Amplify Energy Corp. - Quarter Report: 2016 March (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2016

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, Suite 1000
Tulsa, Oklahoma		74103
(Address of principal executive offices)		(Zip Code)

(918) 947-8550

(Registrant’s telephone number, including area code)

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

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

Large accelerated filer o		Accelerated filer o
Non-accelerated filer x		Smaller reporting company o
(Do not check if a smaller reporting company)

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

The number of shares outstanding of our common stock at May 9, 2016 is shown below:

Class		Number of shares outstanding
Common stock, $0.01 par value		10,772,292

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MIDSTATES PETROLEUM COMPANY, INC.

QUARTERLY REPORT ON

FORM 10-Q

FOR THE THREE MONTHS ENDED MARCH 31, 2016

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	Page

Glossary of Oil and Natural Gas Terms	3

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements	4
Condensed Consolidated Balance Sheets at March 31, 2016 and December 31, 2015 (unaudited)	4
Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2016 and 2015 (unaudited)	5
Condensed Consolidated Statements of Changes in Stockholders’ Equity/(Deficit) for the Three Months Ended March 31, 2016 and 2015 (unaudited)	6
Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2016 and 2015 (unaudited)	7

Notes to Unaudited Condensed Consolidated Financial Statements	8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	21

Item 3. Quantitative and Qualitative Disclosures About Market Risk	33

Item 4. Controls and Procedures	34

PART II - OTHER INFORMATION

Item 1. Legal Proceedings	35

Item 1A. Risk Factors	35

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	39

Item 3. Defaults upon Senior Securities	39

Item 4. Mine Safety Disclosures	39

Item 5. Other Information	39

Item 6. Exhibits	39

SIGNATURES	40

EXHIBIT INDEX	41

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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.

Mcf: One thousand cubic feet of natural gas.

MMBoe: One million barrels of oil equivalent.

MMBtu: One million British thermal units.

Net acres: The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

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 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 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 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 natural gas and/or oil 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, 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)

	March 31, 2016			December 31, 2015
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	301,426		$	81,093
Accounts receivable:
Oil and gas sales	29,919			33,656
Joint interest billing	9,674			12,503
Other	585			17,506
Other current assets	3,098			1,044
Total current assets	344,702			145,802

PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of full-cost accounting	3,723,879			3,666,403
Other property and equipment	13,488			14,798
Less accumulated depreciation, depletion, amortization and impairment	(3,308,871		)	(3,157,332		)
Net property and equipment	428,496			523,869

OTHER NONCURRENT ASSETS	9,647			9,496

TOTAL	$	782,845		$	679,167

LIABILITIES AND STOCKHOLDERS’ EQUITY/(DEFICIT)
CURRENT LIABILITIES:
Accounts payable	$	3,238		$	1,904
Accrued liabilities	127,091			91,712
Debt classified as current less unamortized debt issuance costs (Note 9)	2,134,771			1,890,944
Total current liabilities	2,265,100			1,984,560

LONG-TERM LIABILITIES:
Asset retirement obligations	19,436			18,708
Other long-term liabilities	2,819			1,965
Total long-term liabilities	22,255			20,673

COMMITMENTS AND CONTINGENCIES (Note 13)

STOCKHOLDERS’ EQUITY/(DEFICIT):
Preferred stock, $0.01 par value, 49,675,000 shares authorized; no shares issued or outstanding	—			—
Common stock, $0.01 par value, 100,000,000 shares authorized; 10,917,155 shares issued and 10,773,468 shares outstanding at March 31, 2016 and 10,962,105 shares issued and 10,865,814 shares outstanding at December 31, 2015	109			110
Treasury stock, at cost	(3,133		)	(3,081		)
Additional paid-in-capital	889,130			888,247
Retained deficit	(2,390,616		)	(2,211,342		)
Total stockholders’ equity/(deficit)	(1,504,510		)	(1,326,066		)

TOTAL	$	782,845		$	679,167

The accompanying notes are an integral part of these unaudited 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 March 31,
	2016			2015
REVENUES:
Oil sales	$	30,138		$	59,257
Natural gas liquid sales	7,063			11,010
Natural gas sales	13,942			19,172
Gains on commodity derivative contracts - net	—			21,372
Other	818			387

Total revenues	51,961			111,198

EXPENSES:
Lease operating and workover	15,761			23,262
Gathering and transportation	4,421			3,438
Severance and other taxes	1,504			3,565
Asset retirement accretion	420			445
Depreciation, depletion, and amortization	24,835			58,428
Impairment in carrying value of oil and gas properties	127,734			174,667
General and administrative	11,288			11,654
Advisory fees	1,117			1,743
Other	—			97

Total expenses	187,080			277,299

OPERATING LOSS	(135,119		)	(166,101		)

OTHER INCOME (EXPENSE):
Interest income	57			9
Interest expense — net of amounts capitalized	(44,212		)	(36,503		)

Total other expense	(44,155		)	(36,494		)

LOSS BEFORE TAXES	(179,274		)	(202,595		)

Income tax benefit	—			9,041

NET LOSS	$	(179,274	)	$	(193,554	)

Preferred stock dividend	—			(131		)
Participating securities - Series A Preferred Stock	—			—
Participating securities - Non-vested Restricted Stock	—			—

NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(179,274	)	$	(193,685	)

Basic and diluted net loss per share attributable to common shareholders	$	(16.88	)	$	(28.80	)
Basic and diluted weighted average number of common shares outstanding	10,621			6,726

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

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MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY/(DEFICIT)

(Unaudited)

(In thousands)

	Series A Preferred Stock		Common Stock			Treasury Stock			Additional Paid-in- Capital		Retained Deficit			Total Stockholders’ Equity/(Deficit)
Balance as of December 31, 2015	$	—	$	110		$	(3,081	)	$	888,247	$	(2,211,342	)	$	(1,326,066	)
Share-based compensation	—		(1		)	—			883		—			882
Acquisition of treasury stock	—		—			(52		)	—		—			(52		)
Net loss	—		—			—			—		(179,274		)	(179,274		)
Balance as of March 31, 2016	$	—	$	109		$	(3,133	)	$	889,130	$	(2,390,616	)	$	(1,504,510	)

	Series A Preferred Stock		Common Stock		Treasury Stock			Additional Paid-in- Capital		Retained Deficit			Total Stockholders’ Equity/(Deficit)
Balance as of December 31, 2014	$	3	$	70	$	(2,592	)	$	882,528	$	(414,147	)	$	465,862
Share-based compensation	—		2		—			1,301		—			1,303
Acquisition of treasury stock	—		—		(305		)	—		—			(305		)
Net loss	—		—		—			—		(193,554		)	(193,554		)
Balance as of March 31, 2015	$	3	$	72	$	(2,897	)	$	883,829	$	(607,701	)	$	273,306

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

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MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Three Months Ended March 31,
	2016			2015

CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(179,274	)	$	(193,554	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Gains on commodity derivative contracts — net	—			(21,372		)
Net cash received for commodity derivative contracts	—			52,608
Asset retirement accretion	420			445
Depreciation, depletion, and amortization	24,835			58,428
Impairment in carrying value of oil and gas properties	127,734			174,667
Share-based compensation, net of amounts capitalized to oil and gas properties	685			801
Deferred income taxes	—			(9,041		)
Amortization of deferred financing costs	1,551			1,869
Paid in kind interest expense	2,648			—
Amortization of deferred gain on debt restructuring	(6,276		)	—
Operating lease abandonment	3,310			—
Change in operating assets and liabilities:
Accounts receivable — oil and gas sales	3,457			27,572
Accounts receivable — JIB and other	16,891			13,475
Other current and noncurrent assets	(3,764		)	(1,089		)
Accounts payable	267			322
Accrued liabilities	37,627			8,106
Other	(256		)	(220		)

Net cash provided by operating activities	$	29,855		$	113,017

CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment	(58,654		)	(111,167		)

Net cash used in investing activities	$	(58,654	)	$	(111,167	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving credit facility	249,184			—
Deferred financing costs	—			(1,161		)
Acquisition of treasury stock	(52		)	(305		)

Net cash provided by (used in) financing activities	$	249,132		$	(1,466	)

NET INCREASE IN CASH AND CASH EQUIVALENTS	220,333			384

Cash and cash equivalents, beginning of period	$	81,093		$	11,557

Cash and cash equivalents, end of period	$	301,426		$	11,941

SUPPLEMENTAL INFORMATION:
Non-cash transactions — investments in property and equipment accrued - not paid	$	15,563		$	71,900
Cash paid for interest, net of capitalized interest of $1.0 million for the three months ended March 31, 2015 (no capitalized interest for the three months ended March 31, 2016)	942			2,321

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

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

1. Organization and Business

Midstates Petroleum Company, Inc. (“Midstates”), through its wholly owned subsidiary Midstates Petroleum Company LLC, engages in the business of exploring, 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”), which was previously a wholly owned subsidiary of Midstates Petroleum Holdings LLC (“Holdings LLC”). The terms “Company,” “we,” “us,” “our,” and similar terms when used in the present tense, prospectively or for historical periods since April 25, 2012, refer to Midstates Petroleum Company, Inc. and Midstates Sub, unless the context indicates otherwise.

The Company conducts oil and gas operations and owns and operates oil and gas properties in Oklahoma, Texas and Louisiana. The Company operates a significant portion of its oil and natural gas properties and is engaged in the exploration, development and production of oil, NGLs and natural gas. The Company’s management evaluates performance based on one reportable segment as all its operations are located in the United States and, therefore, it maintains one cost center.

2. Chapter 11 Proceedings, Liquidity and Ability to Continue as a Going Concern

Voluntary Reorganization Under Chapter 11

On April 30, 2016, Midstates and Midstates Sub (collectively, the “Debtors”), filed voluntary petitions (the “Bankruptcy Petitions”) for reorganization under the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Debtors’ Chapter 11 cases (the “Chapter 11 Cases”) are being jointly administered under the case styled In re Midstates Petroleum Company, Inc., et al, No. 16-32237. The Debtors will continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The Company will account for the bankruptcy in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852, “Reorganizations”, beginning with the quarterly period ended June 30, 2016.

By certain “first day” motions filed in the Chapter 11 Cases, the Company obtained Bankruptcy Court approval to, among other things and subject to the terms of the orders entered by the Bankruptcy Court, pay employee wages, health benefits and certain other employee obligations, pay certain lienholders or prospective lienholders and forward funds to third parties, including royalty holders and other working interest owners. As a result, the Company is not only able to conduct normal business activities and pay all associated obligations for the period following its bankruptcy filing, it is also authorized to pay and has paid pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders or prospective lienholders and funds belonging to third parties. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of business require the prior approval of the Bankruptcy Court.

On April 30, 2016, and prior to filing the Bankruptcy Petitions, the Debtors entered into a Plan Support Agreement (the “Plan Support Agreement”) with the following parties:

· Approximately 80.0% of the lenders (collectively, the “Consenting Credit Facility Lenders”) under the Debtors’ secured revolving first lien credit facility (the “Credit Facility”);

· Approximately 74.0% of the holders (collectively, the “Consenting Second Lien Noteholders”) of the Debtors’ 10.0% Second Lien Senior Secured Notes Due 2020 (the “Second Lien Notes”); and

· Approximately 77.0% of the holders (collectively, the “Consenting Third Lien Noteholders”, and together with the Consenting Credit Facility Lenders and Consenting Second Lien Noteholders, the “Plan Support Agreement Parties”) of the Debtors’ 12.0% Third Lien Notes due 2020 (the “Third Lien Notes”).

The restructuring transactions contemplated by the Plan Support Agreement will be effectuated through a joint prearranged plan of reorganization (as may be amended, restated, supplemented, or otherwise modified from time to time, the “Plan”) in accordance with the Plan Support Agreement.

