prior to the effective date. The new standard also provides practical expedients for an entity’s ongoing accounting. The Company elected the short-term lease recognition exemption for all leases that qualify. The Company also elected the practical expedient to not separate lease and non-lease components for the majority of classes of underlying assets.

Through its implementation process, the Company evaluated each of its lease arrangements and enhanced its systems to track and calculate additional information required upon adoption of this standard. The standard had an impact on the Company’s unaudited interim condensed consolidated balance sheets as of June 30, 2019, with the primary change relating to the recognition of ROU assets and lease liabilities for operating leases. Adoption of the new lease standard had an immaterial impact to the Company’s unaudited interim condensed consolidated statement of operations and cash provided from or used in operating, investing or financing activities in its unaudited interim condensed consolidated statements of cash flows for the periods presented. Further discussion of the Company’s accounting for lease arrangements under ASC 842 is included below.

Leases

The Company determines if an arrangement is a lease at inception of the arrangement. To the extent that it is determined an arrangement represents a lease, the Company classifies that lease as an operating lease or a finance lease. The Company capitalizes operating and finance leases on its unaudited interim condensed consolidated balance sheets through a ROU asset and a corresponding lease liability. ROU assets represent the Company’s right to use an underlying asset for the lease term, and lease liabilities represent the Company’s obligation to make lease payments arising from the lease.

Operating leases are included in ROU lease assets, and lease liabilities in the unaudited interim condensed consolidated balance sheets at June 30, 2019. ROU lease assets and lease liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. The ROU lease asset also includes any lease payments made to the lessor prior to lease commencement, less any lease incentives, and initial direct costs incurred. Lease expense for operating lease payments are recognized on a straight-line basis over the lease term.

As of June 30, 2019, the Company had no leases classified as finance leases.

Nature of Leases

In support of the Company’s operations, it leases certain office space, field offices, office equipment, compressors, other production equipment and fleet vehicles under cancelable and non-cancelable contracts. A more detailed description of material lease types is included below.

Corporate and Field Offices

The Company enters into long-term contracts to lease corporate and field office space in support of operations. These contracts are generally structured with an initial non-cancelable term of three to five years. To the extent that corporate and field office contracts include renewal options, the Company evaluates whether it is reasonably certain to exercise those options on a contract by contract basis based on expected future office space needs, market rental rates, drilling plans and other factors. The Company has further determined that its current corporate and field office leases represent operating leases.

Compressors

The Company rents compressors from third-parties in order to facilitate the downstream movement of its production to market. Compressor arrangements are typically structured with a non-cancelable primary term of one to twenty-four months and often continue thereafter on a month-to-month basis subject to termination by either party with thirty-days notice. The Company has concluded that its compressor rental agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease without incurring a significant penalty. As a result, enforceable rights and obligations do not exist under the rental agreement subsequent to the primary term.

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To the extent that compressor rental arrangements have a primary term of twelve-months or less, the Company has elected to apply the practical expedient for short-term leases. For those short-term compressor contracts, the Company does not apply the lease recognition requirements, and recognizes lease payments related to these arrangements in profit or loss on a straight-line basis over the lease term. Refer to “Practical Expedients & Accounting Policy Elections” below for additional detail.

Other Production Equipment

The Company rents other production equipment from third-party vendors to be used in its production operations. These arrangements are typically structured on a month-to-month basis subject to termination by either party with thirty-days notice. The Company has concluded that it is not reasonably certain of executing the month-to-month renewal options beyond a twelve-month period based on the historical term for which it has used other production equipment, and, therefore, its other equipment agreements represent operating leases with a lease term up to twelve months.

The Company has further elected to apply the practical expedient for short-term leases to its other production equipment contracts. Accordingly, it does not apply the lease recognition requirements to these contracts, and recognizes lease payments related to these arrangements in profit or loss on a straight-line basis over the lease term. Refer to “Practical Expedients & Accounting Policy Elections” below for additional detail.

Fleet Vehicles

The Company executes fleet vehicle leases with a third-party vendor in support of its day-to-day drilling and production operations. Its vehicle leases are typically structured with a term of a minimum of 367 days for passenger and light duty vehicles and a minimum of 24 months for commercial vehicles and continue thereafter on a month-to-month basis subject to termination by either party within thirty-days notice. The Company has concluded that its fleet vehicle leases represent operating leases.

Significant Judgments

Transportation, Gathering and Processing Arrangements

The Company is party to a gas purchase, gathering and processing contract in the Mississippian Lime region, which includes certain minimum NGLs volume commitments. To the extent the Company does not deliver natural gas volumes in sufficient quantities to generate, when processed, the minimum levels of recovered NGLs, it would be required to reimburse the counterparty an amount equal to the sum of the monthly shortfall, if any, multiplied by a fee. Decreased drilling activity could result in the inability to meet these commitments in the future.

As the Company does not utilize substantially all of the underlying pipeline, gathering system or processing facilities, it has concluded that those underlying assets do not meet the definition of an identified asset.

Discount Rate

The Company’s leases typically do not provide an implicit rate, and thus, the Company is required to use its incremental borrowing rate in determining the present value of lease payments based on the information available at commencement date. The Company’s incremental borrowing rate reflects the rate of interest that it would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. In order to determine its incremental borrowing rate, the Company utilizes its current credit rating as well as best available market data, which includes public bond information for publicly traded upstream energy companies with similar credit ratings, to estimate its unsecured borrowing rate and applied adjustments to that rate to account for the effect of collateral.

The Company has determined the discount rate as of January 1, 2019, using end of day December 31, 2018, market data. This discount rate will be used at transition to ASC 842 as well as all new leases executed within 2019. The Company intends to update the discount rate annually thereafter on January 1 to be used for all new leases within the year (for example, the discount rate will be updated as of January 1, 2020, to be applied to all new leases in 2020). In the event a material lease is executed within a fiscal year or there have been material changes in the market that would impact the Company’s discount rate, the Company will evaluate whether an intra-year update of the discount rate is required.

Practical Expedients & Accounting Policy Elections

Certain of the Company’s lease agreements include lease and non-lease components. For all current asset classes with multiple component types, the Company has utilized the practical expedient that exempts an entity from separating lease components from non-lease components. Accordingly, the Company accounts for the lease and non-lease components in an arrangement as a single lease component.

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In addition, for all asset classes, the Company has made an accounting policy election not to apply the lease recognition requirements to its short-term leases (that is, a lease that, at commencement, has a lease term of 12 months or less, including renewal options expected to be exercised, and does not include an option to purchase the underlying asset that is reasonably certain to be exercised). Accordingly, the Company recognizes lease payments related to its short-term leases in profit or loss on a straight-line basis over the lease term. To the extent that there are variable lease payments, those payments are recognized in profit or loss in the period in which the obligation for those payments is incurred. Refer to “Nature of Leases” above for further information regarding those asset classes that include material short-term leases.

4. Fair Value Measurements of Financial Instruments

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Derivative Instruments

Commodity derivative contracts reflected in the unaudited interim condensed consolidated balance sheets are recorded at estimated fair value. At June 30, 2019, all of the Company’s commodity derivative contracts were with four bank counterparties and were classified as Level 2 in the fair value input hierarchy. The fair value of the Company’s commodity derivatives are determined using industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, non-performance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data.

Derivative instruments listed below are presented gross and include swaps and collars that are carried at fair value. The Company records the net change in the fair value of these positions in gains (losses) on commodity derivative contracts — net in the Company’s unaudited interim condensed consolidated statements of operations.

	Fair Value Measurements at June 30, 2019
	Quoted Prices		Significant Other			Significant
	in Active Markets (Level 1)		Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
	(in thousands)
Derivative Assets:
Commodity derivative oil swaps	$	—	$	368		$	—	$	368
Commodity derivative gas swaps	$	—	$	831		$	—	$	831
Commodity derivative oil collars	$	—	$	1,917		$	—	$	1,917
Commodity derivative gas collars	$	—	$	460		$	—	$	460
Total assets	$	—	$	3,576		$	—	$	3,576

Derivative Liabilities:
Commodity derivative oil swaps	$	—	$	—		$	—	$	—
Commodity derivative gas swaps	$	—	$	—		$	—	$	—
Commodity derivative oil collars	$	—	$	(1,883	)	$	—	$	(1,883	)
Commodity derivative gas collars	$	—	$	(255	)	$	—	$	(255	)
Total liabilities	$	—	$	(2,138	)	$	—	$	(2,138	)

	Fair Value Measurements at December 31, 2018
	Quoted Prices		Significant Other			Significant
	in Active Markets (Level 1)		Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
	(in thousands)
Derivative Assets:
Commodity derivative oil swaps	$	—	$	3,806		$	—	$	3,806
Commodity derivative gas swaps	$	—	$	236		$	—	$	236
Commodity derivative oil collars	$	—	$	9,306		$	—	$	9,306
Commodity derivative gas collars	$	—	$	577		$	—	$	577
Total assets	$	—	$	13,925		$	—	$	13,925

Derivative Liabilities:
Commodity derivative oil swaps	$	—	$	—		$	—	$	—
Commodity derivative gas swaps	$	—	$	(443	)	$	—	$	(443	)
Commodity derivative oil collars	$	—	$	(5,199	)	$	—	$	(5,199	)
Commodity derivative gas collars	$	—	$	(632	)	$	—	$	(632	)
Total liabilities	$	—	$	(6,274	)	$	—	$	(6,274	)

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5. Risk Management and Derivative Instruments

The Company’s production is exposed to fluctuations in crude oil, NGLs and natural gas prices. The Company believes it is prudent to manage the variability in cash flows by, at times, entering into derivative financial instruments to economically hedge a portion of its crude and natural gas production. The Company utilizes various types of derivative financial instruments, including swaps and collars, to manage fluctuations in cash flows resulting from changes in commodity prices.

· Swaps: The Company receives or pays a fixed price for the commodity and pays or receives a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

· Three-way collars: A three-way collar contains a fixed floor price (long put), fixed sub-floor price (short put), and a fixed ceiling price (short call). If the market price exceeds the ceiling strike price, the Company receives the ceiling strike price and pays the market price. If the market price is between the ceiling and the floor strike price, no payments are due from either party. If the market price is below the floor price but above the sub-floor price, the Company receives the floor strike price and pays the market price. If the market price is below the sub-floor price, the Company receives the market price plus the difference between the floor and the sub-floor strike prices and pays the market price.

These derivative contracts are placed with major financial institutions that the Company believes are minimal credit risks. The crude oil and natural gas reference prices upon which the commodity derivative contracts are based reflect various market indices that management believes correlates with actual prices received by the Company for its crude oil and natural gas production.

Inherent in the Company’s portfolio of commodity derivative contracts are certain business risks, including market risk and credit risk. Market risk is the risk that the price of the commodity will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract. The Company does not require collateral from its counterparties but does attempt to minimize its credit risk associated with derivative instruments by entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. In addition, to mitigate its risk of loss due to default, the Company has entered into agreements with its counterparties on its derivative instruments that allow the Company to offset its asset position with its liability position in the event of default by the counterparty. Due to the netting arrangements, had the Company’s counterparties failed to perform under existing commodity derivative contracts, the maximum loss at June 30, 2019, would have been $1.4 million.

