UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2015

OR

oTRANSITION 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 x
Non-accelerated filer o	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 4, 2015 is shown below:

Class	Number of shares outstanding
Common stock, $0.01 par value	71,719,939

MIDSTATES PETROLEUM COMPANY, INC.

QUARTERLY REPORT ON

FORM 10-Q

FOR THE THREE MONTHS ENDED MARCH 31, 2015

TABLE OF CONTENTS

	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, 2015 and December 31, 2014 (unaudited)	4
Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2015 and 2014 (unaudited)	5
Condensed Consolidated Statements of Changes in Stockholders’ Equity for the Three Months Ended March 31, 2015 and 2014 (unaudited)	6
Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2015 and 2014 (unaudited)	7
Notes to Unaudited Condensed Consolidated Financial Statements	8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3. Quantitative and Qualitative Disclosures About Market Risk	31
Item 4. Controls and Procedures	32
PART II - OTHER INFORMATION
Item 1. Legal Proceedings	34
Item 1A. Risk Factors	34
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	37
Item 3. Defaults upon Senior Securities	37
Item 4. Mine Safety Disclosures	37
Item 5. Other Information	37
Item 6. Exhibits	37
SIGNATURES	38
EXHIBIT INDEX	39

2

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.

3

PART I - FINANCIAL INFORMATION

MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands, except share amounts)

	March 31, 2015			December 31, 2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	11,941		$	11,557
Accounts receivable:
Oil and gas sales	56,843			69,161
Joint interest billing	28,550			42,407
Other	20,157			22,193
Commodity derivative contracts	95,473			126,709
Other current assets	2,119			1,098
Total current assets	215,083			273,125
PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of full-cost accounting	3,532,976			3,442,681
Other property and equipment	13,845			13,454
Less accumulated depreciation, depletion, amortization and impairment	(1,566,043		)	(1,333,019		)
Net property and equipment	1,980,778			2,123,116
OTHER ASSETS:
Deferred income taxes	33,119			35,821
Other noncurrent assets	42,619			43,731
Total other assets	75,738			79,552
TOTAL	$	2,271,599		$	2,475,793
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	24,006		$	22,783
Accrued liabilities	182,488			183,831
Deferred income taxes	33,119			44,862
Total current liabilities	239,613			251,476
LONG-TERM LIABILITIES:
Asset retirement obligations	22,044			21,599
Long-term debt	1,735,150			1,735,150
Other long-term liabilities	1,486			1,706
Total long-term liabilities	1,758,680			1,758,455
COMMITMENTS AND CONTINGENCIES (Note 15)
STOCKHOLDERS’ EQUITY:
Preferred stock, $0.01 par value, 49,675,000 shares authorized; no shares issued or outstanding	—			—
Series A mandatorily convertible preferred stock, $0.01 par value, $395,412 and $387,808 liquidation value at March 31, 2015 and December 31, 2014, respectively; 8% cumulative dividends; 325,000 shares issued and outstanding	3			3
Common stock, $0.01 par value, 300,000,000 shares authorized; 72,440,407 shares issued and 71,650,849 shares outstanding at March 31, 2015 and 70,491,732 shares issued and 69,957,055 shares outstanding at December 31, 2014	724			704
Treasury stock, at cost	(2,897		)	(2,592		)
Additional paid-in-capital	883,177			881,894
Retained deficit	(607,701		)	(414,147		)
Total stockholders’ equity	273,306			465,862
TOTAL	$	2,271,599		$	2,475,793

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

4

MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share amounts)