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The key terms of the restructuring, as contemplated in the Plan Support Agreement, are as follows:

· Substantial Deleveraging of the Balance Sheet: The Plan Support Agreement contemplates (i) the permanent pay-down of $82.0 million of the Company’s Credit Facility, which will be replaced with a $170.0 million exit facility (the “Exit Facility”) upon emergence, (ii) the pay-down of up to $60.0 million of the Company’s Second Lien Notes in cash, and (iii) the conversion into equity of all of the Company’s remaining debt that is junior to the Credit Facility.

· Intercreditor Settlement: Equity distributions among the noteholder classes will be made in accordance with an intercreditor settlement among the Plan Support Agreement Parties (the “Settlement”), which provides for a valuation allocation with respect to the Company’s assets that are encumbered or unencumbered as of the Petition Date, such that the equity of the reorganized Company will be allocated 98.8% on account of prepetition collateral and 1.2% on account of unencumbered assets.

· Credit Facility Claims: Holders of allowed claims under the Credit Facility (the “Credit Facility Claims”) will receive their pro rata share of approximately $82.0 million in cash and the Credit Facility will be replaced by the Exit Facility.

· Second Lien Notes Claims: Holders of allowed claims under the Second Lien Notes (the “Second Lien Notes Claims”) will receive their pro rata share of (a) 96.3% of the equity of the reorganized Company (subject to increase to 98.8% if the Third Lien Intercreditor Settlement (as defined below) is not approved as part of the Plan) and (b) cash payments equal to the amount of cash the Company holds at emergence, less cash distributions and reserves to be funded under the Plan (including the cash payment to, and a $40.0 million cash collateral account for the benefit of, the Consenting Credit Facility Lenders) and $70.0 million, subject to a maximum cash distribution to Consenting Second Lien Noteholders of $60.0 million.

· Third Lien Notes Claims: Holders of allowed claims under the Third Lien Notes (the “Third Lien Notes Claims”) will receive their pro rata share of 2.5% of the equity in the reorganized Company and warrants to acquire 15% of such equity (the “Third Lien Intercreditor Settlement”). These warrants will carry a strike price based on an equity valuation for the Company of $600.0 million and will expire 42 months after the Company emerges from the Chapter 11 Cases.

· Unsecured Claims: Holders (the “Unsecured Noteholders”) of allowed claims under the Debtors’ 10.75% Senior Unsecured Notes due 2020 (the “2020 Notes Claims”), the holders of allowed claims under the 9.25% Senior Unsecured Notes due 2021 (the “2021 Notes Claims,” and together with the 2020 Notes Claims, the “Unsecured Notes Claims”), and the Holders of other unsecured claims will receive their pro rata share of 1.2% of the equity in the reorganized Company (the “Unencumbered Assets Equity Distribution”).

· Existing Equity: All existing equity interests of the Company will be extinguished, and existing equity holders would not receive consideration in respect of their equity interests.

· Exit Facility: The Exit Facility will have an initial borrowing base of $170.0 million with no borrowing base redeterminations to occur until April 2018 (provided certain conditions are met) and semiannual borrowing base redeterminations thereafter. The Exit Facility will mature on the earlier of September 30, 2020, or 4 years from the Plan effective date, with interest payable at LIBOR plus 4.50% per annum, subject to a 1.00% LIBOR floor. The Exit Facility will be secured by first priority mortgages on at least 95.0% of the proved oil and gas reserves and all other oil and gas properties included in the most recently delivered reserve report, pledges of capital stock, a first priority security interest in the cash, cash equivalents, deposit, securities and other similar accounts, and a first-priority perfected security interest in substantially all other tangible and intangible assets (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). The Exit Facility is subject to a variety of other terms and conditions including conditions precedent to funding, financial covenants, and various other covenants and representations and warranties.

· Management Incentive Plan: The Plan will provide for the establishment of a management equity incentive plan (the “MIP”) under which 10% of the equity in the reorganized Company (on a fully-diluted/fully-distributed basis) will be reserved for grants made from time to time to the directors, officers, and other members of management of the reorganized Company. The remainder of compensation will be negotiated in connection with the Plan.

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· Releases: The Plan shall provide for release, exculpation, and injunction provisions, including customary carve-outs, to the fullest extent permitted by applicable law and consistent with the terms of the Plan Support Agreement.

· Corporate Governance: The corporate governance documents of the reorganized Company shall be subject to the consent of the Consenting Second Lien Noteholders. If the settlement is approved, the initial board of directors of the reorganized Company shall be appointed by the parties to the Plan Support Agreement who hold, in the aggregate, at least 50.1% in principal amount outstanding of the Second Lien Notes held by all parties to the Plan Support Agreement.

Subject to certain exceptions, under the Bankruptcy Code, the filing of the Bankruptcy Petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the date of the Bankruptcy Petitions. Accordingly, although the filing of the Bankruptcy Petitions triggered defaults on the Debtors’ debt obligations, creditors are stayed from taking any actions against the Debtors as a result of such defaults, subject to certain limited exceptions permitted by the Bankruptcy Code. Absent an order of the Bankruptcy Court, substantially all of the Debtors’ prepetition liabilities are subject to discharge under the Bankruptcy Code.

Under the priority requirements established by the Bankruptcy Code, unless creditors agree otherwise, pre-petition liabilities to creditors and post-petition liabilities must be satisfied in full before the holders of the Company’s existing common stock are entitled to receive any distribution or retain any property under a plan of reorganization. The ultimate recovery to creditors and/or stockholders, if any, will not be determined until confirmation and implementation of the Plan or an alternative transaction. While the Company is seeking to implement the Plan on the terms summarized above, the outcome of the Chapter 11 Cases remains uncertain at this time and, as a result, the Company cannot accurately estimate the amounts or value of distributions that creditors and stockholders may receive. The Plan Support Agreement provides that stockholders will receive no distribution on account of their interests.

For the duration of the Company’s Chapter 11 proceedings, the Company’s operations and ability to develop and execute its business plan are subject to the risks and uncertainties associated with the Chapter 11 process. As a result of these risks and uncertainties, the number of the Company’s outstanding shares and shareholders, assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 Cases, and the description of the Company’s operations, properties and capital plans included herein may not accurately reflect its operations, properties and capital plans following the Chapter 11 process.

In particular, subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors of performing their future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases may assert unsecured claims in the Bankruptcy Court against the applicable Debtors’ estate for such damages. Generally, the assumption of an executory contract or unexpired lease requires the Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with the Debtors in the interim financial statements, including where applicable a quantification of the Company’s obligations under any such executory contract or unexpired lease with the Debtors is qualified by any overriding rejection rights the Company has under the Bankruptcy Code. Further, nothing herein is or shall be deemed (i) an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the Debtors expressly preserve all of their rights with respect thereto, (ii) a waiver of any rights, claims, actions or defenses that the Company may have in respect of any given executory contract or unexpired leases or (iii) an affirmation by the Company to assume any given executory contract or unexpired lease.

There can be no assurances regarding the Company’s ability to successfully develop, confirm and consummate the Plan as contemplated by the Plan Support Agreement or any other plans of reorganization or other alternative restructuring transactions.

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Liquidity and Ability to Continue as a Going Concern

The Company’s filing of the Bankruptcy Petitions described above accelerated the Company’s obligations under the Credit Facility, the Second Lien Notes, the Third Lien Notes, the 10.75% Senior Unsecured Notes due 2020 (the “2020 Senior Notes”) and the 9.25% Senior Unsecured Notes due 2021 (the “2021 Senior Notes” together with the 2020 Senior Notes, the Second Lien Notes and the Third Lien Notes, the “Senior Notes”). The Company classified all debt as current at December 31, 2015 due to the receipt of a going concern explanatory paragraph from the Company’s predecessor independent registered public accounting firm on the Company’s consolidated financial statements for the year ended December 31, 2015 creating an event of default under the Credit Facility that, together with a projected additional debt covenant violation, and a resulting lack of liquidity, raised substantial doubt about its ability to continue as a going concern. All debt of the Company continued to be classified as current at March 31, 2016. If the Company cannot continue as a going concern, adjustments to the carrying values and classification of its assets and liabilities and the reported income and expenses could be required and could be material.

In February 2016, the Company borrowed approximately $249.2 million under the Credit Facility, which represented the remaining undrawn amount that was available under the Credit Facility. As of March 31, 2016, the total outstanding principal amount of the Company’s debt obligations was approximately $2.1 billion, consisting of approximately $249.2 million of borrowings under the Credit Facility (excluding outstanding letters of credit), $293.6 million of 2020 Senior Notes, $347.7 million of 2021 Senior Notes, $625.0 million of Second Lien Notes and $529.7 million of Third Lien Notes. In addition, as of March 31, 2016, the Company had approximately $2.8 million of outstanding letters of credit under the Credit Facility. On April 1, 2016, the Company elected to utilize the 30 day grace period provided under the indenture to the 2020 Senior Notes with respect to an interest payment of approximately $15.8 million due on that date.

Additionally, on April 1, 2016, the Company received a notice of the result of a scheduled borrowing base redetermination from the administrative agent and the lenders under the Credit Facility that reduced its borrowing base to $170.0 million. As of April 1, 2016, the Company had approximately $252.0 million in aggregate outstanding borrowings and letter of credit obligations under the Credit Facility, resulting in a borrowing base deficiency of approximately $82.0 million. Under the terms of the Credit Facility, the Company was required to cure the borrowing base deficiency within 30 days after receipt of such notice.

The Company’s filing on April 30, 2016 of the Bankruptcy Petitions described herein constitutes an event of default that accelerated the Company’s obligations under the Credit Facility and the Senior Notes. Additionally, other events of default, including cross-defaults, are present, including the failure to make the April 1, 2016 interest payment on the 2020 Senior Notes within the 30 day grace period, the failure to cure the borrowing base deficiency within the prescribed period and the receipt of a going concern explanatory paragraph from the Company’s predecessor independent registered public accounting firm on the Company’s consolidated financial statements for the year ended December 31, 2015. As discussed above, subject to certain limited exceptions, the filing of the Company’s Bankruptcy Petitions automatically enjoined or stayed the Company’s creditors from taking any actions against the Company as a result of such defaults.

The accompanying condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The condensed consolidated financial statements do not reflect any adjustments that might result from the outcome of the uncertainties as discussed above.

3. Summary of Significant Accounting Policies

Basis of Presentation

These interim financial statements are unaudited and 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, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“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, 2015 included in the Company’s Annual Report on Form 10-K as filed with the SEC on March 30, 2016.

All intercompany transactions have been eliminated in consolidation. In the opinion of the Company’s management, the accompanying unaudited 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 condensed consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the 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.

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Recently Issued Standards Not Yet Adopted

In May 2014, the FASB issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”). ASU 2014-09 provides guidance concerning the recognition and measurement of revenue from contracts with customers. The objective of ASU 2014-09 is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. ASU 2014-09 requires an entity to (i) identify the contract(s) with a customer, (ii) identify the performance obligations in the contract(s), (iii) determine the transaction price, (iv) allocate the transaction price to the performance obligations in the contract(s), and (v) recognize revenue when, or as, the entity satisfies a performance obligation. ASU 2014-09 will be effective for the Company beginning on January 1, 2018, including interim periods within that reporting period, considering the one year deferral provided by ASU 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.” The standard permits the use of either the retrospective or cumulative effect transition method and early adoption is permitted. The Company has not selected a transition method and is evaluating the impact this standard will have on its condensed consolidated financial statements and related disclosures.

In February 2016, the FASB issued ASU 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. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The new standard is effective for the Company beginning on January 1, 2019, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Company is currently evaluating the impact this standard will have on its condensed consolidated financial statements and related disclosures.