Commodity Derivative Contracts

The Company has various oil and natural gas derivative contracts that extend through December 31, 2020, summarized as follows:

	NYMEX WTI
	Fixed Swaps			Three-Way Collars
	Hedge Position (Bbls)	Weighted Avg Strike Price		Hedge Position (Bbls)	Weighted Avg Ceiling Price		Weighted Avg Floor Price		Weighted Avg Sub-Floor Price
Quarter Ended:
June 30, 2019	57,650	$	64.69	182,000	$	63.14	$	53.75	$	43.75
September 30, 2019(1)	46,000	$	62.96	184,000	$	63.14	$	53.75	$	43.75
December 31, 2019(1)	46,000	$	61.43	184,000	$	63.14	$	53.75	$	43.75
March 31, 2020(1)	—	$	—	91,000	$	65.75	$	50.00	$	40.00
June 30, 2020(1)	—	$	—	91,000	$	65.75	$	50.00	$	40.00
September 30, 2020(1)	—	$	—	92,000	$	65.75	$	50.00	$	40.00
December 31, 2020(1)	—	$	—	92,000	$	65.75	$	50.00	$	40.00

(1) Positions shown represent open commodity derivative contract positions as of June 30, 2019.

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	NYMEX HENRY HUB
	Fixed Swaps			Three-Way Collars
	Hedge Position (MMBtu)	Weighted Avg Strike Price		Hedge Position (MMBtu)	Weighted Avg Ceiling Price		Weighted Avg Floor Price		Weighted Avg Sub-Floor Price
Quarter Ended:
June 30, 2019	1,365,000	$	2.75	—	$	—	$	—	$	—
September 30, 2019(1)	1,380,000	$	2.75	—	$	—	$	—	$	—
December 31, 2019(1)	465,000	$	2.75	610,000	$	3.45	$	2.65	$	2.15
March 31, 2020(1)	—	$	—	900,000	$	3.45	$	2.65	$	2.15

(1) Positions shown represent open commodity derivative contract positions as of June 30, 2019.

Balance Sheet Presentation

The following table summarizes the net fair values of commodity derivative instruments by the appropriate balance sheet classification in the Company’s unaudited interim condensed consolidated balance sheets for the periods presented (in thousands):

Type	Balance Sheet Location (1)	June 30, 2019			December 31, 2018
Oil swaps	Derivative financial instruments — current assets	$	368		$	3,806
Gas swaps	Derivative financial instruments — current assets	831			(207		)
Oil collars	Derivative financial instruments — current assets	256			3,316
Gas collars	Derivative financial instruments — current assets	204			25
Total derivative financial instruments — current assets		$	1,659		$	6,940

Oil collars	Derivative financial instruments — noncurrent assets	$	108		$	791
Total derivative financial instruments — noncurrent assets		$	108		$	791

Oil swaps	Derivative financial instruments — current liabilities	$	—		$	—
Gas swaps	Derivative financial instruments — current liabilities	—			—
Oil collars	Derivative financial instruments — current liabilities	(329		)	—
Gas collars	Derivative financial instruments — current liabilities	—			—
Total derivative financial instruments — current liabilities		$	(329	)	$	—

Oil collars	Derivative financial instruments — noncurrent liabilities	$	—		$	—
Gas collars	Derivative financial instruments — noncurrent liabilities	—			(80		)
Total derivative financial instruments — noncurrent liabilities		$	—		$	(80	)

Total derivative fair value at period end		$	1,438		$	7,651

(1) The fair values of commodity derivative instruments reported in the Company’s unaudited interim condensed consolidated balance sheets are subject to netting arrangements and qualify for net presentation.

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The following table summarizes the location and fair value amounts of all commodity derivative instruments in the unaudited interim condensed consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the unaudited interim condensed consolidated balance sheets for the periods presented (in thousands):

		June 30, 2019
Not Designated as		Gross Recognized			Gross Amounts			Net Recognized Fair Value
ASC 815 Hedges	Balance Sheet Location Classification	Assets/Liabilities			Offset			Assets/Liabilities
Derivative Assets:
Commodity contracts	Derivative financial instruments — current	$	2,834		$	(1,175	)	$	1,659
Commodity contracts	Derivative financial instruments — noncurrent	742			(634		)	108
		$	3,576		$	(1,809	)	$	1,767
Derivative Liabilities:
Commodity contracts	Derivative financial instruments — current	$	(1,504	)	$	1,175		$	(329	)
Commodity contracts	Derivative financial instruments — noncurrent	(634		)	634			—
		$	(2,138	)	$	1,809		$	(329	)

		December 31, 2018
Not Designated as		Gross Recognized			Gross Amounts			Net Recognized Fair Value
ASC 815 Hedges	Balance Sheet Location Classification	Assets/Liabilities			Offset			Assets/Liabilities
Derivative Assets:
Commodity contracts	Derivative financial instruments — current	$	11,066		$	(4,126	)	$	6,940
Commodity contracts	Derivative financial instruments — noncurrent	2,859			(2,068		)	791
		$	13,925		$	(6,194	)	$	7,731
Derivative Liabilities:
Commodity contracts	Derivative financial instruments — current	$	(4,126	)	$	4,126		$	(—	)
Commodity contracts	Derivative financial instruments — noncurrent	(2,148		)	2,068			(80		)
		$	(6,274	)	$	6,194		$	(80	)

Gains/Losses on Commodity Derivative Contracts

The Company does not designate its commodity derivative contracts as hedging instruments for financial reporting purposes. Accordingly, commodity derivative contracts are marked-to-market each quarter with the change in fair value during the periodic reporting period recognized currently as a gain or loss in gains (losses) on commodity derivative contracts—net within revenues in the unaudited interim condensed consolidated statements of operations.

The following table presents net cash received or net cash paid for the settlement of commodity derivative contracts and unrealized net gains or unrealized net losses recorded by the Company related to the change in fair value of the derivative instruments in gains (losses) on commodity derivative contracts—net for the periods presented (in thousands):

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2019		2018			2019			2018
Net cash received (paid) for commodity derivative contracts	$	253	$	(3,518	)	$	1,022		$	(3,677	)
Unrealized net gains (losses)	2,288		(7,830		)	(6,213		)	(11,610		)
Gains (losses) on commodity derivative contracts—net	$	2,541	$	(11,348	)	$	(5,191	)	$	(15,287	)

Cash settlements, as presented in the table above, represent realized gains (losses) related to the Company’s derivative instruments. In addition to cash settlements, the Company also recognizes fair value changes on its derivative instruments in each reporting period. The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves.

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6. Property and Equipment

Property and equipment consisted of the following as of the dates presented:

	June 30, 2019			December 31, 2018
	(in thousands)
Oil and gas properties, on the basis of full-cost accounting:
Proved properties	$	827,638		$	809,272
Unproved properties not being amortized	1,912			4,050
Other property and equipment	6,280			6,345
Less accumulated depreciation, depletion, amortization and impairment	(331,904		)	(266,198		)
Net property and equipment	$	503,926		$	553,469

Oil and Gas Properties

Historically, the Company has capitalized internal costs directly related to exploration and development activities to oil and gas properties. During the six months ended June 30, 2019, the Company did not have significant exploration and development activities and no internal costs were capitalized. The Company capitalized the following (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Internal costs capitalized to oil and gas properties (1)	$	—	$	922	$	—	$	1,817

(1) Inclusive of $0.3 million and $0.5 million of qualifying share-based compensation expense for the three and six months ended June 30, 2018, respectively.

The Company accounts for its oil and gas properties under the full cost method. Under the full cost method, proceeds realized from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion of the Company’s reserve quantities are sold such that it results in a significant alteration of the relationship between capitalized costs and remaining proved reserves, in which case a gain or loss is generally recognized in income. During the six months ended June 30, 2018, the Company signed a purchase and sale agreement for its Anadarko Basin assets for $58.0 million before customary closing or post-closing adjustments. The sale of the Anadarko Basin assets closed on May 31, 2018, and did not result in a significant alteration of the full cost pool and therefore, no gain or loss was recognized when the transaction closed.

The Company performs a full-cost ceiling test on a quarterly basis. The test establishes a limit (ceiling) on the book value of the Company’s oil and gas properties. The capitalized costs of oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment (“DD&A”) and the related deferred income taxes, may not exceed this “ceiling.” The ceiling limitation is equal to the sum of: (i) the present value of estimated future net revenues from the projected production of proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the balance sheet, calculated using the average oil and natural gas sales price received by the Company as of the first trading day of each month over the preceding twelve months (such prices held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanying unaudited interim condensed consolidated statements of operations.

For the three and six months ended June 30, 2019, capitalized costs exceeded the ceiling and the Company recorded impairments of oil and gas properties of $33.6 million and $43.2 million, respectively. These impairments were primarily the result of low commodity prices, which resulted in a reduction of the discounted present value of the Company’s proved oil and natural gas reserves. No impairment of oil and gas properties was recorded during the three or six months ended June 30, 2018.

Depreciation, depletion and amortization is calculated using the Units of Production Method (“UOP”). The UOP calculation multiplies the percentage of total estimated proved reserves produced by the cost of those reserves. The result is to recognize expense at the same pace that the reservoirs are estimated to be depleting. The amortization base in the UOP calculation includes the sum of proved property costs net of accumulated depreciation, depletion, amortization and impairment, estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs that are not already included in oil and gas property, less related salvage value. The following table presents depletion expense related to oil and gas properties for the periods presented:

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	Three Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018		2019		2018		2019		2018
	(in thousands)				(per Boe)				(in thousands)				(per Boe)
Depletion expense	$	10,762	$	15,898	$	9.85	$	8.97	$	22,442	$	30,520	$	9.83	$	8.71
Depreciation on other property and equipment	111		586		0.10		0.33		225		1,177		0.10		0.34
Depreciation, depletion, and amortization	$	10,873	$	16,484	$	9.95	$	9.30	$	22,667	$	31,697	$	9.93	$	9.05

Oil and gas unproved properties include costs that are not being depleted or amortized. The Company excludes these costs until proved reserves are found, until it is determined that the costs are impaired or until major development projects are placed in service, at which time the costs are moved into oil and natural gas properties subject to amortization. All unproved property costs are reviewed at least annually to determine if impairment has occurred. In addition, impairment assessments are made for interim reporting periods if facts and circumstances exist that suggest impairment may have occurred. During any period in which impairment is indicated, the accumulated costs associated with the impaired property are transferred to proved properties and become part of our depletion base and subject to the full cost ceiling limitation. No impairment of unproved properties was recorded during the three or six months ended June 30, 2019 or 2018. Unproved property was $1.9 million and $4.1 million at June 30, 2019, and December 31, 2018, respectively.

Other Property and Equipment

Other property and equipment consists of vehicles, furniture and fixtures, and computer hardware and software and are carried at cost. Depreciation is calculated principally using the straight-line method over the estimated useful lives of the assets, which range from two to ten years. Maintenance and repairs are charged to expense as incurred, while renewals and betterments are capitalized.

7. Leases

As previously described in “—Note 3. Impact of ASU 842 Adoption”, the Company leases certain office space, field offices, office equipment, compressors, other production equipment and fleet vehicles under cancelable and non-cancelable leases to support its operations. These leases do not contain material variable payments, residual value guarantees, covenants or other restrictions.