	For the Three Months Ended March 31,
	2015			2014
REVENUES:
Oil sales	$	59,257		$	116,222
Natural gas liquid sales	11,010			25,519
Natural gas sales	19,172			25,385
Gains (losses) on commodity derivative contracts - net	21,372			(22,673		)
Other	387			209
Total revenues	111,198			144,662
EXPENSES:
Lease operating and workover	23,262			20,127
Gathering and transportation	3,438			2,855
Severance and other taxes	3,565			7,647
Asset retirement accretion	445			497
Depreciation, depletion, and amortization	58,428			66,901
Impairment in carrying value of oil and gas properties	174,667			86,471
General and administrative	11,654			11,684
Acquisition and transaction costs	—			128
Advisory fees	1,743			—
Other	97			330
Total expenses	277,299			196,640
OPERATING INCOME (LOSS)	(166,101		)	(51,978		)
OTHER INCOME (EXPENSE):
Interest income	9			10
Interest expense — net of amounts capitalized	(36,503		)	(33,947		)
Total other income (expense)	(36,494		)	(33,937		)
LOSS BEFORE TAXES	(202,595		)	(85,915		)
Income tax benefit	9,041			2,270
NET LOSS	$	(193,554	)	$	(83,645	)
Preferred stock dividend	(131		)	(2,620		)
Participating securities - Series A Preferred Stock	—			—
Participating securities - Non-vested Restricted Stock	—			—
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(193,685	)	$	(86,265	)
Basic and diluted net loss per share attributable to common shareholders	$	(2.88	)	$	(1.31	)
Basic and diluted weighted average number of common shares outstanding	67,261			65,987

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

5

MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

(In thousands)

	Series A Preferred Stock		Common Stock		Treasury Stock			Additional Paid-in- Capital		Retained Deficit			Total Stockholders’ Equity
Balance as of December 31, 2014	$	3	$	704	$	(2,592	)	$	881,894	$	(414,147	)	$	465,862
Share-based compensation	—		20		—			1,283		—			1,303
Acquisition of treasury stock	—		—		(305		)	—		—			(305		)
Net loss	—		—		—			—		(193,554		)	(193,554		)
Balance as of March 31, 2015	$	3	$	724	$	(2,897	)	$	883,177	$	(607,701	)	$	273,306

	Series A Preferred Stock		Common Stock		Treasury Stock			Additional Paid-in- Capital		Retained Deficit			Total Stockholders’ Equity
Balance as of December 31, 2013	$	3	$	689	$	(664	)	$	871,047	$	(531,076	)	$	339,999
Share-based compensation	—		16		—			2,049		—			2,065
Acquisition of treasury stock	—		—		(649		)	—		—			(649		)
Net loss	—		—		—			—		(83,645		)	(83,645		)
Balance as of March 31, 2014	$	3	$	705	$	(1,313	)	$	873,096	$	(614,721	)	$	257,770

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

6

MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Three Months Ended March 31,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(193,554	)	$	(83,645	)
Adjustments to reconcile net loss to net cash provided by operating activities:
(Gains) losses on commodity derivative contracts — net	(21,372		)	22,673
Net cash received (paid) for commodity derivative contracts	52,608			(14,810		)
Asset retirement accretion	445			497
Depreciation, depletion, and amortization	58,428			66,901
Impairment in carrying value of oil and gas properties	174,667			86,471
Share-based compensation, net of amounts capitalized to oil and gas properties	801			1,541
Deferred income taxes	(9,041		)	(2,270		)
Amortization of deferred financing costs	1,869			2,386
Change in operating assets and liabilities:
Accounts receivable — oil and gas sales	27,572			(2,767		)
Accounts receivable — JIB and other	13,475			(8,116		)
Other current and noncurrent assets	(1,089		)	(3,972		)
Accounts payable	322			2,813
Accrued liabilities	8,106			37,170
Other	(220		)	537
Net cash provided by operating activities	$	113,017		$	105,409
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment	(111,167		)	(122,780		)
Net cash used in investing activities	$	(111,167	)	$	(122,780	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Deferred financing costs	(1,161		)	(495		)
Acquisition of treasury stock	(305		)	(649		)
Net cash used in financing activities	$	(1,466	)	$	(1,144	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	384			(18,515		)
Cash and cash equivalents, beginning of period	$	11,557		$	33,163
Cash and cash equivalents, end of period	$	11,941		$	14,648
SUPPLEMENTAL INFORMATION:
Non-cash transactions — investments in property and equipment accrued - not paid	$	71,900		$	134,000
Cash paid for interest, net of capitalized interest of $1.0 million and $4.6 million, respectively	2,321			—