In March 2016, the FASB issued ASU 2016-09, “Compensation — Stock Compensation (Topic 718)” (“ASU 2016-09”). ASU 2016-09 simplifies how certain aspects of share-based payments to employees are recorded. ASU 2016-09 requires that entities recognize the income tax effects of awards in the income statement when the awards vest or are settled, provides guidance on the classification of certain aspects of share-based payments on the statement of cash flows, changes the threshold for awards to qualify for equity classification, and allows an entity to make an accounting policy election to account for forfeitures when they occur. The new standard is effective for the Company beginning on January 1, 2017. The Company does not believe the adoption of ASU 2015-09 will have a material impact on its financial position, results of operations or cash flows.

4. Risk Management and Derivative Instruments

Revenue realized by the Company from the sale of its production is exposed to fluctuations in the prices for crude oil, NGLs and natural gas. The Company has historically utilized various types of derivative financial instruments, including swaps and collars, to reduce fluctuations in cash flows resulting from changes in commodity prices. These derivative contracts are placed with major financial institutions that the Company believes are minimal credit risks. The oil, NGLs and natural gas reference prices, upon which the commodity derivative contracts are based, reflect various market indices that management believes have a high degree of historical correlation with actual prices received by the Company for its oil, NGLs and natural gas production. Although the Company has entered into derivative financial instruments in the past, the Company currently has no derivatives in place.

Inherent in 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 historically 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.

Commodity Derivative Contracts

As of March 31, 2016 and December 31, 2015, the Company did not have any open commodity derivative contract positions.

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Gains on Commodity Derivative Contracts

Historically, the Company has not designated 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 condensed consolidated statements of operations.

The following table presents net cash received for commodity derivative contracts and unrealized net losses recorded by the Company related to the change in the fair value of the derivative instruments in “Gains on commodity derivative contracts — net” for the periods presented:

	For the Three Months Ended March 31,
	2016		2015
	(in thousands)
Net cash received for commodity derivative contracts	$	—	$	52,608
Unrealized net losses	—		(31,236		)
Gains on commodity derivative contracts - net	$	—	$	21,372

5. Property and Equipment

	March 31, 2016			December 31, 2015
	(in thousands)
Oil and gas properties, on the basis of full-cost accounting:
Proved properties	$	3,723,879		$	3,666,403
Unevaluated properties	—			—
Other property and equipment	13,488			14,798
Less accumulated depreciation, depletion, amortization and impairment	(3,308,871		)	(3,157,332		)
Net property and equipment	$	428,496		$	523,869

Oil and Gas Properties

The Company capitalizes internal costs directly related to exploration and development activities to oil and gas properties. During the three months ended March 31, 2016 and 2015, the Company capitalized the following amounts (in thousands):

	Three Months Ended March 31,
	2016		2015
Internal costs capitalized to oil and gas properties (1)	$	1,270	$	2,302

(1) Inclusive of $0.2 million and $0.5 million of qualifying share-based compensation expense for the three months ended March 31, 2016 and 2015, 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.

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 and amortization (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 are 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 expense in the accompanying consolidated statements of operations.

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For the three months ended March 31, 2016 and 2015, capitalized costs exceeded the ceiling and the Company recorded an impairment of oil and gas properties of $127.7 million and $174.7 million, respectively. These impairments were primarily the result of continued low commodity prices, which resulted in a reduction of the discounted present value of the Company’s proved oil and natural gas reserves.

Depreciation, depletion and amortization is calculated using the units-of-production method (“UOP”). The UOP calculation multiplies the percentage of estimated proved reserves produced by the cost of these reserves. The result is to recognize the 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 three months ended March 31, 2016 and 2015, respectively:

	Three Months Ended March 31,
	2016		2015		2016		2015
	(in thousands)				(per Boe)
Depletion expense	$	23,742	$	57,605	$	8.15	$	18.73
Depreciation on other property and equipment	1,093		823		0.37		0.27
Depreciation, depletion, and amortization	$	24,835	$	58,428	$	8.52	$	19.00

Oil and gas unevaluated properties and properties under development include costs that are not being depleted or amortized. These costs represent investments in unproved properties. 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 quarterly to determine if impairment has occurred. During 2015, the Company transferred the remaining unevaluated property balance of $56.6 million to the full cost pool as a result of current pricing, its anticipated future drilling plans and uncertainty regarding its ability to finance its future exploration activities. As such, the Company had no balances related to unevaluated properties at either March 31, 2016 or December 31, 2015.

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 five to seven years. Maintenance and repairs are charged to expenses as incurred, while renewals and betterments are capitalized.

6. Other Noncurrent Assets

At March 31, 2016 and December 31, 2015 other noncurrent assets consisted of the following:

	March 31, 2016		December 31, 2015
	(in thousands)
Deferred financing costs associated with the Credit Facility	$	5,473	$	6,105
Field equipment	4,009		3,225
Other	165		166
Other noncurrent assets	$	9,647	$	9,496

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7. Accrued Liabilities

At March 31, 2016 and December 31, 2015 accrued liabilities consisted of the following:

	March 31, 2016		December 31, 2015
	(in thousands)
Accrued oil and gas capital expenditures	$	12,972	$	19,984
Accrued revenue and royalty distributions	27,671		27,939
Accrued lease operating and workover expense	7,512		9,281
Accrued interest	69,070		20,193
Accrued taxes	1,393		1,272
Compensation and benefit related accruals	2,486		8,414
Other	5,987		4,629
Accrued liabilities	$	127,091	$	91,712

8. 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 fair value of the ARO at inception is 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 indicated:

	Three Months Ended March 31, 2016			Three Months Ended March 31, 2015
	(in thousands)
Asset retirement obligations — beginning of period	$	18,708		$	21,599
Liabilities incurred	481			—
Revisions	—			—
Liabilities settled	(173		)	—
Liabilities eliminated through asset sales	—			—
Current period accretion expense	420			445
Asset retirement obligations — end of period	$	19,436		$	22,044

9. Debt

The Company’s total debt, including debt classified as current, as of March 31, 2016 and December 31, 2015 is as follows:

	Principal				Unamortized Deferred Gain on Debt Forgiven				Unamortized Debt Issuance Costs						Total
	March 31, 2016		December 31, 2015		March 31, 2016		December 31, 2015		March 31, 2016			December 31, 2015			March 31, 2016		December 31, 2015
	(in thousands)
Credit Facility	$	249,184	$	—	$	—	$	—	$	—		$	—		$	249,184	$	—
2020 Senior Notes	293,625		293,625		—		—		(10,891		)	(11,344		)	282,734		282,281
2021 Senior Notes	347,652		347,652		—		—		(12,830		)	(13,296		)	334,822		334,356
Second Lien Notes	625,000		625,000		40,225		42,293		—			—			665,225		667,293
Third Lien Notes	529,653		529,653		73,153		77,361		—			—			602,806		607,014
Total debt	$	2,045,114	$	1,795,930	$	113,378	$	119,654	$	(23,721	)	$	(24,640	)	$	2,134,771	$	1,890,944

The Company’s filing of the Bankruptcy Petitions described in Note 2 herein constitutes an event of default that accelerated the Company’s obligations under the Credit Facility and the Senior Notes. Additionally, other events of default, including cross-defaults, are present, including the failure to make the April 1, 2016 interest payment on the 2020 Senior Notes within the 30 day grace period, the failure to cure the borrowing base deficiency within the prescribed period and the receipt of a going concern explanatory paragraph from the Company’s predecessor independent registered public accounting firm on the Company’s 2015 consolidated financial statements for the year ended December 31, 2015. As a result of the filing of the Bankruptcy Petitions, subject to certain limited exceptions, the lenders under the Credit Facility and the holders of the Senior Notes are stayed from taking any actions against the Company as a result of these defaults.

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Reserve-based Credit Facility

The Company maintains a $750.0 million Credit Facility which had a borrowing base of $252.0 at March 31, 2016. In February 2016, the Company borrowed approximately $249.2 million under the Credit Facility, which represented the remaining undrawn availability under the Credit Facility.

The borrowing base under the Credit Facility is subject to semiannual redeterminations in April and October and up to one additional time per six month period following each scheduled borrowing base redetermination, as may be requested by the Company or the administrative agent acting on behalf of lenders under the Credit Facility holding at least two-thirds of the outstanding loans and other obligations.

On April 1, 2016, the Company received a notice of the result of a scheduled borrowing base redetermination (the “Notice”) from the administrative agent (the “Administrative Agent”) and the lenders (the “Lenders”) under the Credit Facility that reduced its borrowing base to $170.0 million (the “Conforming Borrowing Base”). As of April 1, 2016, the Company had approximately $252.0 million in aggregate outstanding borrowings (the “Effective Amount”) under the Credit Facility, resulting in a borrowing base deficiency of approximately $82.0 million based on the Conforming Borrowing Base set forth in the Notice. Under the Credit Facility, the Company is required to cure the borrowing base deficiency within 30 days after receipt of the Notice.

The Credit Facility matures on May 31, 2018 and borrowings thereunder are secured by substantially all of the Company’s oil and natural gas properties and bear interest at LIBOR plus an applicable margin, depending upon the Company’s borrowing base utilization, between 2.00% and 3.00% per annum. The effective interest rate was 4.1% and 3.0% for the quarters ended March 31, 2016 and March 31, 2015, respectively.

In addition to interest expense, the Credit Facility requires the payment of a commitment fee each quarter. The commitment fee is computed at the rate of either 0.375% or 0.500% per annum based on the average daily amount by which the borrowing base exceeds the outstanding borrowings during each quarter.

2020 Senior Notes

On October 1, 2012, the Company issued $600.0 million in aggregate principal amount of 2020 Senior Notes, conducted pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended (the “Securities Act”). In October 2013, these notes were exchanged for an equal principal amount of identical registered notes. In May 2015 and June 2015, a total of $306.4 million aggregate principal amount of 2020 Senior Notes were exchanged for Third Lien Notes. As a result, $293.6 million of 2020 Senior Notes remain outstanding at March 31, 2016.

The estimated fair value of the 2020 Senior Notes as of March 31, 2016 was $11.7 million (Level 2 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities. The effective interest rate was 10.75% and 11.1%, respectively, for the quarters ended March 31, 2016 and 2015.

On April 1, 2016, the Company elected to forego payment with respect to an approximately $15.8 million interest payment due on the 2020 Notes, which after the expiration of the 30 day grace period resulted in an event of default.

The Company’s filing of the Bankruptcy Petitions described in Note 2 herein constitutes an event of default that accelerated the Company’s obligations under the 2020 Senior Notes. However, subject to certain limited exceptions, the filing of the Company’s Bankruptcy Petitions automatically enjoined or stayed the Company’s creditors from taking any actions against the Company as a result of such defaults.

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2021 Senior Notes

On May 31, 2013, the Company issued $700.0 million in aggregate principal amount of 2021 Senior Notes. In October 2013, these notes were exchanged for an equal principal amount of identical registered notes. In May and June 2015, a total of $352.3 million aggregate principal amount of 2021 Senior Notes were exchanged for Third Lien Notes. As a result, $347.7 million of 2021 Senior Notes remain outstanding at March 31, 2016.

The estimated fair value as of March 31, 2016 of the 2021 Senior Notes was $13.9 million (Level 2 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities. The effective interest rate was 9.25% and 9.6%, respectively, for the quarters ended March 31, 2016 and 2015.

The Company’s filing of the Bankruptcy Petitions described in Note 2 herein constitutes an event of default that accelerated the Company’s obligations under the 2021 Senior Notes. However, subject to certain limited exceptions, the filing of the Company’s Bankruptcy Petitions automatically enjoined or stayed the Company’s creditors from taking any actions against the Company as a result of such defaults.