Supplemental cash flow information related to the Company’s leases are included in the table below (in thousands):

	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	309	$	619
Amortization of right-of-use assets:
Operating leases	$	211	$	419

Balance sheet information related to the Company’s leases are included in the table below (in thousands):

	June 30, 2019
Operating Leases
Right-of-use lease assets	4,437
Total operating lease ROU asset	$	4,437

Lease liabilities	$	1,180
Long-term lease liabilities	3,887
Total operating lease liabilities	$	5,067

Weighted-average remaining lease term	6.52 years

As of June 30, 2019, the Company had no finance or operating leases that had not yet commenced.

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8. Accrued Liabilities

The following table presents the components of accrued liabilities as of the dates presented:

	June 30, 2019		December 31, 2018
	(in thousands)
Accrued oil and gas capital expenditures	$	4,103	$	1,534
Accrued revenue and royalty distributions	8,164		13,302
Accrued lease operating and workover expense	3,839		2,843
Accrued interest	68		209
Accrued taxes	935		1,813
Compensation and benefit related accruals	2,872		2,855
Other	668		2,965
Accrued liabilities	$	20,649	$	25,521

9. Asset Retirement Obligations

Asset Retirement Obligations (“AROs”) represent the estimated future abandonment costs of tangible assets, such as wells, service assets and other facilities. The estimated fair value of the AROs at inception are capitalized as part of the carrying amount of the related long-lived assets. The following table reflects the changes in the Company’s AROs for the periods presented (in thousands):

	Six Months Ended June 30,
	2019		2018
Asset retirement obligations — beginning of period	$	8,087	$	15,506
Liabilities incurred	—		219
Revisions	—		—
Liabilities settled	—		(1		)
Liabilities eliminated through asset sales	—		(8,698		)
Current period accretion expense	317		547
Asset retirement obligations — end of period	$	8,404	$	7,573

10. Debt

Reserves-Based Revolving Credit Facility (“RBL”)

At June 30, 2019, and December 31, 2018, the Company maintained an RBL with a borrowing base of $170.0 million. During the six months ended June 30, 2019, the Company drew down $37.5 million, net on its RBL. At June 30, 2019 and December 31, 2018, the Company had $60.6 million and $23.1 million, respectively, drawn on the RBL and had outstanding letters of credit obligations totaling $1.9 million. As a result, at June 30, 2019, the Company had $107.5 million of availability on the RBL.

The RBL matures on September 30, 2020, and bears interest at LIBOR plus 4.50% per annum, subject to a 1.00% LIBOR floor. At June 30, 2019, the weighted average interest rate, excluding amortization expense of deferred financing costs and commitment fees, was 7.7%. Unamortized debt issuance costs of $0.9 million and $1.2 million associated with the RBL are included in other noncurrent assets on the unaudited interim condensed consolidated balance sheets at June 30, 2019, and December 31, 2018, respectively.

In addition to interest expense, the RBL requires the payment of a commitment fee each quarter. The commitment fee is computed at the rate of 0.50% per annum based on the average daily amount by which the borrowing base exceeds outstanding borrowings during each quarter.

The RBL, as amended, includes certain financial maintenance covenants that are required to be calculated on a quarterly basis for compliance purposes. These financial maintenance covenants include EBITDA to interest expense for the trailing four fiscal quarters of not less than 2.50:1.00 and a limitation of Total Net Indebtedness (as defined in the RBL) to EBITDA for the trailing four fiscal quarters of not more than 4.00:1.00.

On November 15, 2018, the Company entered into a Second Amendment to the RBL (the “Second Amendment”). The Second Amendment provides the Company with the ability to make dividends and distributions, including repurchases of its equity interests in cash, in each case, so long as both before and after giving effect to any such repurchase (i) the Company and its subsidiaries maintain liquidity of at least $50.0 million, (ii) no default or event of default exists under the RBL, (iii) the ratio of total net indebtedness to adjusted EBITDA for the most recent period of four fiscal quarters for which financial statements have been delivered pursuant to the RBL shall not exceed 1.50:1.00 and (iv) all repurchased equity interests of the Company must be immediately retired.

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In addition, the RBL contains various other covenants that, among other things, may restrict the Company’s ability to: (i) incur additional indebtedness or guarantee indebtedness; (ii) make loans and investments; (iii) pay dividends on capital stock and make other restricted payments, including the prepayment or redemption of other indebtedness; (iv) create or incur certain liens; (v) sell, transfer or otherwise dispose of certain assets; (vi) enter into certain types of transactions with the Company’s affiliates; (vii) acquire, consolidate or merge with another entity upon certain terms and conditions; (viii) sell all or substantially all of the Company’s assets; (ix) prepay, redeem or repurchase certain debt; (x) alter the business the Company conducts and make amendments to the Company’s organizational documents, (xi) enter into certain derivative transactions and (xii) enter into certain marketing agreements and take-or-pay arrangements. During the six months ended June 30, 2019, the Company partially funded the stock buyback by drawing down $39.0 million from its RBL, as noted in “— Note 11. Equity and Share-Based Compensation” below, with the remainder funded by cash on hand.

The Company was in compliance with all debt covenants at June 30, 2019.

On April 11, 2019, the Company’s borrowing base was redetermined at the existing amount of $170.0 million.

The Company believes the carrying amount of the RBL at June 30, 2019, approximates, its fair value (Level 2) due to the variable nature of the RBL interest rate.

11. Equity and Share-Based Compensation

Common Shares

Share Activity

The following table summarizes changes in the number of shares of common stock and treasury stock during the six months ended June 30, 2019:

	Common Stock		Treasury Stock(1)
Share count as of December 31, 2018	25,520,170		(174,189	)
Common stock issued	100,696		—
Acquisition of treasury stock	—		(5,031,672	)
Retirement of treasury stock	(5,000,000	)	5,000,000
Share count as of June 30, 2019	20,620,866		(205,861	)

(1) Treasury stock at June 30, 2019, and December 31, 2018, represents the net settlement on vesting of restricted stock necessary to satisfy the minimum statutory tax withholding requirements.

On January 14, 2019, the Company announced the commencement of a tender offer (the “Tender Offer”), authorized by the Board of Directors, to repurchase up to 5,000,000 shares of common stock at the offer price of $10.00 per share. On February 14, 2019, the Tender Offer was completed with the purchase of 5,000,000 shares of common stock at a purchase price of $10.00 per share. The 5,000,000 shares repurchased by the Company on February 14, 2019, were subsequently retired. When treasury shares are retired, the excess of the repurchase price over the par value of the shares is allocated to additional paid in capital for amounts up to the original price of the shares at issuance, with any residual excess purchase price allocated to retained earnings. The excess of the repurchase price over the par value of the shares repurchased and subsequently retired on February 14, 2019, was allocated solely to additional paid-in-capital.

Warrants

On October 21, 2016, the Company issued 4,411,765 Third Lien Notes Warrants to purchase up to an aggregate of 4,411,765 shares of common stock at an initial exercise price of $24.00 per share and 2,213,789 Unsecured Creditor Warrants to purchase up to an aggregate of 2,213,789 shares of common stock at an initial exercise price of $46.00 per share. The Warrants expire on April 21, 2020.

The number of shares of common stock for which the Warrants are exercisable, and the exercise price per share of the Warrants are subject to adjustment from time to time upon the occurrence of certain events, including the issuance of common stock as a dividend or distribution to all holders of shares of common stock, a pro-rata repurchase offer of common stock or a subdivision, combination, split, reverse split or reclassification of outstanding common stock into a greater or smaller number of shares of common stock.

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As a result of the Tender Offer, the outstanding warrants of the Company were adjusted. The exercise price of the Third Lien Notes Warrants were adjusted from $24.00 per share to $22.78 per share and the exercise price of the Unsecured Creditor Warrants were adjusted from $46.00 per share to $43.67 per share. Further, the number of shares eligible to be received upon exercise of each warrant was adjusted by a factor of 1.05. Subsequent to the Tender Offer, the Third Lien Notes Warrants and the Unsecured Creditor Warrants may be exercised for up to an aggregate of 4,647,520 and 2,332,089 shares of common stock, respectively.

Share-Based Compensation

2016 Long Term Incentive Plan

On October 21, 2016, the Company established the 2016 LTIP and filed a Form S-8 with the SEC, registering 3,513,950 shares for issuance under the terms of the 2016 LTIP to employees, directors and certain other persons (the “Award Shares”). The types of awards that may be granted under the 2016 LTIP include stock options, restricted stock units, restricted stock, performance awards and other forms of awards granted or denominated in shares of common stock of the reorganized Company, as well as certain cash-based awards (the “Awards”). The terms of each award are as determined by the Compensation Committee of the Board of Directors. Awards that expire, or are canceled, forfeited, exchanged, settled in cash or otherwise terminated, will again be available for future issuance under the 2016 LTIP. At June 30, 2019, 1,768,660 Award Shares remain available for issuance under the terms of the 2016 LTIP.

Stock Buyback Equalization Program

On December 21, 2018, the Company adopted a stock buyback equalization program that allows holders of the Company’s outstanding equity awards to participate in any tender program or share repurchase program of the Company with their vested and unvested shares applicable to those equity awards. Vested awards that have been elected for participation in the equalization program are settled in a cash payment equal to the cash purchase price paid by the Company in the applicable tender offer or share repurchase program. Unvested or deferred awards that have been elected for participation in an equalization program are realized through a cash settlement of the awards upon the vesting or lapse of the award’s deferral conditions.

On January 14, 2019, the Company announced the commencement of the Tender Offer, authorized by the Board of Directors, to repurchase up to 5,000,000 shares of common stock at the offer price of $10.00 per share. On February 14, 2019, the Tender Offer was completed with the purchase of 5,000,000 shares of common stock at a purchase price of $10.00 per share. In conjunction with the Tender Offer, holders of the Company’s restricted stock units participated in the related equalization program, as discussed below. No other outstanding equity awards were eligible for participation in the equalization program.

Restricted Stock Units

At June 30, 2019, the Company had 353,464 non-vested restricted stock units outstanding to employees and non-employee directors pursuant to the 2016 LTIP, excluding restricted stock units issued to non-employee directors containing a market condition, which are discussed below. During the six months ended June 30, 2019, 161,194 non-vested restricted stock units were issued to employees and non-employee directors. Restricted stock units granted to employees in 2019 under the 2016 LTIP vest in full on March 1, 2021, or upon the occurrence of a change in control, provided the employee has not terminated employment prior to such vesting date. Restricted stock units granted to non-employee directors during 2019 vest on the first to occur of (i) December 31, 2019, (ii) the date the non-employee director ceases to be a director of the Board (other than for cause), (iii) the director’s death, (iv) the director’s disability or (v) a change in control of the Company.

The fair value of restricted stock units granted to employees and non-employee directors during 2019 was based on grant date fair value of the Company’s common stock. Compensation expense is recognized ratably over the requisite service period.

In conjunction with the Company’s purchase of common stock through the Tender Offer completed on February 14, 2019, holders of the Company’s restricted stock units participated in an equalization program in which 97,995 unvested shares were tendered at the settlement price of $10.00 per unvested share. The Company recorded a liability of $1.0 million for the modified awards during the six months ended June 30, 2019, for the future cash settlement of these tendered shares upon vesting.