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

7

MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

1. Organization and Business

Midstates Petroleum Company, Inc., through its wholly owned subsidiary Midstates Petroleum Company LLC, engages in the business of drilling for, and 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 its subsidiary, unless the context indicates otherwise.

The Company has oil and gas operations and properties in Oklahoma, Texas and Louisiana. At March 31, 2015, the Company operated oil and natural gas properties as one reportable segment engaged in the exploration, development and production of oil, natural gas liquids and natural gas. The Company’s management evaluates performance based on one reportable segment as all our operations are located in the United States and therefore we maintain one cost center.

2. Liquidity and Capital Resources

As of March 31, 2015, the Company had available cash of approximately $11.9 million and availability under its reserve based revolving credit facility (the “Credit Facility”) of approximately $88.4 million. As of March 31, 2015, payments due on contractual obligations during the remainder of 2015, as well as for the years ending December 31, 2016 and 2017 are approximately $143.5 million, $132.0 million and $131.2 million, respectively. This includes approximately $387.8 million of interest payments on the senior notes, but excludes interest on our Credit Facility, for the remainder of 2015, as well as for the years ending December 31, 2016 and 2017.  The Company believes it will need to complete certain transactions, including management of debt capital structure and potential asset sales, to have sufficient liquidity to satisfy these obligations, as well as other obligations such as fixed drilling commitments and operating leases, in the long term.

Liquidity Sufficiency

As a result of substantial declines in oil and gas prices during the latter half of 2014 and continuing into the first part of 2015, the liquidity outlook of the Company has been impacted.  As a result, we expect lower operating cash flows than previously experienced and if commodity prices continue to remain low, our liquidity will be further impacted as current hedging contracts expire.  During the three months ended March 31, 2015, the Company received cash payments on settled derivative contracts of $52.6 million.  Such cash payments will not be received in 2016 and future periods due to the expiration of our hedging contracts.

As a result of the commodity price decline and the Company’s substantial debt burden, the Company continues to believe forecasted cash and expected available credit capacity will not be sufficient to meet commitments as they come due and, absent a material improvement in oil and gas prices, the Company will not be able to remain in compliance with current debt covenants unless able to successfully increase liquidity. Additionally, while the terms of the Credit Facility were amended in March 2015 to allow the divestiture of certain of its oil and gas properties in Beauregard and Calcasieu Parishes, Louisiana, which closed on April 21, 2015 (“Sale of Dequincy”), with no associated reduction in the borrowing base of the Credit Facility, absent additional amendments, the terms of the Credit Facility and the indentures governing the senior notes require that some or all of the proceeds from certain future asset sales be used to permanently reduce outstanding debt, which could substantially reduce the amount of proceeds retained.  Additionally, the covenants in these debt instruments impose limitations on the amount and type of additional indebtedness the Company can incur, which may significantly reduce the ability to obtain liquidity through the incurrence of additional indebtedness. Furthermore, the ability to refinance any of the existing indebtedness on commercially reasonable terms may be materially and adversely impacted by the current conditions in the energy industry and the Company’s financial condition.