Second Lien Notes

On May 21, 2015, the Company and Midstates Sub issued and sold $625.0 million aggregate principal amount of Second Lien Notes, in a private placement conducted pursuant to Rule 144A under the Securities Act. In November 2015, these notes were exchanged for an equal principal amount of identical registered notes.

The estimated fair value of the Second Lien Notes was $232.8 million as of March 31, 2016 (Level 2 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities. The effective interest rate was 10.0% for the quarter ended March 31, 2016.

The Company’s filing of the Bankruptcy Petitions described in Note 2 herein constitutes an event of default that accelerated the Company’s obligations under the Second Lien Notes. However, subject to certain limited exceptions, the filing of the Company’s Bankruptcy Petitions automatically enjoined or stayed the Company’s creditors from taking any actions against the Company as a result of such defaults.

Third Lien Notes

On May 21, 2015 and June 2, 2015, the Company issued approximately $504.1 million and $20.0 million, respectively, in aggregate principal amount of Third Lien Notes in a private placement and in exchange for an aggregate $306.4 million of the 2020 Senior Notes and $352.3 million of the 2021 Senior Notes. In November 2015, these notes were exchanged for an equal principal amount of identical registered notes.

The estimated fair value of the Third Lien Notes was $37.1 million as of March 31, 2016 (Level 2 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities. The effective interest rate was 12.0% for the quarter ended March 31, 2016.

The Company’s filing of the Bankruptcy Petitions described in Note 2 herein constitutes an event of default that accelerated the Company’s obligations under the Third Lien Notes. However, subject to certain limited exceptions, the filing of the Company’s Bankruptcy Petitions automatically enjoined or stayed the Company’s creditors from taking any actions against the Company as a result of such defaults.

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10. Equity and Share-Based Compensation

The Company has a significant amount of indebtedness that is senior to its existing common stock in its capital structure. As a result, the Company believes that it is highly likely that its existing common shares, including shares of its restricted stock, will be cancelled in its Chapter 11 proceedings and entitled to no recovery. Additionally, significant restrictions have been put in place on trading of the Company’s common stock.

Common Shares

Share Activity

The following table summarizes changes in the number of outstanding shares during the three months ended March 31, 2016:

	Number of Shares
	Common Stock		Treasury Stock
Share count as of December 31, 2015	10,962,105		(96,291	)
Grants of restricted stock	—		—
Forfeitures of restricted stock	(44,950	)	—
Acquisition of treasury stock	—		(47,396	)
Share count as of March 31, 2016	10,917,155		(143,687	)

The Company’s 2012 Long Term Incentive Unit Plan (the “2012 LTIP”) allows for the recipients of restricted stock to surrender a portion of their shares upon vesting to satisfy Federal Income Tax (“FIT”) withholding requirements. The Company then remits to the IRS the cash equivalent of the FIT withholding liability. Shares surrendered to the Company in this fashion have been treated as treasury shares acquired at a cost equivalent to the related tax liability. These shares are available for future issuance by the Company.

Share-based Compensation

2012 Long Term Incentive Plan

The 2012 LTIP provides for the granting of Options (Incentive and other), Restricted Stock Awards, Restricted Stock Units, Stock Appreciation Rights, Dividend Equivalents, Bonus Stock, Other Stock Based Awards, Annual Incentive Awards, Performance Awards, or any combination of the foregoing (the “Awards”). Subject to certain limitations as defined in the 2012 LTIP, the terms of each Award are as determined by the Compensation Committee of the Board of Directors. As of March 31, 2016, a total of 863,843 common share Awards are authorized for issuance and shares of stock subject to an Award that expire, or are canceled, forfeited, exchanged, settled in cash or otherwise terminated, will again be available for future Awards under the 2012 LTIP.

Non-vested Stock Awards

At March 31, 2016, the Company had 126,812 non-vested shares of restricted common stock to directors, management and employees outstanding pursuant to the 2012 LTIP. Shares granted under the LTIP generally vest ratably over a period of three years (one-third on each anniversary of the grant); however, beginning in 2013, any shares granted under the 2012 LTIP to directors are subject to one-year cliff vesting.

The fair value of restricted stock grants is based on the value of the Company’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period.

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The following table summarizes the Company’s non-vested share award activity for the three months ended March 31, 2016:

	Shares		Weighted Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2015	318,031		$	21.46
Granted	—		$	—
Vested	(146,269	)	$	21.85
Forfeited	(44,950	)	$	19.34
Non-vested shares outstanding at March 31, 2016	126,812		$	21.77

Unrecognized expense, adjusted for estimated forfeitures, as of March 31, 2016 for all outstanding restricted stock awards, was $2.1 million and will be recognized over a weighted average period of 1.4 years.

At March 31, 2016, 248,539 shares remain available for issuance under the terms of the 2012 LTIP.

11. Income Taxes

For the three months ended March 31, 2016, we recorded no income tax expense or benefit. The significant difference between our effective tax rate and federal statutory income tax rate of 35% is primarily due to the effect of changes in the valuation allowance. During the three months ended March 31, 2016, the Company recorded $60.8 million in additional valuation allowance in light of the impairment of oil and gas properties and the settlement of certain hedging contracts that existed at December 31, 2015, bringing the total valuation allowance to $755.9 million at March 31, 2016.

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 except to the extent of future taxable income primarily related to the excess of book carrying value of properties over their respective tax bases. No other sources of future taxable income are considered in this judgment.

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.

12. Net Loss Per Share

Prior to conversion on September 30, 2015, the Company’s Series A Preferred Stock had the nonforfeitable right to participate on an as converted basis at the conversion rate then in effect in any common stock dividends declared and as such, was considered a participating security. The Company’s nonvested stock awards, which are granted as part of the 2012 LTIP, contain nonforfeitable rights to dividends and as such, are considered to be participating securities and, together with the Series A Preferred Stock, are included in the computation of basic and diluted earnings per share, pursuant to the two class method. In the calculation of basic earnings per share attributable to common shareholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common shareholders, if any, after recognizing distributed earnings. The Company’s participating securities do not participate in undistributed net losses because they are not contractually obligated to do so.

The computation of diluted earnings per share attributable to common shareholders reflects the potential dilution that could occur if securities or other contracts to issue common shares that are dilutive were exercised or converted into common shares (or resulted in the issuance of common shares) and would then share in the earnings of the Company. During the periods in which the Company records a loss from continuing operations attributable to common shareholders, securities would not be dilutive to net loss per share and conversion into common shares is assumed to not occur. Diluted net earnings/(loss) per share attributable to common shareholders is calculated under both the two-class method and the treasury stock method; the more dilutive of the two calculations is presented below.

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The following table (in thousands, except per share amounts) provides a reconciliation of net loss to preferred shareholders, common shareholders, and non-vested restricted shareholders for purposes of computing net loss per share for the three months ended March 31, 2016 and 2015, respectively:

	Three Months Ended March 31,
	2016			2015
Net loss	$	(179,274	)	$	(193,554	)
Preferred Dividend	—			(131		)
Net loss attributable to shareholders	$	(179,274	)	$	(193,685	)

Weighted average shares outstanding	10,621			6,726
Net loss per share	$	(16.88	)	$	(28.80	)

The aggregate number of common shares outstanding at March 31, 2016 was 10,773,468 of which 126,812 were non-vested restricted shares.

13. Commitments and Contingencies

Litigation

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 authorities 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 the 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 March 31, 2016 and December 31, 2015, the Company’s 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, 2015, 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 30, 2016, as well as the unaudited condensed consolidated financial statements and notes thereto included in this quarterly report on Form 10-Q.

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 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;

· availability of oilfield labor;

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

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

· 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;

· counterparty credit risk;

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· the outcome of pending and future litigation;

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

· developments in oil producing and natural gas producing countries;

· uncertainty regarding our future operating results;

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

· inability to maintain relationship with suppliers, customers, employees and other third parties as a result of our Chapter 11 filing; and

· the outcome of our Bankruptcy Petitions for reorganization under Chapter 11of the Bankruptcy Code.

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. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. 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.

Overview

We are an independent exploration and production company focused on the application of modern drilling and completion techniques to oil-prone resources. Our common stock was listed on the New York Stock Exchange (the “NYSE”) beginning in 2012 under the symbol “MPO” however, we were delisted by the NYSE on February 3, 2016 and now trade on the over the counter market under the symbol “MPOY”. 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.

Recent Developments

Chapter 11 Filing

On April 30, 2016, we filed Bankruptcy Petitions for reorganization under the Bankruptcy Code in the Bankruptcy Court. Our Chapter 11 Cases are being jointly administered under the case styled In re Midstates Petroleum Company, Inc., et al, No. 16-32237. We will continue to operate our businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. We will account for the bankruptcy in accordance with FASB ASC 852, “Reorganizations”, in the quarterly period ended June 30, 2016.

By certain “first day” motions filed in the Chapter 11 Cases, we obtained Bankruptcy Court approval to, among other things and subject to the terms of the orders entered by the Bankruptcy Court, pay employee wages, health benefits and certain other employee obligations, pay certain lienholders and forward funds to third parties, including royalty holders and other partners. As a result, we are not only able to conduct normal business activities and pay all associated obligations for the period following our bankruptcy filing, we are also authorized to pay and have paid pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders and funds belonging to third parties. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of our business require the prior approval of the Bankruptcy Court.

For the duration of our Chapter 11 Cases, our operations and ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 process. For example, negative events associated with our Chapter 11 Cases could adversely affect our relationships with our suppliers, service providers, customers, and other third parties and our ability to retain employees, which in turn could adversely affect our operations and financial condition. For a description of these and other risks, please see 1A. “Risk Factors.” As a result of these risks and uncertainties, the number of our outstanding shares and shareholders, assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 Cases, and the description of our operations, properties and capital plans included in this quarterly report may not accurately reflect our operations, properties and capital plans following the Chapter 11 process.

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Our filing of the Bankruptcy Petitions described herein constitutes an event of default that accelerated our obligations under the Credit Facility and the Senior Notes. Additionally, other events of default, including cross-defaults, are present, including the failure to make the April 1, 2016 interest payment on the 2020 Senior Notes within the 30 day grace period, the failure to cure the borrowing base deficiency within the prescribed period and the receipt of a going concern explanatory paragraph from our predecessor independent registered public accounting firm on our consolidated financial statements for the year ended December 31, 2015. We have classified all debt as current as of March 31, 2016 and December 31, 2015. If we cannot continue as a going concern, adjustments to the carrying values and classification of our assets and liabilities and our reported income and expenses could be required and could be material.

Operations Update

Mississippian Lime

For the three months ended March 31, 2016 and December 31, 2015, our average daily production from the Mississippian Lime area was as follows:

	Three Months Ended March 31, 2016	Three Months Ended December 31, 2015	Increase in Production

Average daily production:
Oil (Bbls)	9,195	9,158	0.4	%
Natural gas liquids (Bbls)	5,586	5,188	7.7	%
Natural gas (Mcf)	71,415	65,260	9.4	%
Net Boe/day	26,683	25,222	5.8	%

The following table shows our total number of horizontal wells spud and brought into production in the Mississippian Lime area during the first quarter of 2016:

		Total Number of Gross Horizontal Wells Spud (1)		Total Number of Gross Horizontal Wells Brought into Production
Mississippian Lime		15		17

(1) We had 1 rig drilling in the Mississippian Lime horizontal well program at March 31, 2016. Of the 15 wells spud, 5 were producing, 9 were awaiting completion and 1 was being drilled at quarter-end.