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The following table summarizes the Company’s non-vested restricted stock unit award activity for the six months ended June 30, 2019:

	Restricted Stock		Weighted Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2018	251,522		$	15.79
Granted	161,194		$	7.94
Vested(1)	(37,258	)	$	16.62
Forfeited	(21,994	)	$	13.70
Non-vested shares outstanding at June 30, 2019	353,464		$	12.25

(1) Restricted stock units which vested during the six months ended June 30, 2019 were accelerated as a result of a reduction in workforce that occurred during the period.

Unrecognized expense as of June 30, 2019, for all outstanding restricted stock units under the 2016 LTIP Plan was $1.7 million and will be recognized over a weighted average period of 0.9 years.

Stock Options

At June 30, 2019, the Company had 54,365 non-vested options outstanding pursuant to the 2016 LTIP. Stock Option Awards currently outstanding under 2016 LTIP vest ratably over a period of three years: one-sixth will vest on the six-month anniversary of the grant date, an additional one-sixth will vest on the twelve-month anniversary of the grant date, an additional one-third will vest on the twenty-four month anniversary of the grant date and the final one-third will vest on the thirty-six month anniversary of the grant date. Stock Option Awards expire 10 years from the grant date. There were no issuances of stock options during the six months ended June 30, 2019.

The following table summarizes the Company’s 2016 LTIP non-vested stock option activity for the six months ended June 30, 2019:

	Options		Range of Exercise Prices		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (Years)
Stock options outstanding at December 31, 2018	70,102				$	19.65	7.3
Granted	—		$	—	$	—	—
Vested(1)	(14,889	)	$	19.08–19.66	$	19.56	0.1
Forfeited	(848	)	$	19.66	$	19.66	—
Stock options outstanding at June 30, 2019	54,365				$	19.68	7.3
Vested and exercisable at end of period(2)	151,050		$	19.08-20.97	$	19.66	5.4

(1) Vested stock options during the six months ended June 30, 2019, were accelerated as a result of a reduction in workforce that occurred during the six months ended June 30, 2019.

(2) Vested and exercisable options at June 30, 2019, had no aggregate intrinsic value.

Unrecognized expense as of June 30, 2019, for all outstanding stock options under the 2016 LTIP Plan was $0.1 million and will be recognized over a weighted average period of 0.3 years.

Non-Employee Director Restricted Stock Units Containing a Market Condition

On November 23, 2016, the Company issued restricted stock units to non-employee directors that contain a market vesting condition. These restricted stock units will vest (i) on the first business day following the date on which the trailing 60-day average share price (including any dividends paid) of the Company’s common stock is equal to or greater than $30.00 or (ii) upon a change in control (as defined in the 2016 LTIP) of the Company. Additionally, all unvested restricted stock units containing a market vesting condition will be immediately forfeited upon the first to occur of (i) the fifth anniversary of the grant date or (ii) any participant’s termination as a director for any reason (except for a termination as part of a change in control of the Company).

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These restricted stock awards are accounted for as liability awards under FASB Accounting Standards Codification 718 — Stock Compensation (“ASC 718”) as the awards allow for the withholding of taxes at the discretion of the non-employee director. The liability is re-measured, with a corresponding adjustment to earnings, at each fiscal quarter-end during the performance cycle. The derived service period related to these awards ended in November 2017. As such, changes in the fair value of the liability and related compensation expense of these awards are no longer recognized pro-rata over the period for which service has already been provided but rather are compensation cost in the period in which the changes occur. As there are inherent uncertainties related to these factors and the Company’s judgment in applying them to the fair value determinations, there is risk that the recorded compensation may not accurately reflect the amount ultimately earned by the non-employee directors.

At June 30, 2019, the Company recorded a $0.1 million liability included within accrued liabilities on the unaudited interim condensed consolidated balance sheets, related to the 50,864 market condition awards outstanding. The weighted-average fair value of the restricted stock units containing a market condition was $0.27 at June 30, 2019.

As of June 30, 2019, there was no unrecognized stock-based compensation expense related to market condition awards.

Chief Executive Officer (“CEO”) Restricted Stock Units Containing a Market Condition

On November 1, 2017, the Company issued 135,778 restricted stock units to its CEO that contain a market vesting condition. These restricted stock units will vest, if at all, based on the Company’s total stockholder return for the performance period of October 25, 2017, through October 31, 2020. Market conditions under this grant are (i) with respect to 50% of the RSUs granted, the Company’s cumulative total shareholder return (“TSR”) which is defined as the change in the value of the stock over the performance period with the beginning and ending stock price based on a 20-day average stock price and (ii) with respect to the remaining 50% of the RSUs granted, the percentile rank of the Company’s TSR compared to the TSR of the Peer Group over the performance period (“Relative TSR”).

To the extent that actual TSR or Relative TSR for the performance period is between specified vesting levels, the portion of the RSUs that shall become vested based on actual and Relative TSR performance shall be determined on a pro-rata basis using straight-line interpolation; provided that the maximum portion of the RSUs that may become vested based on actual cumulative TSR or Relative TSR for the performance period shall not exceed 120% of the awards granted.

The RSUs issued to the CEO containing a market condition have a service period of three years. The share-based compensation costs related to the CEO restricted stock units containing a market condition recognized as general and administrative expense by the Company was $0.1 million and $0.2 million for the three and six months ended June 30, 2019. As of June 30, 2019, unrecognized stock-based compensation related to CEO RSUs containing a market condition was $0.7 million and will be recognized over a weighted-average period of 1.3 years.

2018 Performance Stock Units Issued to Certain Members of Executive Management Containing a Market Condition

On March 1, 2018, the Company issued 96,305 restricted stock units to certain members of executive management that contain a market vesting condition. These restricted stock units will vest, if at all, based on the Company’s total stockholder return for the performance period of January 1, 2018, through December 31, 2020. To the extent that the Relative TSR for the performance period is between specified vesting levels, the portion of the restricted stock units that become vested based on the Relative TSR performance shall be determined on a pro-rata basis using straight-line interpolation; provided that the maximum portion of the restricted stock units that may become vested based on the Relative TSR for the performance period shall not exceed 150% of the awards granted. In addition, if the Relative TSR for the Company is negative over the performance period, vesting of these performance stock units is limited to no more than 100%.

If a member of executive management terminates employment prior to vesting, the outstanding award is forfeited. Executive management restricted stock units with a market condition are subject to accelerated vesting in the event the executive’s employment is terminated prior to vesting by the Company without “Cause” or by the participant with “Good Reason” (each, as defined in the 2016 LTIP) or due to the executive’s death or disability. Upon a change in control (as defined in the 2016 LTIP), the compensation committee of the board of directors could (i) accelerate all or a portion of the award, (ii) cancel all of the award and pay cash, stock or combination equal to the change in control price, (iii) provide for the assumption or substitution or continuation by the successor company, (iv) certify to the extent to which the vesting conditions had been achieved prior to the conclusion of the performance period or (v) adjust restricted stock units to reflect the change in control.

These restricted stock awards are accounted for as equity awards under ASC 718 as the awards are settled in shares of the Company with no additional settlement options permitted. At the grant date, the Company estimated the fair value of this equity award. The compensation expense of this award each period is recognized by dividing the fair value of the total award by the requisite service period and recording the pro-rata share for the period for which service has already been provided. As there are inherent uncertainties related to these factors and the Company’s judgment in applying them to the fair value determinations, there is risk that the recorded compensation may not accurately reflect the amount ultimately earned by the executives.

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The restricted stock units issued to executive management containing a market condition have a service period of three years. The share-based compensation costs related to executive management’s restricted stock units containing a market condition recognized as general and administrative expense by the Company was $0.1 million and $0.2 million for the three and six months ended June 30, 2019. As of June 30, 2019, unrecognized stock-based compensation related to executive management’s restricted stock units containing a market condition was $0.7 million and will be recognized over a weighted-average period of 1.5 years.

2019 Performance Stock Units Issued to Certain Members of Executive Management Containing a Market Condition

On March 7, 2019, the Company issued 193,921 restricted stock units to certain members of executive management that contain a market vesting condition. These restricted stock units will vest, if at all, when a 60 consecutive trading day volume weighted average price is achieved at any time during the performance period of January 1, 2019, through December 31, 2020. To the extent that the price per common share of stock for the performance period is between specified vesting levels, the portion of the restricted stock units that become vested based on the price per common share of stock shall be determined on a pro-rata basis using straight-line interpolation; provided that the maximum portion of the restricted stock units that may become vested based on the price per common share of stock for the performance period shall not exceed 150% of the awards granted.

If a member of executive management terminates employment prior to vesting, the outstanding award is forfeited. Executive management members whose employment is terminated between months 6 and 12 of the performance period without “Cause”, due to the executive’s death or disability, or by the participant with “Good Reason” (each, as defined in the 2016 LTIP) shall forfeit 50% of the restricted stock units. The remaining 50% of the stock units will remain eligible to vest according to the performance vesting schedule above. Executive management members whose employment is terminated without Cause or by the participant for Good Reason between months 12 and 24 of the performance period, will not forfeit restricted stock units, with 100% of the restricted stock units remaining eligible for vesting according to the performance vesting schedule above. Upon a change in control (as defined in the 2016 LTIP), the compensation committee of the board of directors could (1) accelerate all or a portion of the award, (2) cancel all of the award and pay cash, stock or combination equal to the change in control price, (3) provide for the assumption or substitution or continuation by the successor company, (4) certify to the extent to which the vesting conditions had been achieved prior to the conclusion of the performance period or (5) adjust restricted stock units to reflect the change in control. If restricted stock units remain in effect following a change of control effectuated by a sale, merger or business combination and an executive’s employment is terminated without Cause or by the participant with Good Reason, the participant’s right to vest in the restricted stock units is determined by the price determined to have been paid as consideration to the Company for the common share of the Company’s stock in the change of control. If the change of control price is below $9.50 a share of common stock, the restricted stock units of the terminated executive will be forfeited. If the change of control price is above $9.50 a share of common stock, the vesting of the restricted stock units will occur upon termination of the executive, at the vesting percentages specified in the performance vesting schedule above. The termination of an executive without Cause or by the participant with Good Reason within 12 months of a change of control not effectuated by a sale, merger or business combination shall not forfeit restricted stock units, which will vest as described in the performance vesting schedule above.

The restricted stock units issued to executive management containing a market condition have a service period of two years. The share-based compensation costs related to executive management’s restricted stock units containing a market condition recognized as general and administrative expense by the Company was $0.2 million and $0.3 million for the three and six months ended June 30, 2019. As of June 30, 2019, unrecognized stock-based compensation related to executive management’s restricted stock units containing a market condition was $1.1 million and will be recognized over a weighted-average period of 1.5 years.

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12. Income Taxes

For the six months ended June 30, 2019, the Company recorded no income tax expense or benefit. The significant difference between our effective tax rate and the federal statutory income tax rate of 21% is primarily due to the effect of changes in the Company’s valuation allowance. During the six months ended June 30, 2019, the Company’s valuation allowance increased by $13.8 million from December 31, 2018, bringing the total valuation allowance to $123.4 million at June 30, 2019. A valuation allowance has been recorded as management does not believe that it is more-likely-than-not that its deferred tax assets are realizable.

The Company expects to incur a tax loss in the current year due to the flexibility in deducting or capitalizing current year intangible drilling costs; thus no current income taxes are anticipated to be paid.