The interest payment obligations are substantial, and the Company is required to pay approximately $32 million in interest on the 2020 Senior Notes (as defined below) on each of April 1 and October 1 and approximately $32 million in interest on the 2021 Senior Notes (as defined below) on each of June 1 and December 1. The Company received a going concern qualification from its independent registered public accounting firm for the year ended December 31, 2014, but obtained a waiver to the Credit Facility waiving any default as a result of receiving such qualification. As the Company pursues the actions mentioned above to increase liquidity, it will likely need to negotiate additional waivers or amendments to the Credit Facility or indentures to facilitate those actions. There can be no assurance that the lenders or the holders of the senior notes will agree to any amendment or waiver on acceptable terms and if a default occurs, a failure to do so may provide the lenders the opportunity to accelerate the outstanding debt under these facilities and it would be classified as a current liability on the balance sheet.

The uncertainty associated with the Company’s ability to meet commitments as they come due or to repay outstanding debt raises substantial doubt about the Company’s ability to continue as a going concern. The accompanying financial statements do not include

8

any adjustments related to the recoverability and classification of recorded assets or the amounts and classification of liabilities that might result from the uncertainty associated with the ability to meet obligations as they come due.

The Company continues to pursue a number of actions including (i) actively managing the debt capital structure, (ii) selling additional assets, (iii) minimizing capital expenditures, (iv) obtaining waivers or amendments from lenders, (v) effectively managing working capital and (vi) improving cash flows from operations. As previously announced, in early 2015 the Company engaged Evercore and Kirkland & Ellis to assist with reviewing all options to improve its liquidity profile and strengthen its balance sheet. These efforts continue in earnest and the Company is considering all available strategic alternatives and financing possibilities, including, without limitation, the incurrence of additional secured indebtedness and the exchange or refinancing of existing obligations.  We can provide no assurance that these discussions will result in the completion of a transaction, or that any completed transaction will result in sufficient liquidity to satisfy our obligations.

Financial Ratio Covenants

As of March 31, 2015, the ratio of net consolidated indebtedness to EBITDA was 3.7:1.0 and the ratio of current assets to current liabilities was 1.0:1.0. As calculated for covenant compliance purposes, the Company’s current assets exceeded its current liabilities by approximately $1.5 million at March 31, 2015. If liquidity concerns are not addressed in the near term, the Company will likely breach the financial ratio covenants of the Credit Facility in 2015. As of March 31, 2015, the Company was in compliance with the financial ratio covenants included in the Credit Facility.

Borrowing Base Redetermination

On March 24, 2015, the Company and Midstates Sub entered into a Sixth Amendment (the “Sixth Amendment”) to the Second Amended and Restated Credit Agreement dated as of June 8, 2012, among Midstates, Midstates Sub, as borrower, SunTrust Bank, N.A., as administrative agent, and the lenders and other parties thereto (the “Credit Agreement”). The Sixth Amendment provides that Midstates Sub’s borrowing base will remain at its current size of $525.0 million as part of the regular semi-annual borrowing base redetermination under the Credit Agreement. The Sixth Amendment also confirmed that the borrowing base will not be reduced as a result of the Sale of Dequincy. The Sixth Amendment amends the required ratio of net consolidated indebtedness to EBITDA under the Credit Agreement for each of the fiscal quarters in 2015 from 4.0:1.0 to 4.5:1.0.  Additionally, the Sixth Amendment amends the mortgage requirements under the Credit Agreement to provide for an increase from 80% to 90% for the percentage of properties included in the borrowing base that are required to be subject to mortgages for the benefit of the lenders.

Cross Default Provisions

The Company’s debt facilities contain significant cross default and/or cross acceleration provisions where a default under the Credit Facility or one of the indentures could enable the lenders of the other debt to also declare events of default and accelerate repayment of the obligations under those debt instruments. In general, these cross default/cross acceleration provisions are as follows:

·The Credit Facility allows the lenders to declare an event of default if there is an event of default on other indebtedness and that default: (i) is the result of the failure to make any payment when due in respect of other indebtedness having an aggregate principal amount of at least 5% of the then effective borrowing base and such failure continues after the applicable grace or notice period; or (ii) is the result of a failure to perform any condition, covenant or other event and such failure permits the holders of such other indebtedness to cause the acceleration of such other indebtedness.