Anadarko Basin

For the three months ended March 31, 2016 and December 31, 2015, our average daily production from our Anadarko Basin area was as follows:

	Three Months Ended March 31, 2016	Three Months Ended December 31, 2015	Increase/ (Decrease) in Production

Average daily production:
Oil (Bbls)	2,188	2,165	1.1	%
Natural gas liquids (Bbls)	1,284	1,479	(13.2	)%
Natural gas (Mcf)	11,176	12,145	(8.0	)%
Net Boe/day	5,335	5,668	(5.9	)%

We did not spud any wells in the Anadarko Basin area and did not have any operated drilling rigs in the area during the first quarter of 2016.

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Capital Expenditures

During the three months ended March 31, 2016, we incurred operational capital expenditures of $54.4 million, which consisted of:

	For the Three Months Ended March 31, 2016
Drilling and completion activities	$	52,595
Acquisition of acreage and seismic data	1,773
Operational capital expenditures incurred	$	54,368
Capitalized G&A, office, ARO & other	1,980
Total capital expenditures incurred	$	56,348

Operational capital expenditures by area were as follows:

	For the Three Months Ended March 31, 2016
Mississippian Lime	53,851
Anadarko Basin	517
Total operational capital expenditures incurred	$	54,368

We expect to invest between $95.0 million to $125.0 million of capital for exploration, development and lease and seismic acquisition during the year ended December 31, 2016.

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.

Like all businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from any given well is expected to decline. As a result, oil and natural gas exploration and production companies deplete their asset base with each unit of oil or natural gas they produce. We attempt to overcome this natural production decline by developing additional reserves through our drilling operations, acquiring additional reserves and production and implementing secondary recovery techniques. Our future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production. We will maintain our focus on the capital investments necessary to produce our reserves as well as to add to our reserves through drilling and acquisition. Our ability to make the necessary capital expenditures is dependent on cash flow from operations as well as our ability to obtain additional debt and equity financing. That ability can be limited by many factors, including the cost and terms of such capital, our current financial condition, expectations regarding the future price for oil and natural gas, and operational considerations.

The volumes of oil and natural gas that we produce are driven by several factors, including:

· success in the drilling of new wells, including exploratory wells, and the recompletion or workover of existing wells;

· the amount of capital we invest in the leasing and development of our oil and natural gas properties;

· facility or equipment availability and unexpected downtime;

· delays imposed by or resulting from compliance with regulatory requirements;

· the rate at which production volumes on our wells naturally decline; and

· our ability to economically dispose of salt water produced in conjunction with our production of oil and gas.

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We follow the full cost method of accounting for our oil and gas properties. In the first quarter of 2016, the results of our full cost “ceiling test” required us to recognize an impairment of our oil and gas properties of $127.7 million. While this impairment did not impact cash flow from operating activities, it did increase our net loss and shareholders’ deficit. Based upon commodity pricing for the first quarter of 2016, we expect to recognize a further full cost impairment that is likely to be material to our net loss for fiscal 2016. While inherently imprecise and difficult to measure, we estimate our second quarter 2016 impairment will be approximately $45.0 million to $70.0 million. Our full cost impairments have no impact to our cash flow or liquidity.

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.

There exists a growing concern and heightened regulatory scrutiny surrounding any potential correlation between the injection of saltwater into disposal wells and those activities alleged contribution to increased seismic activity in certain areas, including the areas in which we operate, Oklahoma and Texas. On February 16, 2016, the Oil and Gas Conservation Division (“OGCD”) of the Oklahoma Corporation Commission requested that we curtail our current wastewater disposal injection volumes into the Arbuckle formation in our Mississippian Lime area of operation by approximately 40%. We are currently in discussions with the OGCD regarding this matter; however, the inability to economically dispose of produced saltwater could require us to reduce our oil and gas production by shutting in certain producing wells until alternative disposal wells and methods can be permitted and developed. Potential actions to address the OGCD’s curtailment request include, among other things, drilling new or converting existing vertical wells into wastewater injection wells that would inject produced water into formations other than the Arbuckle, selectively shutting in or curtailing production from currently producing wells, or possibly a combination of the above. There can be no assurance we will receive the necessary permits or the consent of impacted parties to convert existing wells or drill new wells into alternative wastewater disposal formations. Any forced reduction in oil and gas production could have a material adverse effect on our cash flow and results of operations.

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Results of Operations

The following tables summarize our revenue, production and price data for the periods indicated.

Revenues

	For the Three Months Ended March 31
	2016				2015
	(in thousands)
REVENUES:
Oil sales	$	30,138	58.9	%	$	59,257		66.3	%
Natural gas liquid sales	7,063		13.8	%	11,010			12.3	%
Natural gas sales	13,942		27.3	%	19,172			21.4	%
Total oil, natural gas liquids, and natural gas sales	51,143		100.0	%	89,439			100.0	%

Net cash received for commodity derivative contracts	—		—		52,608			246.2	%
Unrealized losses on commodity derivative contracts, net	—		—		(31,236		)	(146.2	)%
Gains on commodity derivative contracts - net	—		—		21,372			100.0	%

Other	818				387

Total revenues	$	51,961			$	111,198

Production

	For the Three Months Ended March 31,
	2016	2015	% Change
PRODUCTION DATA:
Oil (MBbls)	1,036	1,310	(20.9	)%
Natural gas liquids (MBbls)	625	619	1.0	%
Natural gas (MMcf)	7,516	6,870	9.4	%
Oil equivalents (MBoe)	2,914	3,075	(5.2	)%

Oil (Boe/day)	11,383	14,561	(21.8	)%
Natural gas liquids (Boe/day)	6,870	6,881	(0.2	)%
Natural gas (Mcf/day)	82,592	76,331	8.2	%
Average daily production (Boe/d)	32,018	34,164	(6.3	)%

Prices

	For the Three Months Ended March 31,
	2016		2015		% Change
AVERAGE SALES PRICES:
Oil, without realized derivatives (per Bbl)	$	29.09	$	45.22	(35.7	)%
Oil, with realized derivatives (per Bbl)	$	29.09	$	79.45	(63.4	)%
Natural gas liquids, without realized derivatives (per Bbl)	$	11.30	$	17.78	(36.4	)%
Natural gas liquids, with realized derivatives (per Bbl)	$	11.30	$	17.78	(36.4	)%
Natural gas, without realized derivatives (per Mcf)	$	1.86	$	2.79	(33.3	)%
Natural gas, with realized derivatives (per Mcf)	$	1.86	$	3.92	(52.6	)%

Three Months Ended March 31, 2016 as Compared to March 31, 2015

Oil, natural gas liquids and natural gas sales revenues

Our oil, NGL and natural gas sales revenues decreased by $38.3 million, or 42.8% to $51.1 million during the three months ended March 31, 2016 as compared to $89.4 million during the three months ended March 31, 2015. Lower revenue was primarily the result of decreases in oil, natural gas and NGL production and prices for the three months ended March 31, 2016 as compared to the three months ended March 31, 2015.

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Our oil sales revenues decreased by $29.1 million, or 49.1%, to $30.1 million during the three months ended March 31, 2016, as compared to $59.2 million for the three months ended March 31, 2015. Oil volumes sold decreased 3,178 Boe/day, or 21.8%, to 11,383 Boe/day for the three months ended March 31, 2016, from 14,561 Boe/day for the three months ended March 31, 2015. This decrease in oil volumes sold was attributable to decreased production quarter over quarter in the Mississippian Lime area of 1,480 Boe/day and 840 Boe/day in the Anadarko Basin area, as well as 858 Boe/day decrease in production from our Gulf Coast area due to the sale of our oil and gas properties in Beauregard and Calcasieu Parishes, Louisiana (the “Dequincy Divestiture”) in the second quarter of 2015. Average oil sales prices, without realized derivatives, decreased by $16.13 per barrel, or 35.7%, to $29.09 per barrel during the three months ended March 31, 2016 as compared to $45.22 per barrel for the three months ended March 31, 2015.

Our NGL sales revenues decreased by $3.9 million, or 35.8%, to $7.1 million during the three months ended March 31, 2016, as compared to $11.0 million for the three months ended March 31, 2015. NGL volumes sold decreased 11 Boe/day, or 0.2%, to 6,870 Boe/day for the three months ended March 31, 2016, from 6,881 Boe/day for the three months ended March 31, 2015. This decrease in NGL volumes sold was attributable to a decrease of 274 Boe/day from our Gulf Coast area due to the Dequincy Divestiture in the second quarter of 2015, offset by increased production quarter over quarter in the Mississippian Lime and Anadarko Basin areas of 219 Boe/day and 44 Boe/day, respectively. Average NGL sales prices, without realized derivatives, decreased by $6.48 per barrel, or 36.4%, to $11.30 per barrel during the three months ended March 31, 2016 as compared to $17.78 per barrel for the corresponding period in 2015.

Our natural gas sales revenues decreased by $5.2 million, or 27.3%, to $13.9 million during the three months ended March 31, 2016, as compared to $19.1 million for the three months ended March 31, 2015. Natural gas volumes sold increased 6,261 Mcf/day or 8.2%, to 82,592 Mcf/day for the three months ended March 31, 2016, from 76,331 Mcf/day for the three months ended March 31, 2015. This increase in natural gas volumes sold was attributable to increased production of 8,482 Mcf/day in the Mississippian Lime area, partially offset by a decrease in production of 1,557 Mcf/day from our Anadarko Basin area, as well as a 664 Mcf/day decrease in production from our Gulf Coast area due to the Dequincy Divestiture in the second quarter of 2015. Average natural gas sales prices, without realized derivatives, decreased by $0.93 per Mcf, or 33.3%, to $1.86 per Mcf during the three months ended March 31, 2016 as compared to $2.79 per Mcf for the three months ended March 31, 2015.

Gains/losses on commodity derivative contracts - net

During the first quarter of 2015, we had an unrealized loss of $31.2 million from our mark-to-market (“MTM”) derivative positions, representing the changes in fair value from new positions and settlements that occurred during the period, as well as the relationship between contract prices and the associated forward curves. This loss was offset by cash receipts for the settlements of derivatives of $52.6 million. We had no derivative positions at either March 31, 2016 or December 31, 2015, and as such, had no gains or losses related to derivative positions in the first quarter of 2016.

Operating Expenses

The table below presents a comparison of our expenses on an absolute dollar basis and a per Boe basis. Depending on the relevance, our discussion may reference expenses on an absolute dollar basis, a per Boe basis, or both.

	Three Months Ended March 31
	2016		2015		2016		2015
	(in thousands)				(per Boe)
EXPENSES:
Lease operating and workover	$	15,761	$	23,262	$	5.41	$	7.56
Gathering and transportation	4,421		3,438		1.52		1.12
Severance and other taxes	1,504		3,565		0.52		1.16
Asset retirement accretion	420		445		0.15		0.14
Depreciation, depletion, and amortization	24,835		58,428		8.52		19.00
Impairment of oil and gas properties	127,734		174,667		43.83		56.80
General and administrative	11,288		11,654		3.87		3.79
Advisory fees	1,117		1,743		0.38		0.57
Other	—		97		—		0.03
Total expenses	$	187,080	$	277,299	$	64.20	$	90.17

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Three Months Ended March 31, 2016 as Compared to the Three Months Ended March 31, 2015

Lease operating and workover expenses

Lease operating and workover expenses decreased $7.5 million, or 32.2%, to $15.8 million for the three months ended March 31, 2016 compared to $23.3 million for the three months ended March 31, 2015. The decrease in lease operating expenses is primarily the result of ongoing cost reduction efforts in our Mississippian Lime and Anadarko Basin areas, specifically in salt water disposal trucking, chemical well treatment, and surface maintenance and repair expense. Also contributing to the decrease in lease operating and workover expenses was the sale of our Dequincy assets in Louisiana in the second quarter of 2015, where average lease operating expenses were higher compared to our other operating basins. Lease operating and workover expenses decreased to $5.41 per Boe for the three months ended March 31, 2016, a decrease of $2.15, or 28.4%, over the $7.56 per Boe for the three months ended March 31, 2015, largely as a result of the factors discussed above.