13. Income Per Share

The following table provides a reconciliation of net income attributable to common shareholders and weighted average common shares outstanding for basic and diluted income (loss) per share for the periods presented:

	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(in thousands, except per share amounts)						(in thousands, except per share amounts)
Net Income (Loss):
Net income (loss)	$	(36,948	)	$	(1,542	)	$	(54,755	)	$	2,461
Participating securities—non-vested restricted stock	—			—			—			(68		)
Basic and diluted income (loss)	$	(36,948	)	$	(1,542	)	$	(54,755	)	$	2,393

Common Shares:
Common shares outstanding — basic (1)	20,512			25,332			21,668			25,316
Dilutive effect of potential common shares	—			—			—			—
Common shares outstanding — diluted	20,512			25,332			21,668			25,316

Net Income (Loss) Per Share:
Basic	$	(1.80	)	$	(0.06	)	$	(2.53	)	$	0.09
Diluted	$	(1.80	)	$	(0.06	)	$	(2.53	)	$	0.09
Antidilutive stock options (2)	205			500			205			500
Antidilutive warrants (3)	6,980			6,626			6,980			6,626

(1) Weighted-average common shares outstanding for basic and diluted income per share purposes includes 9,407 shares of common stock that, while not issued and outstanding at June 30, 2019 or 2018, respectively, are required by the First Amended Joint Chapter 11 Plan of Reorganization of Midstates Petroleum Company, Inc. and its Debtor Affiliate as filed on September 28, 2016, (the “Plan”) to be issued. Weighted-average common shares outstanding for basic and diluted income per share purposes also includes 79,389 director shares that vested as of June 30, 2019, but final issuance of the vested shares was deferred by the non-employee directors until 2021.

(2) Amount represents options to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect.

(3) Amount represents warrants to purchase common stock that are excluded from the diluted net income per share calculations because of their antidilutive effect.

14. Related Party Transactions

During 2017, the Company entered into an arrangement with EcoStim Energy Solutions, Inc. (“EcoStim”) for well stimulation and completion services. EcoStim is an affiliate of Fir Tree Inc. who is a holder of the Company’s outstanding common stock. The Company had $2.1 million included in accounts payable in the Company’s unaudited interim condensed consolidated balance sheets at December 31, 2017, to EcoStim that was paid during the six months ended June 30, 2018. No transactions with EcoStim occurred during the six months ended June 30, 2019.

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15. Commitments and Contingencies

The Company is involved in various matters incidental to its operations and business that might give rise to a loss contingency. These matters may include legal and regulatory proceedings, commercial disputes, claims from royalty, working interest and surface owners, property damage and personal injury claims and environmental or other matters. In addition, the Company may be subject to customary audits by governmental authorities regarding the payment and reporting of various taxes, governmental royalties and fees as well as compliance with unclaimed property (escheatment) requirements and other laws. Further, other parties with an interest in wells operated by the Company have the ability under various contractual agreements to perform audits of its joint interest billing practices.

The Company vigorously defends itself in these matters. If the Company determines that an unfavorable outcome or loss of a particular matter is probable and the amount of loss can be reasonably estimated, it accrues a liability for the contingent obligation. As new information becomes available or as a result of legal or administrative rulings in similar matters or a change in applicable law, the Company’s conclusions regarding the probability of outcomes and the amount of estimated loss, if any, may change. The impact of subsequent changes to the Company’s accruals could have a material effect on its results of operations. As of June 30, 2019, the Company did not have an accrual for loss contingencies. As of December 31, 2018, the Company’s total accrual for all loss contingencies was $1.1 million.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and notes thereto for the year ended December 31, 2018, and the related management’s discussion and analysis contained in our annual report on Form 10-K dated and filed with the Securities and Exchange Commission (“SEC”) on March 14, 2019, as well as the unaudited interim condensed consolidated financial statements and notes thereto included in this quarterly report on Form 10-Q and our quarterly report on Form 10-Q for the quarter ended March 31, 2019, filed with the SEC on May 10, 2019.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in or incorporated by reference into this report are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, and the plans, beliefs, expectations, intentions and objectives of management are forward-looking statements. When used in this quarterly report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” and similar expressions are intended to identify forward looking statements, although not all forward looking statements contain such identifying words. All forward-looking statements speak only as of the date of this quarterly report. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions, including changes in oil and natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this report and in the Annual Report on Form 10-K. Moreover, we operate in a very competitive and rapidly changing environment. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this quarterly report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.

Forward-looking statements may include statements about our:

· business strategy;

· estimated future net reserves and present value thereof;

· technology;

· financial condition, revenues, cash flows and expenses;

· levels of indebtedness, liquidity, borrowing capacity and compliance with debt covenants;

· financial strategy, budget, projections and operating results;

· oil and natural gas realized prices;

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

· availability of drilling and production equipment;

· the amount, nature and timing of capital expenditures, including future development costs;

· availability of oilfield labor;

· availability of third party natural gas gathering and processing capacity;

· availability and terms of capital;

· drilling of wells, including our identified drilling locations;

· successful results from our identified drilling locations;

· marketing of oil and natural gas;

· the integration and benefits of asset and property acquisitions or the effects of asset and property acquisitions or dispositions on our cash position and levels of indebtedness;

· infrastructure for salt water disposal and electricity;

· current and future ability to dispose of salt water;

· sources of electricity utilized in operations and the related infrastructures;

· costs of developing our properties and conducting other operations;

· general economic conditions;

· effectiveness of our risk management activities;

· environmental liabilities;

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· counterparty credit risk;

· the outcome of pending and future litigation;

· governmental regulation and taxation of the oil and natural gas industry;

· developments in oil and natural gas producing countries;

· capital structure and capital returns;

· uncertainty regarding our future operating results; and

· plans, objectives, expectations and intentions contained in this quarterly report that are not historical.

Overview

We are an independent exploration and production company focused on the application of modern drilling and completion techniques in oil and liquids-rich basins in the onshore United States. Our operations are primarily focused on exploration and production activities in the Mississippian Lime. The terms “Company,” “we,” “us,” “our,” and similar terms refer to us and our subsidiary, unless the context indicates otherwise.

Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we realize from the sale of that production. The amount we realize for our production depends predominantly upon commodity prices and our related commodity price hedging activities, if any, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials, and other factors. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.

Definitive Merger Agreement

On May 6, 2019, we entered into a definitive merger agreement (“Merger Agreement”) pursuant to which Amplify Energy Corp. (“Amplify”) will merge with a subsidiary of ours in an all-stock merger-of-equals. Under the terms of the Merger Agreement, Amplify stockholders will receive 0.933 shares of newly issued common stock for each Amplify share of common stock. The merger is expected to close on August 6, 2019, at which time Amplify and our stockholders will each own 50% of the outstanding shares of the combined entity.

The transaction is subject to the terms and conditions set forth in the Merger Agreement, including holders of a majority of our stock present at the special meeting having voted in favor of the stock issuance, holders of a majority of Amplify stock having voted in favor of the merger, the waiting period under the U.S. Hart-Scott-Rodino Act having expired or been terminated early, our stock being issued to Amplify stockholders in connection with the merger being listed on the NYSE and other customary conditions. All such conditions were satisfied as of August 5, 2019.

The transactions contemplated by the Merger Agreement will be treated as a “change in control” as of the effective date for purposes of all Parent Benefit Plans (as defined in the Merger Agreement), including the Parent Stock Plans (as defined in the Merger Agreement) and all applicable employment agreements in effect prior to the effective date to which any employee of ours is a party. We have agreed to satisfy promptly all applicable severance, retention and change in control payments and benefits owing to our employees, directors and other service providers under the Parent Benefit Plans. Without limiting the foregoing, (i) with respect to any employee of ours whose employment is terminated without “cause” (as such term is defined in the applicable Parent Benefit Plan, but also including certain employees who are deemed to be terminated without cause pursuant to the Merger Agreement) on or within one year after the closing of the merger, (A) all Parent Stock Options (as defined in the Merger Agreement) held by such employee shall become fully vested, (B) all Parent RSUs (as defined in the Merger Agreement) held by such employee shall become fully vested and shall be settled promptly upon termination, (C) all Parent PSUs (as defined in the Merger Agreement) that are subject to the achievement of our specific stock price levels shall be deemed earned at the level specified in the applicable award agreement and shall become vested and settled promptly upon termination, (D) all Parent PSUs that are not described in the foregoing clause (C) shall be deemed earned at the target level of such award and shall become vested and settled promptly upon termination, and (E) all cash amounts pursuant to the “Share Buyback Equalization Program” approved by our board of directors on December 21, 2018 (the “Equalization Program”) that are owing to such employee(s) shall be paid promptly upon termination, (ii) all Parent RSUs held by members of the board of directors shall become fully vested and shall be settled promptly upon the closing of the merger, and (iii) all cash amounts pursuant to the Equalization Program that are owing to our non-employee directors shall be paid promptly upon the closing of the merger.

We estimate that between 500,000 and 800,000 unvested stock awards (including stock options) will vest upon closing and between $8.5 million to $11.5 million in severance payments will be made. The number of unvested stock awards and severance payments are estimated and the final amount has not yet been determined.

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Operations Update

Mississippian Lime

The following table presents our average daily production from our Mississippian Lime asset for the periods presented:

	Three Months Ended June 30, 2019	Three Months Ended March 31, 2019	Decrease in Production

Average daily production:
Oil (Bbls)	2,753	3,381	(18.6	)%
Natural gas liquids (Bbls)	3,250	3,538	(8.1	)%
Natural gas (Mcf)	36,032	37,919	(5.0	)%
Net Boe/day	12,008	13,239	(9.3	)%

In the second quarter of 2019, we incurred approximately $10.7 million of operational capital expenditures in the Mississippian Lime basin.

Anadarko Basin

On May 31, 2018, we closed on the sale of our Anadarko Basin assets for $58.0 million in cash ($54.4 million, net of closing adjustments).

Capital Expenditures

During the three and six months ended June 30, 2019, we incurred operational capital expenditures of $10.7 million and $17.2 million, respectively, in the Mississippian Lime basin, which consisted of the following:

	For the Three Months Ended June 30, 2019			For the Six Months Ended June 30, 2019
Drilling and completion activities	$	10,335		$	15,670
Acquisition of acreage and seismic data	380			1,488
Operational capital expenditures incurred	$	10,715		$	17,158
Capitalized G&A, office, ARO & other	(16		)	54
Capitalized interest	44			147
Total capital expenditures incurred	$	10,743		$	17,359

Factors that Significantly Affect Our Risk

Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, our cash flows, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

We follow the full cost method of accounting for our oil and gas properties. For the three and six months ended June 30, 2019, the results of our full cost “ceiling test” required us to recognize impairments of our oil and gas properties of $33.6 million and $43.2 million, respectively. While these impairments did not impact cash flows from operating activities or liquidity, they did increase our net loss and shareholders’ equity. As a result of the pause in our drilling program, we could continue to incur impairment charges throughout fiscal year 2019. The magnitude of future impairment charges, if any, will be impacted by certain factors outside of our control, such as commodity pricing.

We dispose of large volumes of saltwater produced in conjunction with oil and natural gas from drilling and production operations in the Mississippian Lime. Our disposal operations are conducted pursuant to permits issued to us by governmental authorities overseeing such disposal activities.