·The indentures governing the senior notes allow the lenders to declare an event of default if there is an event of default on other indebtedness and that default: (i) is caused by a failure to make any payment of principal prior to the expiration of the grace period following the final maturity date of such indebtedness; or (ii) results in the acceleration of such indebtedness prior to its stated maturity, and, in each case, the principal amount of any such indebtedness, together with the principal amount of any other indebtedness with respect to which an event described herein has occurred, aggregates $50.0 million or more.

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, 2014 included in the Company’s Annual Report on Form 10-K as filed with the SEC on March 16, 2015.

9

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.

Recently Issued Standards Not Yet Adopted

In April 2015, the FASB issued Accounting Standards Update 2015-03 “Interest-Imputation of Interest (Subtopic 835-30):  Simplifying the Presentation of Debt Issuance Costs” (“ASU 2015-03”).  ASU 2015-03 requires that debt issuance costs related to a recognized liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts.  The recognition and measurement guidance for debt issuance costs is not affected by ASU 2015-03.  ASU 2015-03 is effective retrospectively for the Company beginning on January 1, 2016.  The Company does not expect the reclassification of debt issuance costs on the Company’s consolidated balance sheet as a result of the adoption of ASU 2015-03 to have a material impact on its consolidated financial statements or related disclosures.

Correction of Operating and Investing Cash Flows for the Three Months Ended March 31, 2014

In the first quarter of 2015, the Company determined that it had incorrectly presented non-cash accrued capital expenditures in its Statements of Cash Flows since December 31, 2012. Management concluded the misstatement is immaterial to previously issued financial statements; however, the Company has corrected the cash flow presentation in the accompanying Condensed Consolidated Statement of Cash Flows for the three months ended March 31, 2014. There was no impact of the misstatement on the Condensed Consolidated Balance Sheet as of December 31, 2014, or on the Condensed Consolidated Statement of Operations for the three months ended March 31, 2014. The impact of the correction is shown in the table below (in thousands):

	For the Three Months Ended March 31, 2014
Statement of Cash Flows	As Previously Reported			As Restated
Change in operating assets and liabilities:
accounts receivable - JIB and other	$	(16,093	)	$	(8,116	)
Net cash provided by operating activities	97,432			105,409
Investment in property and equipment	(114,803		)	(122,780		)
Net cash used in investing activities	(114,803		)	(122,780		)

4. Fair Value Measurements of Financial Instruments

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Derivative Instruments

Commodity derivative contracts reflected in the condensed consolidated balance sheets are recorded at estimated fair value. At March 31, 2015 and December 31, 2014, all of the Company’s commodity derivative contracts were with seven bank counterparties and were classified as Level 2 in the fair value input hierarchy.

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

	Fair Value Measurements at March 31, 2015
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in thousands)
Assets:
Commodity derivative oil swaps	$	—	$	79,344	$	—	$	79,344
Commodity derivative gas swaps	—		16,129		—		16,129
Total assets	$	—	$	95,473	$	—	$	95,473
Liabilities:
Commodity derivative oil swaps	$	—	$	—	$	—	$	—
Commodity derivative gas swaps	—		—		—		—
Total liabilities	$	—	$	—	$	—	$	—

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	Fair Value Measurements at December 31, 2014
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in thousands)
Assets:
Commodity derivative oil swaps	$	—	$	106,450	$	—	$	106,450
Commodity derivative gas swaps	—		20,259		—		20,259
Total assets	$	—	$	126,709	$	—	$	126,709
Liabilities:
Commodity derivative oil swaps	$	—	$	—	$	—	$	—
Commodity derivative gas swaps	—		—		—		—
Total liabilities	$	—	$	—	$	—	$	—

5. Risk Management and Derivative Instruments

The Company’s production is exposed to fluctuations in crude oil, NGLs and natural gas prices. The Company periodically utilizes derivative financial instruments to provide partial protection against declines in oil, natural gas and NGLs prices by reducing the risk of price volatility and the effect such volatility could have on the Company’s operations and its ability to finance its capital budget and operations. The Company’s decision on the quantity and price at which it chooses to hedge its production is based on its view of existing and forecasted oil, natural gas and NGLs production volumes, planned drilling projects and current and future market conditions. The Company currently utilizes swaps to manage 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 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.