Gathering and transportation

Gathering and transportation expenses increased $1.0 million, or 28.6 % to $4.4 million for the three months ended March 31, 2016 compared to $3.4 million for the three months ended March 31, 2015, due primarily to a 9.4% corresponding increase in natural gas production volumes, which are subject to gathering and transportation fees.

Severance and other taxes

	Three Months Ended March 31
	2016			2015

Total oil, natural gas, and natural gas liquids sales	$	51,143		$	89,439

Severance taxes	1,068			1,782
Ad valorem and other taxes	436			1,783
Severance and other taxes	$	1,504		$	3,565

Severance taxes as a percentage of sales	2.1		%	2.0		%
Severance and other taxes as a percentage of sales	2.9		%	4.0		%

Severance taxes decreased $0.7 million, or 40.1%, to $1.1 million for the three months ended March 31, 2016, as compared to $1.8 million for the three months ended March 31, 2015, due to lower realized pricing in the 2016 period. Severance taxes as a percentage of sales remained consistent between the periods, increasing just slightly from 2.0% for the three months ended March 31, 2015 to 2.1% for the three months ended March 31, 2016. Ad valorem taxes decreased $1.4 million, or 75.5%, to $0.4 million for the three months ended March 31, 2016 as compared to $1.8 million for the three months ended March 31, 2015, due to a decrease in the value of our proved oil and gas reserves.

Depreciation, depletion and amortization (“DD&A”)

DD&A expense decreased $33.6 million, or 57.5%, to $24.8 million for the three months ended March 31, 2016 compared to $58.4 million for the three months ended March 31, 2015. The decrease in DD&A expense was driven by ceiling impairments recorded during 2015 and the first quarter of 2016, decreasing our depletion rates. Consequently, the depletion rate per Boe also decreased from $18.73 per Boe for the three months ended March 31, 2015 to $8.15 per Boe for the three months ended March 31, 2016.

Impairment of oil and gas properties

We recorded impairment expense related to our oil and natural gas properties for the three months ended March 31, 2016 and 2015 of $127.7 million and $174.7 million, respectively, as a result of our full-cost ceiling test. Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of costs associated with our oil and natural gas properties that can be capitalized in our condensed consolidated balance sheets. The impairment expense for the three months ended March 31, 2016 was due to a decrease in value of our proven oil and natural gas reserves as a result of an extended period of low commodity prices.

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General and administrative (“G&A”)

G&A expense decreased $0.4 million, or 3.1%, to $11.3 million for the three months ended March 31, 2016 compared to $11.7 million for the three months ended March 31, 2015. The decrease is primarily due to $2.0 million less in employee related expenses in the three months ended March 31, 2016 as compared to the three months ended March 31, 2015, which included approximately $1.7 million in severance related payments to employees due to the Houston office relocation. This decrease was offset by the acceleration of rent and related expenses totaling $3.3 million associated with the Houston office lease in the three months ended March 31, 2016.

Advisory fees

As discussed previously, we have engaged financial and legal advisors to, among other things, assist with analyzing various strategic alternatives to address our liquidity and capital structure. For the three months ended March 31, 2016 and 2015, the Company incurred approximately $1.1 and $1.7 million, respectively, in fees associated with these advisors. We expect to incur additional significant costs during the remainder of 2016 for such advisors.

Other Income (Expenses)

	For the Three Months Ended March 31,
	2016			2015
	(in thousands)
OTHER INCOME (EXPENSE)
Interest income	$	57		$	9

Interest expense	(44,212		)	(37,487		)
Capitalized Interest	—			984
Interest expense — net of amounts capitalized	(44,212		)	(36,503		)

Total other income (expense)	$	(44,155	)	$	(36,494	)

Interest expense

Three Months Ended March 31, 2016 as Compared to the Three Months Ended March 31, 2015

Interest expense for the three months ended March 31, 2016 and 2015 was $44.2 million and $37.5 million, respectively. The increase in interest expense was primarily due to the issuance of the Second and Third Lien Notes in the second quarter of 2015. The Second Lien Notes bear interest at 10.0%. The Third Lien Notes bear interest at 12.0% and were exchanged for a portion of the 2020 Senior Notes and 2021 Senior Notes, which had stated interest rates of 10.75% and 9.25%, respectively. Increased interest expense was partially offset by $6.3 million in amortization of the deferred gain on forgiven debt during the three months ended March 31, 2016. No interest expense was capitalized for the three months ended March 31, 2016, due to the transfer of all balances related to unevaluated properties to the full cost pool at December 31, 2015. $1.0 million was capitalized to oil and gas properties for the three months ended March 31, 2015.

Provision for Income Taxes

Three Months Ended March 31, 2016 as Compared to the Three Months Ended March 31, 2015

For the three months ended March 31, 2016, we recorded no income tax expense or benefit. Our effective tax rate for the first quarter of 2016 differs from the federal statutory rate of 35% primarily due to changes in the valuation allowance.

We expect 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.

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Liquidity and Capital Resources

The filing of the Bankruptcy Petitions described above accelerated our obligations under the Credit Facility, the Second Lien Notes, the Third Lien Notes, the 2020 Senior Notes and the 2021 Senior Notes. We classified all debt as current at December 31, 2015 due to the receipt of a going concern explanatory paragraph from our predecessor independent registered public accounting firm on our consolidated financial statements for the year ended December 31, 2015 creating an event of default under the Credit Facility that, together with a projected additional debt covenant violation, and a resulting lack of liquidity, raised substantial doubt about our ability to continue as a going concern. All of our debt continued to be classified as current at March 31, 2016. If we cannot continue as a going concern, adjustments to the carrying values and classification of our assets and liabilities and our reported income and expenses could be required and could be material.

In February 2016, we borrowed approximately $249.2 million under the Credit Facility, which represented the remaining undrawn amount that was available under the Credit Facility. As of March 31, 2016, the total outstanding principal amount of our debt obligations was $2.1 billion, consisting of approximately $249.2 million of borrowings under the Credit Facility (excluding outstanding letters of credit), $293.6 million of 2020 Senior Notes, $347.7 million of 2021 Senior Notes, $625.0 million of Second Lien Notes and $529.7 million of Third Lien Notes. In addition, as of March 31, 2016, we had approximately $2.8 million of outstanding letters of credit under the Credit Facility. On April 1, 2016, we elected to utilize the 30 day grace period provided under the indenture to the 2020 Senior Notes with respect to an interest payment of approximately $15.8 million due on that date.

Additionally, on April 1, 2016, we received notice of the result of a scheduled borrowing base redetermination from the administrative agent and the lenders under the Credit Facility that reduced our borrowing base to $170.0 million. As of April 1, 2016, we had approximately $252.0 million in aggregate outstanding borrowings (including outstanding letters of credit) under the Credit Facility, resulting in a borrowing base deficiency of approximately $82.0 million. Under the Credit Facility, we are required to cure the borrowing base deficiency within 30 days after receipt of such notice.

Our filing of the Bankruptcy Petitions described herein constitutes an event of default that accelerated our obligations under the Credit Facility and the Senior Notes. Additionally, other events of default, including cross-defaults, are present, including the failure to make the April 1, 2016 interest payment on the 2020 Senior Notes within the 30 day grade period, the failure to cure the borrowing base deficiency within the prescribed period and the receipt of a going concern explanatory paragraph from our predecessor independent registered public accounting firm on our consolidated financial statements for the year ended December 31, 2015. As discussed above, subject to certain limited exceptions, the filing of our Bankruptcy Petitions automatically enjoined or stayed our creditors from taking any actions against us as a result of such defaults.

The condensed consolidated financial statements included in this Quarterly Report on Form 10-Q have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The condensed consolidated financial statements do not reflect any adjustments that might result from the outcome of the uncertainties as discussed above.

Significant Sources of Capital

Reserve-based Credit Facility

Our credit facility consists of a $750.0 million senior revolving credit facility with a borrowing base of $252.0 million at March 31, 2016, supported by our Mississippian Lime and Anadarko Basin oil and gas assets. The borrowing base under the Credit Facility is subject to semiannual redeterminations in April and October and up to one additional time per six month period following each scheduled borrowing base redetermination, as may be requested by us or the administrative agent acting on behalf of lenders holding at least two-thirds of the outstanding loans and other obligations.

On April 1, 2016, we received a Notice from the Administrative Agent and the Lenders under the Credit Facility, reducing our borrowing base to the Conforming Borrowing Base as a result of a scheduled borrowing base redetermination. As of April 1, 2016, we had approximately $252.0 million in aggregate outstanding borrowings under the Credit Facility, resulting in a borrowing base deficiency of approximately $82.0 million based on the Conforming Borrowing Base set forth in the Notice. Under the Credit Facility, we are required to cure the borrowing base deficiency within 30 days after receipt of the Notice.

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The Credit Facility matures on May 31, 2018 and borrowings thereunder are secured by substantially all of our oil and natural gas properties and bear interest at LIBOR plus an applicable margin, depending upon our borrowing base utilization, between 2.00% and 3.00% per annum. At March 31, 2016 and 2015, the weighted average interest rate was 4.1% and 3.0%, respectively.

In addition to interest expense, the Credit Facility requires the payment of a commitment fee each quarter. The commitment fee is computed at the rate of either 0.375% or 0.50% per annum based on the average daily amount by which the borrowing base exceeds the outstanding borrowings during each quarter.

Our filing of the Bankruptcy Petitions, as described in “—Note 2. Chapter 11 Proceedings, Liquidity and Ability to Continue as a Going Concern” in the notes to our condensed consolidated financial statements included herein, constitutes an event of default that accelerated our obligations under the Credit Facility. However, subject to certain limited exceptions, our filing of the Bankruptcy Petitions automatically enjoined or stayed the Lenders under the Credit Facility from taking any actions against us as a result of such defaults.

2020 Senior Notes

On October 1, 2012, we issued $600.0 million in aggregate principal amount of 2020 Senior Notes conducted pursuant to Rule 144A and Regulation S under the Securities Act. In October 2013, these notes were exchanged for an equal principal amount of identical registered notes. In May 2015 and June 2015, a total of $306.4 million aggregate principal amount of 2020 Senior Notes were exchanged for Third Lien Notes. As a result, $293.6 million of 2020 Senior Notes remain outstanding at March 31, 2016.

On April 1, 2016, we elected to forego payment with respect to an approximately $15.8 million interest payment due on the 2020 Notes, which after the expiration of the 30 day grace period resulted in an event of default.

Our filing of the Bankruptcy Petitions, as described in “—Note 2. Chapter 11 Proceedings, Liquidity and Ability to Continue as a Going Concern” in the notes to our condensed consolidated financial statements included herein, constitutes an event of default that accelerated our obligations under the 2020 Senior Notes. However, subject to certain limited exceptions, our filing of the Bankruptcy Petitions automatically enjoined or stayed our creditors from taking any actions against us as a result of such defaults.

2021 Senior Notes

On May 31, 2013, we issued $700.0 million in aggregate principal amount of 2021 Senior Notes. In October 2013, these notes were exchanged for an equal principal amount of identical registered notes. In May 2015 and June 2015, a total of $352.3 million aggregate principal amount of 2021 Senior Notes were exchanged for Third Lien Notes. As a result, $347.7 million of 2021 Senior Notes remain outstanding at March 31, 2016.

Our filing of the Bankruptcy Petitions, as described in “—Note 2. Chapter 11 Proceedings, Liquidity and Ability to Continue as a Going Concern” in the notes to our condensed consolidated financial statements included herein, constitutes an event of default that accelerated our obligations under the 2021 Senior Notes. However, subject to certain limited exceptions, our filing of the Bankruptcy Petitions automatically enjoined or stayed our creditors from taking any actions against us as a result of such defaults.