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There continues to be a concern that the injection of saltwater into belowground disposal wells contributes to seismic activity in certain areas, including Oklahoma, where we operate. The Oil and Gas Conservation Division (“OGCD”) of the Oklahoma Corporation Commission established caps for additional wells in the Arbuckle formation, including 16 that we operate, on February 24, 2017. On March 1, 2017, the OGCD also issued a statement saying that further actions to reduce the earthquake rate in Oklahoma could be expected. The OGCD has since issued several directives for disposal well shut-in and volume reductions in certain areas following seismic activity. While our current plans are for future disposal wells to inject into formations other than the Arbuckle and we currently operate 9 such non-Arbuckle formation disposal wells, we continue to utilize wells that dispose into the Arbuckle formation. We have timely met and satisfied all requests of the OGCD regarding changes and/or reductions in disposal capacity in our operated disposal wells, all while maintaining our production base without any negative material impact thereto. We believe we are currently in compliance with the OGCD’s latest requests regarding Arbuckle injection limits; however, a change in disposal well regulations or injection limits, or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of saltwater and ultimately increase the cost of our operations and/or reduce the volume of oil and natural gas that we produce from our wells.

Results of Operations

The following tables summarize our revenues for the periods indicated (in thousands):

	Crude Oil			Natural Gas			NGLs			Total
Revenues for the three months ended June 30, 2018	$	34,202		$	6,782		$	11,893		$	52,877
Changes due to volumes	(17,318		)	(2,385		)	(3,543		)	(23,246		)
Changes due to price	(2,330		)	(1,229		)	(3,374		)	(6,933		)
Revenues for the three months ended June 30, 2019	$	14,554		$	3,168		$	4,976		$	22,698

	Crude Oil			Natural Gas			NGLs			Total
Revenues for the six months ended June 30, 2018	$	66,616		$	15,119		$	22,931		$	104,666
Changes due to volumes	(30,622		)	(4,780		)	(6,267		)	(41,669		)
Changes due to price	(5,113		)	(561		)	(5,472		)	(11,146		)
Revenues for the six months ended June 30, 2019	$	30,881		$	9,778		$	11,192		$	51,851

Oil, NGLs and Natural Gas Pricing

The following tables set forth information regarding average realized sales prices for the periods indicated (per BOE):

	For the Three		For the Three				For the Six		For the Six
	Months Ended		Months Ended		%		Months Ended		Months Ended		%
	June 30, 2019		June 30, 2018		Change		June 30, 2019		June 30, 2018		Change
AVERAGE SALES PRICES:
Oil, without realized derivatives (per Bbl)	$	58.09	$	67.42	(13.8	)%	$	55.65	$	64.89	(14.2	)%
Oil, with realized derivatives (per Bbl)	$	58.48	$	59.95	(2.5	)%	$	57.67	$	59.76	(3.5	)%
Natural gas liquids, without realized derivatives (per Bbl)	$	16.82	$	28.24	(40.4	)%	$	18.22	$	27.14	(32.9	)%
Natural gas liquids, with realized derivatives (per Bbl)	$	16.82	$	28.24	(40.4	)%	$	18.22	$	27.14	(32.9	)%
Natural gas, without realized derivatives (per Mcf)	$	0.97	$	1.34	(27.6	)%	$	1.46	$	1.55	(5.8	)%
Natural gas, with realized derivatives (per Mcf)	$	1.01	$	1.39	(27.3	)%	$	1.45	$	1.71	(15.2	)%

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Oil, NGLs and Natural Gas Production

	For the Three Months	For the Three Months			For the Six Months	For the Six Months
	Ended June 30, 2019	Ended June 30, 2018	% Change		Ended June 30, 2019	Ended June 30, 2018	% Change
PRODUCTION DATA:
Oil (Bbls/d)
Mississippian Lime	2,753	4,833	(43.0	)%	3,066	4,699	(34.8	)%
Anadarko Basin(1)	—	1,110	(100.0	)%	—	1,168	(100.0	)%
Natural gas liquids (Bbls/d)
Mississippian Lime	3,250	3,995	(18.6	)%	3,393	3,821	(11.2	)%
Anadarko Basin(1)	—	946	(100.0	)%	—	1,017	(100.0	)%
Natural gas (Mcf/d)
Mississippian Lime	36,032	50,246	(28.3	)%	36,970	47,083	(21.5	)%
Anadarko Basin(1)	—	7,956	(100.0	)%	—	8,365	(100.0	)%
Combined (Boe/d)
Mississippian Lime	12,008	17,202	(30.2	)%	12,620	16,367	(22.9	)%
Anadarko Basin(1)	—	3,382	(100.0	)%	—	3,579	(100.0	)%

(1) We divested our Anadarko Basin assets during the second quarter of 2018.

Oil Revenues

Oil volumes in the Mississippian Lime decreased 2,080 Boe/day and 1,633 Boe/day, or 43.0% and 34.8%, respectively, for the three and six months ended June 30, 2019, primarily due to lower production as a result of reduced drilling activity and natural decline. Average oil sales prices, without realized derivatives, decreased by $9.33 per barrel and $9.24 per barrel, or 13.8% and 14.2%, respectively, largely as a result of a decrease in prevailing market prices.

NGLs Revenues

NGLs volumes in the Mississippian Lime decreased 745 Boe/day and 428 Boe/day, or 18.6% and 11.2%, respectively, for the three and six months ended June 30, 2019, primarily as a result of reduced drilling activity and natural decline. Average NGLs sales prices, without realized derivatives, decreased by $11.42 per barrel and $8.92 per barrel, or 40.4% and 32.9%, respectively, largely as a result of lower oil prices, which correlate with NGLs pricing.

Natural Gas Revenues

Natural gas volumes in the Mississippian Lime decreased 14,214 Mcf/day and 10,113 Mcf/day, or 28.3% and 21.5%, respectively, for the three and six months ended June 30, 2019, primarily as a result of reduced drilling activity and natural decline. Average natural gas sales prices, without realized derivatives, decreased by $0.37 per MCf and $0.09 per Mcf, or 27.6% and 5.8%, respectively, largely due to lower prevailing index prices at our delivery points.

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Gains/Losses on Commodity Derivative Contracts—Net

A summary of our open commodity derivative positions is included in Note 5 to the financial statements included in “Part I. Financial Information — Item 1. Financial Statements” of this report. The following tables provide financial information associated with our oil and natural gas hedges for the periods indicated (in thousands):

	For the Three Months Ended June 30, 2019		For the Three Months Ended June 30, 2018			For the Six Months Ended June 30, 2019			For the Six Months Ended June 30, 2018
Cash receipts (payments on settlement)
Oil derivatives	$	98	$	(3,776	)	$	1,116		$	(5,252	)
Natural gas derivatives	155		258			(94		)	1,575
Total cash settlements	$	253	$	(3,518	)	$	1,022		$	(3,677	)

Gains (losses) due to fair value changes
Oil derivatives	$	1,168	$	(6,986	)	$	(7,510	)	$	(9,390	)
Natural gas derivatives	1,120		(844		)	1,297			(2,220		)
Total gains (losses) on fair value changes	$	2,288	$	(7,830	)	$	(6,213	)	$	(11,610	)

Gains (losses) on commodity derivative contracts—net	$	2,541	$	(11,348	)	$	(5,191	)	$	(15,287	)

Cash settlements, as presented in the table above, represent realized gains (losses) related to our derivative instruments. In addition to cash settlements, we also recognize fair value changes on our derivative instruments in each reporting period. The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves.

Expenses

	Three Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018		2019		2018		2019		2018
	(in thousands)				(per Boe)				(in thousands)				(per Boe)
EXPENSES:
Lease operating and workover	$	9,911	$	16,952	$	9.07	$	9.57	$	18,901	$	31,760	$	8.27	$	9.07
Gathering and transportation	63		67		0.06		0.04		82		124		0.04		0.04
Severance and other taxes	1,572		2,776		1.44		1.57		3,505		5,638		1.53		1.61
Asset retirement accretion	160		250		0.15		0.14		317		547		0.14		0.16
Depreciation, depletion, and amortization	10,873		16,484		9.95		9.30		22,667		31,697		9.93		9.05
Impairment of oil and gas properties	33,557		—		30.70		—		43,210		—		18.92		—
General and administrative	5,238		5,190		4.80		2.93		11,676		15,047		5.11		4.30
Advisory fees	—		850		—		0.48		—		850		—		0.24
Total expenses	$	61,374	$	42,569	$	56.17	$	24.03	$	100,358	$	85,663	$	43.94	$	24.47

Lease Operating and Workover

Lease operating and workover expenses decreased $7.0 million and $12.9 million, or 41.5% and 40.5%, to $9.9 million and $18.9 million, respectively, for the three and six months ended June 30, 2019. Lower lease operating and work over expense was due to the sale of Anadarko in the second quarter of 2018. Lease operating and workover expenses decreased to $9.07 per Boe and $8.27 per Boe, during the three and six months ended June 30, 2019 from $9.57 per Boe and $9.07 per Boe during the related periods in 2018, decreases of $0.50 per Boe and $0.80 per Boe, or 5.2% and 8.8%, respectively, largely as a result of decreased workover activity during the 2019 period.

Gathering and Transportation

Gathering and transportation expenses decreased 6.0% and 33.9%, respectively, for the three and six months ended June 30, 2019. These decreases in gathering and transportation expenses are due primarily to decreased natural gas production in the Mississippian Lime basin.

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Severance and Other Taxes

	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(in thousands)						(in thousands)
Total oil, NGLs and natural gas sales	$	22,698		$	52,877		$	51,851		$	104,666

Severance taxes	1,569			2,655			3,499			5,336
Ad valorem and other taxes	3			121			6			302
Severance and other taxes	$	1,572		$	2,776		$	3,505		$	5,638
Severance taxes as a percentage of sales	6.9		%	5.0		%	6.7		%	5.1		%
Severance and other taxes as a percentage of sales	6.9		%	5.2		%	6.8		%	5.4		%

Severance and other taxes increased to 6.9% and 6.8% as a percentage of sales for the three and six months ended June 30, 2019, as compared to 5.2% and 5.4% for the three and six months ended June 30, 2018. These increases in severance taxes as a percentage of sales for the 2019 period were primarily the result of legislative changes in the State of Oklahoma which increased the gross production incentive tax rate for wells drilled beginning July 1, 2015, from 2.0% to 5.0%. The initial 2.0% rate is effective for the first thirty-six months of production and moves to 7.0% thereafter. Beginning in July 2018, this legislation increased the incentive tax rate to 5.0% for all new and existing wells that previously qualified for the 2.0% incentive tax rate.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization expense decreased $5.6 million and $9.0 million, or 34.0% and 28.5%, to $10.9 million and $22.7 million, respectively, for the three and six months ended June 30, 2019, compared to $16.5 million and $31.7 million for the three and six months ended June 30, 2018. This decrease in depreciation, depletion and amortization is due primarily to the Anadarko Divestiture in the second quarter of 2018, as well as a decrease in our production as compared to the three and six months ended June 30, 2018. Depreciation, depletion and amortization per Boe increased $0.65 per Boe and $0.88 per Boe during the three and six months ended June 30, 2019, to $9.95 per Boe and $9.93 per Boe from $9.30 per Boe and $9.05 per Boe for the three and six months ended June 30, 2018. Our depletion rate has increased for the three and six months ended June 30, 2019 compared to prior year primarily as a result of decreased proved reserves volumes from the prior year.