Second Lien Notes

On May 21, 2015, we and Midstates Sub issued and sold $625.0 million aggregate principal amount of Second Lien Notes in a private placement conducted pursuant to Rule 144A under the Securities Act. In November 2015, these notes were exchanged for an equal principal amount of identical registered notes.

Our filing of the Bankruptcy Petitions, as described in “—Note 2. Chapter 11 Proceedings, Liquidity and Ability to Continue as a Going Concern” in the notes to our condensed consolidated financial statements included herein, constitutes an event of default that accelerated our obligations under the Second Lien Notes. However, subject to certain limited exceptions, our filing of the Bankruptcy Petitions automatically enjoined or stayed our creditors from taking any actions against us as a result of such defaults.

Third Lien Notes

On May 21, 2015 and June 2, 2015, we issued approximately $504.1 million and $20.0 million, respectively, in aggregate principal amount of Third Lien Notes in a private placement and in exchange for an aggregate of $306.4 million of the 2020 Senior Notes and $352.3 million of the 2021 Senior Notes. In November 2015, these notes were exchanged for an equal principal amount of identical registered notes.

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Our filing of the Bankruptcy Petitions, as described in “—Note 2. Chapter 11 Proceedings, Liquidity and Ability to Continue as a Going Concern” in the notes to our condensed consolidated financial statements included herein, constitutes an event of default that accelerated our obligations under the Third Lien Notes. However, subject to certain limited exceptions, our filing of the Bankruptcy Petitions automatically enjoined or stayed our creditors from taking any actions against us as a result of such defaults.

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 Condensed Consolidated Statements of Cash Flows included under Item 1 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 “Item 3. — Quantitative and Qualitative Disclosures About Market Risk.”

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

	For the Three Months Ended March 31,
	2015			2014
Net cash provided by operating activities	$	29,855		$	113,017
Net cash used in investing activities	(58,654		)	(111,167		)
Net cash provided by (used in) financing activities	249,132			(1,466		)

Net change in cash	$	220,333		$	384

Cash flows provided by operating activities

Net cash provided by operating activities was $29.9 million and $113.0 million for the three months ended March 31, 2016 and 2015, respectively. The decrease in net cash provided by operating activities was primarily the result of the expiration of our commodity derivative contracts in 2015. No cash was received from commodity derivative contracts for the three months ended March 31, 2016 compared to $52.6 million received in the three months ended March 31, 2015. Additionally, lower commodity pricing during the first quarter of 2016 resulted in a decrease in our oil and gas revenues of $38.3 million. These decreases were partially offset by positive working capital changes.

Cash flows used in investing activities

Net cash used in investing activities was $58.7 million and $111.2 million during the three months ended March 31, 2016 and 2015, respectively. The decrease in our capital expenditures is the result of a lower rig count during the 2016 period.

Cash flows provided by (used in) financing activities

Net cash provided by financing activities was $249.1 million for the three months ended March 31, 2016, compared to $1.5 million used in financing activities for the three months ended March 31, 2015. The increase in net cash provided by financing activities was the result of a draw on our Credit Facility of $249.2 million in February of 2016.

Critical Accounting Policies and Estimates

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, 2015. There have been no material changes to those policies. When used in the preparation of our unaudited 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.

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Other Items

Obligations and Commitments

We have various contractual obligations for operating leases, including drilling contracts, as well as lease commitments and commitments under our debt instruments. The only material change in our commitments and contractual obligations from December 31, 2015 is the acceleration of payments under our debt instruments as a result of our filing of the Bankruptcy Petitions as described in Note 2 herein. Additionally, other events of default, including cross-defaults, are present, including the failure to make the April 1, 2016 interest payment on the 2020 Senior Notes within the 30 day grace period, the failure to cure the borrowing base deficiency within the prescribed period and the receipt of a going concern explanatory paragraph from our predecessor independent registered public accounting firm on our consolidated financial statements for the year ended December 31, 2015. However, subject to certain limited exceptions, the filing of the Bankruptcy Petitions automatically enjoined or stayed our creditors from taking any actions against us as a result of such defaults.

Off-Balance Sheet Arrangements

We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance our liquidity and capital resource positions or for any other purpose. However, as is customary in the oil and gas industry, we have various contractual work commitments and letters of credit as described in our notes to the condensed consolidated financial statements.

Recently Issued Standards Not Yet Adopted

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”). ASU 2014-09 provides guidance concerning the recognition and measurement of revenue from contracts with customers. The objective of ASU 2014-09 is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. ASU 2014-09 requires an entity to (i) identify the contract(s) with a customer, (ii) identify the performance obligations in the contract(s), (iii) determine the transaction price, (iv) allocate the transaction price to the performance obligations in the contract(s), and (v) recognize revenue when, or as, the entity satisfies a performance obligation. ASU 2014-09 will be effective for the Company beginning on January 1, 2018, including interim periods within that reporting period, considering the one year deferral provided by ASU 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.” The standard permits the use of either the retrospective or cumulative effect transition method and early adoption is permitted. The Company has not selected a transition method and is evaluating the impact this standard will have on its consolidated financial statements and related disclosures.

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842)” (“ASU 2016-02”). ASU 2016-02 establishes 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. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The new standard is effective for the Company beginning on January 1, 2019, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Company is currently evaluating the impact this standard will have on its consolidated financial statements and related disclosures.

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, in the past and likely in the future, 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 trading. These derivative instruments are discussed in “Item 1.—Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements — Note 4. 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 historically utilized derivative financial instruments, including fixed price swaps, to reduce the volatility of oil, NGL and natural gas prices on a portion of our future expected oil and natural gas production in order to manage risks related to changes in these prices. We continually reevaluate and consider whether in the long-term we will hedge any of our future production. At March 31, 2016 and December 31, 2015, we had no outstanding commodity derivative contracts.

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Interest Rate Risk. At March 31, 2016, we had indebtedness outstanding under our Credit Facility of $249.2 million, which bears interest at floating rates, $293.6 million outstanding in 2020 Senior Notes, which bore interest at 10.75%, $347.7 million outstanding in 2021 Senior Notes, which bore interest at 9.25%, $625.0 million outstanding in Second Lien Notes, which bear interest at 10.0%, and $529.7 million in Third Lien Notes, which bear interest at 12.0%.

A 1.0% increase in each of the average LIBOR and federal funds rate for the three months ended March 31, 2016 would have resulted in an estimated $0.3 million increase in interest expense.

At March 31, 2016 we do not have any interest rate derivatives in place. In the future, we may utilize interest rate derivatives to mitigate our exposure to change in interest rates. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

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 Interim President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of March 31, 2016, 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 March 31, 2016 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, Item 1, Note 13 to our unaudited condensed consolidated financial statements entitled “Commitments and Contingencies - Litigation,” 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.

Except as set forth below, 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, 2015, filed with the SEC on March 30, 2016.

We are subject to the risks and uncertainties associated with Chapter 11 proceedings.

For the duration of our Chapter 11 proceedings, our operations and our ability to develop and execute our business plan, and our continuation as a going concern are subjects to the risks and uncertainties associated with bankruptcy. These risks include the following:

· Our ability to develop, confirm and consummate a Chapter 11 plan or other restructuring transaction;

· Our ability to obtain court approval with respect to Chapter 11 proceedings from time to time;

· Our ability to maintain our relationships with our suppliers, service providers, customers, employees, and other third parties;

· Our ability to execute our business plan;

· The ability of third parties to seek and obtain court approval to terminate contracts and other agreements with us;

· The ability of third parties to seek and obtain court approval to terminate or shorten the exclusivity period for us to propose and confirm a Chapter 11 plan, to appoint a Chapter 11 trustee, or to convert the Chapter 11 proceedings to a Chapter 7 proceeding; and

· The actions and decisions of our creditors or other third parties who have interests in our Chapter 11 proceedings that may be inconsistent with our plans.

These risks and uncertainties could affect our business and operations in various ways. For example, negative events associated with our Chapter 11 proceedings could adversely affect our relationships with our suppliers, service providers, customers, employees, and other third parties, which in turn could adversely affect our operations and financial condition. Also, we need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond timely to certain events or take advantage of certain opportunities. Because of the risks and uncertainties associated with our Chapter 11 proceedings, we cannot accurately predict or quantify the ultimate impact of events which could occur during our Chapter 11 proceedings that may be inconsistent with our plans.

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Operating under Bankruptcy Court protection for a long period of time may harm our business.

Our future results are dependent upon the successful confirmation and implementation of a plan of reorganization. A long period of operations under Bankruptcy Court protection could have a material adverse effect on our business, results of operations and liquidity. So long as the proceedings related to the Chapter 11 proceedings continue, our senior management will be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing exclusively on our business operations. A prolonged period of operating under Bankruptcy Court protection also may make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, the longer the proceedings related to the Chapter 11 proceedings continue, the more likely it is that our customers and suppliers will lose confidence in our ability to reorganize our business successfully and will seek to establish alternative commercial relationships.

Furthermore, so long as the proceedings related to the Chapter 11 proceedings continue, we will be required to incur substantial costs for professional fees and other expenses associated with the administration of the Chapter 11 proceeding. If we are unable to fund these expenses, our chances of successfully reorganizing our business may be seriously jeopardized, the likelihood that we instead will be required to liquidate our assets may be enhanced, and, as a result, any securities in the Debtor could become further devalued or become worthless.

Furthermore, we cannot predict the ultimate amount of all settlement terms for the liabilities that will be subject to a plan of reorganization. Even once a plan of reorganization is approved and implemented, our operating results may be adversely affected by the possible reluctance of prospective lenders and other counterparties to do business with a company that recently emerged from Chapter 11 proceedings.

The Plan Support Agreement provides that the shares of our existing common stock will be cancelled in our Chapter 11 proceedings.

We have a significant amount of indebtedness that is senior to our existing common stock in our capital structure. The Plan Support Agreement provides that the shares of our existing common stock will be cancelled in our Chapter 11 proceedings and will be entitled to a limited recovery, if any. Any trading in shares of our common stock during the pendency of the Chapter 11 proceedings is highly speculative and poses substantial risks to purchasers of shares of our common stock.

We may not be able to obtain confirmation of a Chapter 11 plan of reorganization

To emerge successfully from Bankruptcy Court protection as a viable entity, we must meet certain statutory requirements with respect to adequacy of disclosure with respect to a Chapter 11 plan of reorganization (the “Plan”), solicit and obtain the requisite acceptances of such a plan and fulfill other statutory conditions for confirmation of such a plan, which have not occurred to date. The confirmation process is subject to numerous, unanticipated potential delays, including a delay in the Bankruptcy Court’s commencement of the confirmation hearing regarding our Plan.

Prior to filing the Chapter 11 Cases, we entered into the Plan Support Agreement with certain of our creditors. The restructuring transactions contemplated by the Plan Support Agreement will be effectuated through the Plan. However, we may not receive the requisite acceptances of constituencies in the proceedings related to the Chapter 11 proceedings to confirm our Plan. Even if the requisite acceptances of the Plan are received, the Bankruptcy Court may not confirm such a plan. The precise requirements and evidentiary showing for confirming a plan, notwithstanding its rejection by one or more impaired classes of claims or equity interests, depends upon a number of factors including, without limitation, the status and seniority of the claims or equity interests in the rejecting class (i.e., secured claims or unsecured claims, subordinated or senior claims, preferred or common stock).

If a Chapter 11 plan of reorganization is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if anything, holders of claims against us would ultimately receive with respect to their claims.