Impairment in Carrying Value of Oil and Gas Properties

As we account for our oil and gas properties under the full cost method, we are required to perform a full-cost ceiling test on a quarterly basis. The test establishes a limit (ceiling) on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated DD&A and the related deferred income taxes, may not exceed this “ceiling.” The ceiling limitation is equal to the sum of: (i) the present value of estimated future net revenues from the projected production of proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the balance sheet, calculated using the average oil and natural gas sales price we received as of the first trading day of each month over the preceding twelve months (such average price is held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved and unevaluated properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to impairment expense in the accompanying unaudited interim condensed consolidated statements of operations.

During the three and six months ended June 30, 2019, we recorded impairment charges of $33.6 million and $43.2 million, respectively. These impairment expenses recognized during the periods were primarily due to decreases in the PV-10 value of proven oil and natural gas reserves as a result of lower commodity pricing.

General and Administrative (“G&A”)

G&A expenses remained relatively unchanged during the three months ended June 30, 2019 when compared to the same period in prior year. G&A expenses decreased $3.4 million, or 22.4%, to $11.7 million, for the six months ended June 30, 2019, compared to $15.0 million for the six months ended June 30, 2018. The decrease in G&A expenses during the six months ended June 30, 2019 is primarily due to reductions-in-force that occurred in both the six months ended 2019 and 2018, resulting in a $2.1 million decrease in share based compensation expense in the 2019 period. Additionally, there was a $0.9 million decrease in cost related to our review of various strategic options as compared to the six months ended June 30, 2018.

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Other Income (Expense)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(in thousands)						(in thousands)
OTHER EXPENSE
Interest income	$	4		$	5		$	9		$	24
Interest expense	(1,229		)	(1,308		)	(2,094		)	(3,104		)
Amortization of deferred financing costs	(174		)	(108		)	(348		)	(216		)
Capitalized interest	44			114			146			191
Interest expense—net of amounts capitalized	(1,359		)	(1,302		)	(2,296		)	(3,129		)

Total other income (expense)	$	(1,355	)	$	(1,297	)	$	(2,287	)	$	(3,105	)

Interest Expense

Interest expense was $1.4 million for the three months ended June 30, 2019, an increase of 4.4%, from $1.3 million for the three months ended June 30, 2018. Interest expense was $2.3 million for the six months ended June 30, 2019, a decrease of 26.6%, from $3.1 million for the six months ended June 30, 2018. Our average outstanding balance under our revolving credit facility was $60.6 million and $50.5 million during the three and six months ended June 30, 2019, compared to $65.5 million and $89.2 million for the three and six months ended June 30, 2018. Total interest expense capitalized to oil and gas properties was $0.1 million for the three months ended June 30, 2019 and 2018, respectively. Total interest expense capitalized to oil and gas properties was $0.1 million and $0.2 million for the six months ended June 30, 2019 and 2018, respectively.

Provision for Income Taxes

We recorded no income tax expense or benefit for the three and six months ended June 30, 2019 or 2018, respectively, due to the change in our valuation allowance recorded against our net deferred tax assets. Our valuation allowances were $123.4 million and $119.4 million for the six months ended June 30, 2019 and 2018, respectively.

Liquidity and Capital Resources

Overview

The following table presents a summary of our key financial indicators at the dates presented (in thousands):

	June 30, 2019			December 31, 2018
Cash and cash equivalents	$	4,797		$	11,341
Net working capital (deficit)	(3,495		)	13,946
Total long-term debt	60,559			23,059
Total stockholders’ equity	437,561			541,677
Available borrowing capacity	107,500			145,000

Our decisions regarding capital structure, hedging and drilling are based upon many factors, including anticipated future commodity pricing, expected economic conditions and recoverable reserves.

We anticipate our operating cash flows, cash on hand and cash available from borrowings under the RBL will be our primary sources of liquidity although we may seek to supplement our liquidity through divestitures, additional or refinanced borrowings or debt or equity securities offerings as circumstances and market conditions dictate. We believe the combination of these sources of liquidity will be adequate to fund anticipated capital expenditures, service our existing debt and remain compliant with all other contractual commitments.

Our cash flows from operations are impacted by various factors, the most significant of which is the market pricing for oil, NGLs and natural gas. The pricing for these commodities is volatile, and the factors that impact such market pricing are global and therefore outside of our control. Volatility in commodity prices also impacts estimated quantities of proved reserves. As a result, it is not possible for us to precisely predict our future cash flows from operating revenues due to these market forces.

We enter into hedging activities with respect to a portion of our production to manage our exposure to oil and natural gas price volatility. To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may be prevented from fully realizing the benefits of commodity price increases above the prices established by our hedging contracts. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the contract counterparties fail to perform under the contracts.

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Significant Sources of Capital

RBL

At June 30, 2019, in addition to cash on hand of $4.8 million, we maintained the RBL. The RBL has a current borrowing base of $170.0 million. At June 30, 2019, we had $60.6 million drawn on the RBL and outstanding letters of credit obligations totaling $1.9 million. As a result, at June 30, 2019, we had $107.5 million of availability on the RBL.

The RBL matures on September 30, 2020, and borrowings thereunder are secured by (i) first-priority mortgages on at least 90% of the our oil and gas properties, (ii) all other presently owned or after-acquired property (including but not limited to as-extracted collateral, accounts receivable, inventory, equipment, general intangibles, investment property, intellectual property, real property and the proceeds of the foregoing) and (iii) a perfected pledge on all equity interests. The RBL bears interest at LIBOR plus 4.50% per annum, subject to a 1.00% LIBOR floor. For the six months ended June 30, 2019, the weighted average interest rate was 7.7%, excluding amortization expense of deferred financing costs and commitment fees.

On April 11, 2019, our borrowing base was redetermined at the existing amount of $170.0 million.

Debt Covenants

The RBL as amended, contains various other financial covenants, including an EBITDA to interest expense coverage ratio limitation of not less than 2.50:1.00 and a ratio limitation of Total Net Indebtedness (as defined in the RBL) to EBITDA of not more than 4.00:1.00.

In addition, the RBL contains various other covenants that, among other things, may restrict our ability to: (i) incur additional indebtedness or guarantee indebtedness (ii) make loans and investments; (iii) pay dividends on capital stock and make other restricted payments, including the prepayment or redemption of other indebtedness; (iv) create or incur certain liens; (v) sell, transfer or otherwise dispose of certain assets; (vi) enter into certain types of transactions with our affiliates; (vii) acquire, consolidate or merge with another entity upon certain terms and conditions; (viii) sell all or substantially all of our assets; (ix) prepay, redeem or repurchase certain debt; (x) alter the business we conduct and make amendments to our organizational documents, (xi) enter into certain derivative transactions and (xii) enter into certain marketing agreements and take-or-pay arrangements.

As of June 30, 2019, we were in compliance with our debt covenants.

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our consolidated cash flows from operating, investing and financing activities for the periods presented. For information regarding the individual components of our cash flow amounts, please refer to the unaudited interim condensed consolidated statements of cash flows included under “Part I. Financial Information — Item 1. Financial Statements”of this Quarterly Report.

Our operating cash flows are sensitive to a number of variables, the most significant of which is the volatility of oil and gas prices. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of these commodities. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “Part I. Financial Information — Item 3. Quantitative and Qualitative Disclosures about Market Risk.”

The following information highlights the significant period-to-period variances in our cash flow amounts (in thousands):

	For the Six Months Ended June 30, 2019			For the Six Months Ended June 30, 2018
Net cash provided by operating activities	$	25,318		$	49,292
Net cash used in investing activities	(19,094		)	(11,056		)
Net cash used in financing activities	(12,768		)	(100,478		)
Net change in cash	$	(6,544	)	$	(62,242	)

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Cash flows provided by operating activities

Net cash provided by operating activities was $25.3 million and $49.3 million for the six months ended June 30, 2019 and 2018, respectively. The decrease in net cash provided by operating activities was primarily the result of a $53.4 million decrease in revenues from contracts with customers, partially offset by payments received for the settlement of certain derivatives of $1.0 million as compared to payments for derivative settlements of $3.7 million, a decrease in general and administrative expenses of $3.4 million, a decrease in lease operating and workover expenses of $12.9 million and an increase in the change of working capital of $6.1 million for the six months ended June 30, 2019 as compared to the six months ended June 30, 2018.

Cash flows used in investing activities

Net cash used in investing activities were $19.1 million and $11.1 million for the six months ended June 30, 2019 and 2018, respectively. Substantially all of our capital spend is invested into our Mississippi Lime asset, and the decrease year-over-year, after consideration of the sale of our Anadarko Basin assets in May of 2018, is the result of our decision to pause drilling beginning in the fourth quarter of 2018.

Cash flows used in financing activities

Net cash used in financing activities was $12.8 million and $100.5 million for the six months ended June 30, 2019 and 2018, respectively. During the six months ended June 30, 2019, we drew down $37.5 million, net on the RBL, as well as, repurchased and retired $50.0 million of common stock as a result of the Tender Offer noted in “Part I. Financial Information — Note 11. Equity and Share-Based Compensation” of this Quarterly Report.

Critical Accounting Policies and Estimates

When used in the preparation of our unaudited interim condensed consolidated financial statements, estimates are based on our current knowledge and understanding of the underlying facts and circumstances and may be revised as a result of actions we take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our condensed consolidated financial position, results of operations and cash flows.

A discussion of our critical accounting policies and estimates is included in our Annual Report on Form 10-K for the year ended December 31, 2018. There have been no changes to our critical accounting policies other than discussed below.

Leases

We determine if an arrangement is a lease at inception of the arrangement. To the extent that we determine an arrangement represents a lease, we classify that lease as an operating lease or a finance lease. We capitalize operating and finance leases on our unaudited interim condensed consolidated balance sheets through a ROU asset and a corresponding lease liability. ROU assets represent our right to use an underlying asset for the lease term, and lease liabilities represent our obligation to make lease payments arising from the lease.

Operating leases are included in ROU lease assets, and lease liabilities in our unaudited interim condensed consolidated balance sheets. ROU lease assets and lease liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. The ROU lease asset also includes any lease payments made to the lessor prior to lease commencement, less any lease incentives, and initial direct costs incurred. Lease expense for operating lease payments are recognized on a straight-line basis over the lease term.

As of June 30, 2019, we had no leases classified as finance leases.

Nature of Leases

In support of our operations, we lease certain office space, field offices, office equipment, compressors, other production equipment and fleet vehicles under cancelable and non-cancelable contracts. A more detailed description of our material lease types is included below.

Corporate and Field Offices

We enter into long-term contracts to lease corporate and field office space in support of company operations. These contracts are generally structured with an initial non-cancelable term of three to five years. To the extent that our corporate and field office contracts include renewal options, we evaluate whether we are reasonably certain to exercise those options on a contract by contract basis based on expected future office space needs, market rental rates, drilling plans and other factors. We have further determined that our current corporate and field office leases represent operating leases.

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Compressors

We rent compressors from third parties in order to facilitate the downstream movement of our production to market. Our compressor arrangements are typically structured with a non-cancelable primary term of one to twenty-four months and often continue thereafter on a month-to-month basis subject to termination by either party with thirty days notice. We have concluded that our compressor rental agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease without incurring a significant penalty. As a result, enforceable rights and obligations do not exist under the rental agreement subsequent to the primary term.