Even if a Chapter 11 plan of reorganization is consummated, we will continue to face risks

Even if a Chapter 11 plan of reorganization is consummated, we will continue to face a number of risks, including certain risks that are beyond our control, such as further deterioration or other changes in economic conditions, changes in our industry, potential revaluing of our assets due to Chapter 11 proceedings, changes in consumer demand for, and acceptance of, our oil and gas and increasing expenses. Some of these concerns and effects typically become more acute when a case under the Bankruptcy Code continues for a protracted period without indication of how or when the case may be completed. As a result of these risks and others, there is no guaranty that a Chapter 11 plan of reorganization reflecting the Plan will achieve our stated goals.

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In addition, at the outset of the Chapter 11 proceedings, the Bankruptcy Code gives the Debtor the exclusive right to propose the Plan and prohibits creditors, equity security holders and others from proposing a plan. We have currently retained the exclusive rights to propose the Plan. If the Bankruptcy Court terminates that right, however, or the exclusivity period expires, there could be a material adverse effect on our ability to achieve confirmation of the Plan in order to achieve our stated goals. Furthermore, even if our debts are reduced or discharged through the Plan, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of the proceedings related to the Chapter 11 proceedings. The Plan Support Agreement contemplates an exit financing facility, but there is no guarantee that such financing will be obtained on acceptable terms in accordance with the Plan Support Agreement, or at all. Adequate funds may not be available when needed or may not be available on favorable terms.

We have substantial liquidity needs and may be required to seek additional financing. If we are unable to obtain financing on satisfactory terms or maintain adequate liquidity, our ability to replace our proved reserves or to maintain current production levels and generate revenue will be limited.

Our principal sources of liquidity historically have been cash flows from operations, borrowings under our Credit Facility and issuances of debt securities. Our capital program will require additional financing above the level of cash generated by our operations to fund growth. If our cash flow from operations remains depressed or decreases as a result of lower commodity prices or otherwise, our ability to expend the capital necessary to replace our proved reserves, maintain our leasehold acreage or maintain current production may be limited, resulting in decreased production and proved reserves over time. In addition, drilling activity may be directed by our partners in certain areas and we may have to forfeit acreage if we do not have sufficient capital resources to fund our portion of expenses.

We face uncertainty regarding the adequacy of our liquidity and capital resources and have extremely limited, if any, access to additional financing. In addition to the cash requirement necessary to fund ongoing operations, we have incurred significant professional fees and costs throughout our Chapter 11 proceedings. We cannot assure you that cash on hand and cash flow from operations will be sufficient to continue to fund our operations and allow us to satisfy our obligations related to Chapter 11 cases until we are able to emerge from our Chapter 11 proceedings.

Our liquidity, including our ability to meet our ongoing operation obligations, is dependent upon, among other things; (i) our ability to comply with the terms and conclusion of any cash collateral order entered by the Bankruptcy Court in connection with the Chapter 11 proceedings, (ii) our ability to maintain adequate cash on hand, (iii) our ability to generate cash flow from operations, (iv) our ability to develop, confirm and consummate a Chapter 11 plan or other alternative restructuring transaction, and (v) the cost, duration and outcome of the Chapter 11 proceedings. Our ability to maintain adequate liquidity depends in part upon industry conditions and general economic, financial, competitive, regulatory and other factors beyond our control. In the event that cash on hand and cash flow from operation is not sufficient to meet our liquidity needs, we may be required to see additional financing. We can provide no assurance that additional financing would be available or, if available, offered to us on acceptable terms. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited if it is available at all. Our long-term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time.

In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.

If the Bankruptcy Court finds that it would be in the best interest of creditors and/or the Debtors, the Bankruptcy Court may convert our Chapter 11 bankruptcy case to a case under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate the Debtors’ assets for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under Chapter 7 would result in a significantly smaller distributions being made to our creditors than those provided for in a Chapter 11 plan because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a disorderly fashion over a short period of time rather than reorganizing or selling in a controlled manner our businesses as a going concern, (ii) additional administrative expenses involved in the appointment of a Chapter 7 trustee, and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with cessation of operations.

We may be subject to claims that will not be discharged in the Chapter 11 proceedings, which could have a material adverse effect on our financial condition and results or operations.

The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arose prior to April 30, 2016 or before confirmation of the plan of reorganization (i) would be subject to compromise and/or treatment under the plan of reorganization and/or (ii) would be discharged in accordance with the terms of the plan of reorganization. Any claims not ultimately discharged through a plan of reorganization could be asserted against the reorganized entities and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis.

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Our financial results may be volatile and may not reflect historical trends.

During the Chapter 11 proceedings, we expect our financial results to continue to be volatile as asset impairments, asset dispositions, restructuring activities and expenses, contract terminations and rejections, and claims assessments significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance after the date of the bankruptcy filing.

In addition, if we emerge from Chapter 11, the amounts reported in subsequent consolidated financial statements may materially change relative to historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to a plan of reorganization. We also may be required to adopt fresh start accounting, in which case our assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets. Our financial results after the application of fresh start accounting also may be different from historical trends.

Transfers of our equity, or issuances of equity in connection with our Chapter 11 proceedings, may impair our ability to utilize our federal income tax net operating loss carryforwards in future years.

Under federal income tax law, a corporation is generally permitted to deduct from taxable income net operating losses carried forward from prior years. Our ability to utilize our net operating loss carryforwards to offset future taxable income and to reduce federal income tax liability is subject to certain requirements and restrictions. If we experience an “ownership change,” as defined in section 382 of the Internal Revenue Code, then our ability to use our net operating loss carryforwards may be substantially limited, which could have a negative impact on our financial position and results of operations. Generally, there is an “ownership change” if one or more stockholders owning 5% or more of a corporation’s common stock have aggregate increases in their ownership of such stock of more than 50 percentage points over the prior three-year period. Following the implementation of a plan of reorganization, it is possible that an “ownership change” may be deemed to occur. Under section 382 of the Internal Revenue Code, absent an applicable exception, if a corporation undergoes an “ownership change,” the amount of its net operating losses that may be utilized to offset future taxable income generally is subject to an annual limitation. Even if the net operating loss carryforwards is subject to limitation under Section 382, the net operating losses can be reduced from the amount of discharge of indebtedness arising in a Chapter 11 case under Section 108 of the Internal Revenue Code.

We have significant exposure to fluctuations in commodity prices since none of our estimated future production is covered by commodity derivatives and we may not be able to enter into commodity derivatives covering our estimated future production on favorable terms or at all.

During the Chapter 11 proceedings, our ability to enter into new commodity derivatives covering additional estimated future production will be dependent upon either entering into unsecured hedges or obtaining Bankruptcy Court approval to enter into secured hedges. As a result, we may not be able to enter into additional commodity derivatives covering our production in future periods on favorable terms or at all. If we cannot or choose not to enter into commodity derivatives in the future, we could be more affected by changes in commodity prices than our competitors who engage in hedging arrangements. Our inability to hedge the risk of low commodity prices in the future, on favorable terms or at all, could have a material adverse impact on our business, financial condition and results of operations.

If we are able to enter into any commodity derivatives, they may limit the benefit we would receive from increases in commodity prices. These arrangements would also expose us to risk of financial losses in some circumstances, including (i) our production could be materially less than expected or (ii) the counterparties to the contracts could fail to perform their contractual obligations. If our actual production and sales for any period are less than the production covered by any commodity derivatives (including reduced production due to operational delays) or if we are unable to perform our exploration and development activities as planned, we might be required to satisfy a portion of our obligation under those commodity derivatives without the benefit of the cash flow from the sale of that production, which may materially impact our liquidity. Additionally, if market prices for our production exceed collar ceilings or swap prices, we would be required to make monthly cash payments, which could materially adversely affect our liquidity.

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Loss of additional personnel could adversely affect our operations.

Our operations are dependent on a relatively small group of key management personnel, including our executive officers. Our recent liquidity issues and our Chapter 11 proceedings have created distractions and uncertainty for our key management personnel and our employees. As a result, we have experienced and may continue to experience increased levels of employee attrition. Because competition for experienced personnel in our industry can be intense, we may be unable to find acceptable replacements with comparable skills and experience and their loss could adversely affect our ability to operate our business. In addition, a loss of key personnel or material erosion of employee morale, at the corporate and field levels, could have a material adverse effect on our ability to meet customer and counterparty expectations, thereby adversely affecting our business and results of operations.

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

None.

Item 3. Defaults Upon Senior Securities

See Part I, Item 1, Note 2 to our unaudited condensed consolidated financial statements entitled “Chapter 11 Proceedings, Liquidity and Ability to Continue as a Going Concern,” which is incorporated in this item by reference.

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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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: May 13, 2016	/s/ Frederic F. Brace
	Frederic F. Brace
	Interim President and Chief Executive Officer
	(Principal Executive Officer)

Dated: May 13, 2016	/s/ Nelson M. Haight
	Nelson M. Haight
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)

Dated: May 13, 2016	/s/ Richard W. McCullough
	Richard W. McCullough
	Vice President and Chief Accounting Officer
	(Principal Accounting Officer)

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EXHIBIT INDEX

3.1	Amended and Restated Certificate of Incorporation of Midstates Petroleum Company, Inc. (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on April 25, 2012, and incorporated herein by reference).

3.2	Certificate of Amendment of the Amended and Restated Certificate of Incorporation of Midstates Petroleum Company, Inc. (filed as Appendix A to the Company’s 2014 Proxy Statement filed on April 8, 2014 and incorporated herein by reference.)

3.3	Certificate of Amendment of the Amended and Restated Certificate of Incorporation of Midstates Petroleum Company, Inc. (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on August 4, 2015, and incorporated herein by reference).

3.4	Amended and Restated Bylaws of Midstates Petroleum Company, Inc. (filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on April 25, 2012, and incorporated herein by reference).

3.5	Certificate of Designations of Series A Mandatorily Convertible Preferred Stock of Midstates Petroleum Company, Inc. (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on October 2, 2012, and incorporated herein by reference).

4.1	Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-1/A on February 29, 2012, and incorporated herein by reference).

4.2	Indenture, dated October 1, 2012, by and among the Company, Midstates Petroleum Company LLC and Wells Fargo Bank, National Association, as trustee, governing the 10.75% senior notes due 2020 (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on October 2, 2012, and incorporated herein by reference).

4.3	Registration Rights Agreement, dated October 1, 2012, by and among the Company, Midstates Petroleum Company LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers named therein, relating to the 10.75% senior notes due 2020 (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on October 2, 2012, and incorporated herein by reference).

4.4	Registration Rights Agreement, dated October 1, 2012, by and among the Company, Eagle Energy Production, LLC, FR Midstates Interholding, LP and certain other of the Company’s stockholders (filed as Exhibit 4.3 to the Company’s Current Report on Form 8-K filed on October 2, 2012, and incorporated herein by reference).

4.5	Indenture, dated May 31, 2013, by and among the Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC and the Well Fargo Bank, National Association, as trustee, governing the 9.25% senior notes due 2021 (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on June 3, 2013, and incorporated herein by reference).

4.6	Registration Rights Agreement, dated May 31, 2013, by and among the Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC and Morgan Stanley & Co. LLC and SunTrust Robinson Humphrey, Inc., as representatives of the several initial purchasers named therein, relating to the 9.25% senior notes due 2021 (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on June 3, 2013, and incorporated herein by reference).

4.7	Indenture, dated May 21, 2015, by and among Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC and, Wilmington Trust, National Association, as trustee, governing the Second Lien Notes (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on May 22, 2015, and incorporated herein by reference).

4.8	Indenture, dated May 21, 2015, by and among Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC and Wilmington Trust, National Association, as trustee, governing the Third Lien Notes (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on May 22, 2015, and incorporated herein by reference).

10.1	Plan Support Agreement, dated as of April 30, 2016, by and among Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC and the supporting parties thereto. (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 2, 2016, 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

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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