To the extent that our compressor rental arrangements have a primary term of twelve-months or less, we have elected to apply the practical expedient for short-term leases. For those short-term compressor contracts, we do not apply the lease recognition requirements, and we recognize lease payments related to these arrangements in profit or loss on a straight-line basis over the lease term. Refer to “Practical Expedients & Accounting Policy Elections” below for additional detail.

Other Production Equipment

We rent other production equipment from third party vendors to be used in our production operations. These arrangements are typically structured on a month-to-month basis subject to termination by either party with thirty days notice. We have concluded that we are not reasonably certain of executing the month-to-month renewal options beyond a twelve-month period based on the historical term for which we have used other production equipment, and, therefore, our other equipment agreements represent operating leases with a lease term up to twelve-months.

We have further elected to apply the practical expedient for short-term leases to our other production equipment contracts. Accordingly, we do not apply the lease recognition requirements to these contracts, and we recognize lease payments related to these arrangements in profit or loss on a straight-line basis over the lease term. Refer to “Practical Expedients & Accounting Policy Elections” below for additional detail.

Fleet Vehicles

We execute fleet vehicle leases with a third-party vendor in support of our day-to-day drilling and production operations. Our vehicle leases are typically structured with a term of a minimum of 367 days for passenger and light duty vehicles and a minimum of 24 months for commercial vehicles and continue thereafter on a month-to-month basis subject to termination by either party within thirty days notice. We have concluded that our fleet vehicle leases represent operating leases.

Significant Judgments

Transportation, Gathering and Processing Arrangements

As the Company does not utilize substantially all of the underlying pipeline, gathering system or processing facilities, we have concluded that those underlying assets do not meet the definition of an identified asset.

Discount Rate

Our leases typically do not provide an implicit rate, and thus, we are required to use our incremental borrowing rate in determining the present value of lease payments based on the information available at commencement date. Our incremental borrowing rate reflects the rate of interest that we would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. In order to determine our incremental borrowing rate, we utilized our current credit rating as well as best available market data, which includes public bond information for publicly traded upstream energy companies with similar credit ratings, to estimate our unsecured borrowing rate and applied adjustments to that rate to account for the effect of collateral.

The Company has determined the discount rate as of January 1, 2019 using end of day December 31, 2018 market data. This discount rate will be used at transition to ASC 842 as well as all new leases executed within 2019. The Company intends to update the discount rate annually thereafter on January 1 to be used for all new leases within the year (for example, the discount rate will be updated as of January 1, 2020 to be applied to all new leases in 2020). In the event a material lease is executed within a fiscal year or there have been material changes in the market that would impact the Company’s discount rate, the Company will evaluate whether an intra-year update of the discount rate is required.

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Practical Expedients & Accounting Policy Elections

Certain of our lease agreements include lease and non-lease components. For all current asset classes with multiple component types, we have utilized the practical expedient that exempts us from separating lease components from non-lease components. Accordingly, we account for the lease and non-lease components in an arrangement as a single lease component.

In addition, for all of our asset classes, we have made an accounting policy election not to apply the lease recognition requirements to our short-term leases (that is, a lease that, at commencement, has a lease term of 12 months or less, including renewal options expected to be exercised, and does not include an option to purchase the underlying asset that we are reasonably certain to exercise). Accordingly, we recognize lease payments related to our short-term leases in profit or loss on a straight-line basis over the lease term. To the extent that there are variable lease payments, we recognize those payments in profit or loss in the period in which the obligation for those payments is incurred. Refer to “Nature of Leases” above for further information regarding those asset classes that include material short-term leases.

Recent Accounting Pronouncements Adopted During the Period

In July 2017, the FASB issued ASU 2017-11, “Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480), and Derivatives and Hedging (Topic 815)”. ASU 2017-11 changes the classification analysis of certain equity-linked financial instruments (or embedded features) with down round features. The amendments require entities that present earnings per share (“EPS”) in accordance with Topic 260 to recognize the effect of the down round feature when triggered with the effect treated as a dividend and as a reduction of income available to common shareholders in basic EPS. The new standard is effective for us for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The adoption of ASU 2017-11 did not have a material impact on its financial position, results of operations or cash flows.

In June 2018, the FASB issued ASU 2018-07, “Compensation - Stock Compensation (Topic 718) — Improvements to Nonemployee Share-Based Payment Accounting”. ASU 2018-07 expands the scope of Topic 718 to include share-based payments issued to non-employees for goods and services. Consequently, the accounting for share-based payments to non-employees and employees will be substantially aligned. The new standard is effective for us for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The adoption of ASU 2018-07 did not have a material impact on its financial position, results of operations or cash flows.

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842)”. ASU 2016-02 establishes a right-of-use (“ROU”) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. We adopted ASU 2016-02 using the modified retrospective transition approach. See “Part I. Financial Information — Item 1. Financial Statements Notes to the Unaudited Interim Condensed Consolidated Financial Statements— Note 3. Impact of ASC 842 Adoption”.

Recent Accounting Pronouncements Issued But Not Yet Adopted

In June 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments”. ASU 2016-13 replaces the incurred loss model with an expected loss model, which is referred to as the current expected credit loss (“CECL”) model. The CECL model is applicable to the measurement of credit losses on financial assets measured at amortized cost, including but not limited to trade receivables. The ASU is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. We are still performing our evaluation of Update 2016-13, but do not believe it will have a material impact on our consolidated financial statements at this time.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative instruments.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The disclosures are not meant to be precise indicators of expected future losses or gains, but rather indicators of reasonably possible losses or gains. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. These derivative instruments are discussed in “Part I. Financial Information — Item 1. Financial Statements — Notes to the Unaudited Interim Condensed Consolidated Financial Statements — Note 5. Risk Management and Derivative Instruments.”

Commodity Price Exposure

We are exposed to market risk as the prices of oil, NGLs and natural gas fluctuate due to changes in supply and demand. To partially reduce price risk caused by these market fluctuations, we have hedged and in the long-term, expect to hedge, a significant portion of our future production.

We utilize derivative financial instruments to manage risks related to changes in oil and natural gas prices. At June 30, 2019, we utilized fixed price swaps and three-way collars to reduce the volatility of oil and natural gas prices on a portion of our future expected production.

For derivative instruments recorded at fair value, the credit standing of our counterparties is analyzed and factored into the fair value amounts recognized on the balance sheet.

The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. At June 30, 2019, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net liability positions by the following amounts:

	10% Increase			10% Decrease
	(in thousands)
Gain (loss):
Gas derivatives	$	(621	)	$	606
Oil derivatives	$	(2,918	)	$	2,395

Interest Rate Risk

At June 30, 2019, we had indebtedness outstanding under our RBL of $60.6 million, which bears interest at LIBOR plus 4.50% per annum, subject to a 1.00% LIBOR floor. Assuming the RBL is fully drawn, a one percent increase in interest rates for the three months ended June 30, 2019, would have resulted in a $1.7 million increase in annual interest cost, before capitalization.

At June 30, 2019, we did not have any interest rate derivatives in place and have not historically utilized interest rate derivatives. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

During the period covered by this report, our management carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Our disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports we file with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to our management, including our President, Chief Executive Officer and Director and our Vice President and Chief Accounting Officer, as appropriate, to allow timely decisions regarding required disclosures. Based on that evaluation, our President, Chief Executive Officer and Director and our Vice President and Chief Accounting Officer concluded that as of June 30, 2019, these disclosure controls and procedures were effective and ensured that the information required to be disclosed in our reports filed with the SEC is recorded, processed, summarized and reported on a timely basis.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2019, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings

From time to time, we are party to various legal proceedings arising in the ordinary course of business. Although we cannot predict the outcomes of any such legal proceedings, our management believes that the resolution of currently pending legal actions will not have a material adverse effect on our business, results of operations and financial condition. See “Part I. Financial Information — Item 1. Financial Statements — Notes to the Unaudited Interim Condensed Consolidated Financial Statements — Note 15. Commitments and Contingencies”, which is incorporated in this item by reference.

Item 1A. Risk Factors

Our business faces many risks. Any of the risks discussed in this Quarterly Report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.

There have been no material changes to the risks described in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2018, filed with the SEC on March 14, 2019.

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

The following table provides information regarding the purchase of our common stock made during the second quarter of 2019. Shares purchased represent the net settlement on vesting of restricted stock necessary to satisfy the minimum statutory withholding requirements.

Period	Total Number of Shares Purchased	Average Price Paid Per Share
April 1, 2019 — April 30, 2019	518	$	10.34
May 1, 2019 — May 31, 2019	—	$	—
June 1, 2019 — June 30, 2019	—	$	—
Total	518	$	10.34

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

Exhibits included in this Quarterly Report are listed in the Exhibit Index and incorporated herein by reference.

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EXHIBIT INDEX

Exhibit Number		Exhibit Description
2.1		Agreement and Plan of Merger, dated May 5, 2019, by and among Amplify Energy Corp., Midstates Petroleum Company, Inc. and Midstates Holdings, Inc. (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on May 6, 2019, and incorporated herein by reference).

3.1		Second Amended and Restated Certificate of Incorporation of Midstates Petroleum Company, Inc. (filed as Exhibit 3.1 to the Company’s Registration Statement on Form 8-A filed on October 21, 2016, and incorporated herein by reference).

3.2		Amended and Restated Bylaws of Midstates Petroleum Company, Inc. (filed as Exhibit 3.2 to the Company’s Registration Statement on Form 8-A filed on October 21, 2016, and incorporated herein by reference).

10.1		Voting and Support Agreement, dated May 5, 2019, by and between Midstates Petroleum Company, Inc. and Fir Tree Capital Management LP (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 6, 2019, and incorporated herein by reference).

10.2		Voting and Support Agreement, dated May 5, 2019, by and between Midstates Petroleum Company, Inc. and Brigade Capital Management, LP (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on May 6, 2019, and incorporated herein by reference).

10.3		Voting and Support Agreement, dated May 5, 2019, by and between Midstates Petroleum Company, Inc. and Axys Capital Income Fund, LLC (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on May 6, 2019, and incorporated herein by reference).

10.4		Voting and Support Agreement, dated May 5, 2019, by and between Midstates Petroleum Company, Inc. and Cross Sound Management LLC (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on May 6, 2019, and incorporated herein by reference).

31.1*		Sarbanes-Oxley Section 302 certification of Principal Executive Officer.

31.2*		Sarbanes-Oxley Section 302 certification of Principal Financial Officer.

32.1**		Sarbanes-Oxley Section 906 certification of Principal Executive Officer and Principal Financial Officer.

101.INS*		XBRL Instance Document.

101.SCH*		XBRL Schema Document.

101.CAL*		XBRL Calculation Linkbase Document.

101.DEF*		XBRL Definition Linkbase Document.

101.LAB*		XBRL Labels Linkbase Document

101.PRE*		XBRL Presentation Linkbase Document.

*		Filed herewith
**		Furnished 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 thereunto duly authorized.

	MIDSTATES PETROLEUM COMPANY, INC.

Dated: August 5, 2019	/s/ DAVID J. SAMBROOKS
	David J. Sambrooks
	President, Chief Executive Officer and Director
	(Principal Executive Officer)

Dated: August 5, 2019	/s/ RICHARD W. MCCULLOUGH
	Richard W. McCullough
	Vice President and Chief Accounting Officer
	(Principal Financial Officer and Principal Accounting Officer)