Inherent in the Company’s portfolio of commodity derivative contracts are certain business risks, including market risk and credit risk. Market risk is the risk that the price of the commodity will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract. The Company does not require collateral from its counterparties but does attempt to minimize its credit risk associated with derivative instruments by entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. In addition, to mitigate its risk of loss due to default, the Company has entered into agreements with its counterparties on its derivative instruments that allow the Company to offset its asset position with its liability position in the event of default by the counterparty. Due to the netting arrangements, had the Company’s counterparties failed to perform under existing commodity derivative contracts, the maximum loss at March 31, 2015 would have been approximately $95.5 million.

Commodity Derivative Contracts

As of March 31, 2015, the Company had the following open commodity derivative contract positions:

	Hedged Volume	Weighted-Average Fixed Price
Oil (Bbls):
WTI Swaps — 2015	2,196,000	$	88.04
Natural Gas (MMBtu):
Swaps — 2015 (1)	13,750,000	$	4.13

(1)Includes 1,500,000 MMBtus in natural gas swaps that priced during the period, but had not cash settled as of March 31, 2015.

Balance Sheet Presentation

The following table summarizes the gross fair values of derivative instruments by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s unaudited condensed consolidated balance sheets at March 31, 2015 and December 31, 2014, respectively (in thousands):

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Type	Balance Sheet Location (1)	March 31, 2015		December 31, 2014
Oil Swaps	Derivative financial instruments — Current Assets	$	79,344	$	106,450
Gas Swaps	Derivative financial instruments — Current Assets	16,129		20,259
Total derivative fair value at period end		$	95,473	$	126,709

(1)The fair values of commodity derivative instruments reported in the Company’s consolidated balance sheets are subject to netting arrangements and qualify for net presentation. The following table summarizes the location and fair value amounts of all derivative instruments in the consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheets at March 31, 2015 and December 31, 2014, respectively (in thousands):

		March 31, 2015
Not Designated as ASC 815 Hedges:	Balance Sheet Classification	Gross Recognized Assets/ Liabilities		Gross Amounts Offset		Net Recognized Fair Value Assets/ Liabilities
Derivative assets:
Commodity contracts	Derivative financial instruments - current	$	95,473	$	—	$	95,473
Commodity contracts	Derivative financial instruments - noncurrent	—		—		—
		$	95,473	$	—	$	95,473
Derivative liabilities:
Commodity contracts	Derivative financial instruments - current	$	—	$	—	$	—
Commodity contracts	Derivative financial instruments - noncurrent	—		—		—
		$	—	$	—	$	—

		December 31, 2014
Not Designated as ASC 815 Hedges:	Balance Sheet Classification	Gross Recognized Assets/ Liabilities		Gross Amounts Offset		Net Recognized Fair Value Assets/ Liabilities
Derivative assets:
Commodity contracts	Derivative financial instruments - current	$	126,709	$	—	$	126,709
Commodity contracts	Derivative financial instruments - noncurrent	—		—		—
		$	126,709	$	—	$	126,709
Derivative liabilities:
Commodity contracts	Derivative financial instruments - current	$	—	$	—	$	—
Commodity contracts	Derivative financial instruments - noncurrent	—		—		—
		$	—	$	—	$	—

Gains (losses) on Commodity Derivative Contracts

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

The following table presents “Gains (losses) on commodity derivative contracts — net” for the periods presented:

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	For the Three Months Ended March 31,
	2015			2014
	(in thousands)
Net cash received (paid) for commodity derivative contracts	$	52,608		$	(14,810	)
Unrealized net losses	(31,236		)	(7,863		)
Gains (losses) on commodity derivative contracts - net	$	21,372		$	(22,673	)

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

6. Property and Equipment

	March 31, 2015			December 31, 2014
	(in thousands)
Oil and gas properties, on the basis of full-cost accounting:
Proved properties	$	3,491,783		$	3,398,146
Unevaluated properties	41,193			44,535
Other property and equipment	13,845			13,454
Less accumulated depreciation, depletion, amortization and impairment	(1,566,043		)	(1,333,019		)
Net property and equipment	$	1,980,778		$	2,123,116

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, 2015 and 2014, the Company capitalized the following amounts (in thousands):

	Three Months Ended March 31,
	2015		2014
Internal costs capitalized to oil and gas properties (1)	$	2,302	$	3,124

(1)Inclusive of $0.5 million of qualifying share-based compensation expense for the three months ended March 31, 2015 and 2014.

The Company accounts for its oil and gas properties under the full cost method. Under the full cost method, proceeds 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 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.

At March 31, 2015 and 2014, capitalized costs exceeded the ceiling and the Company recorded an impairment of oil and gas properties of $174.7 million and $86.5 million, respectively.  The impairment at March 31, 2015 was primarily due to 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 based upon estimates of proved reserve quantities, the Company’s costs incurred for proved developed properties and costs expected to be incurred to develop its proved

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undeveloped reserves.   The following table presents depletion expense related to oil and gas properties for the three months ended March 31, 2015 and 2014, respectively:

	Three Months Ended March 31,
	2015		2014		2015		2014
	(in thousands)				(per Boe)
Depletion expense	$	57,605	$	66,204	$	18.73	$	25.37
Depreciation on other property	823		697		0.27		0.26
Depreciation, depletion, and amortization	$	58,428	$	66,901	$	19.00	$	25.63

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. Unevaluated property was $41.2 million and $44.5 million at March 31, 2015 and December 31, 2014, respectively.

Sale of Dequincy Assets

On April 21, 2015, the Company closed on the sale of its ownership interest in developed and undeveloped acreage in the Dequincy area located in Beauregard and Calcasieu Parishes, Louisiana for $44 million to Pintail Oil and Gas LLC. The net proceeds of approximately $42 million, which was net of customary closing adjustments, will be reflected as a reduction of oil and natural gas properties, with no gain or loss recognized. The proceeds from the sale will be used to pay down a portion of the outstanding borrowings under the Company’s revolving credit facility and for general corporate purposes.

7. Other Noncurrent Assets

At March 31, 2015 and December 31, 2014 other noncurrent assets consisted of the following:

	March 31, 2015		December 31, 2014
	(in thousands)
Deferred financing costs	$	37,099	$	37,807
Field equipment inventory	5,309		5,713
Other	211		211
Other noncurrent assets	$	42,619	$	43,731

8. Accrued Liabilities

At March 31, 2015 and December 31, 2014 accrued liabilities consisted of the following:

	March 31, 2015		December 31, 2014
	(in thousands)
Accrued oil and gas capital expenditures	$	52,709	$	76,398
Accrued revenue and royalty distributions	46,286		51,292
Accrued lease operating and workover expense	16,313		10,113
Accrued interest	53,833		21,521
Accrued taxes	4,618		4,226
Other	8,729		20,281
Accrued liabilities	$	182,488	$	183,831

9. Asset Retirement Obligations

Asset Retirement Obligations (“AROs”) represent the 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. AROs approximated $22.0 million and $21.6 million as of March 31, 2015 and December 31, 2014, respectively, and the liability has been accreted to its present value as of March 31, 2015 and December 31, 2014.

10. Long-Term Debt

The Company’s long-term debt as of March 31, 2015 and December 31, 2014 is as follows:

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	At March 31, 2015		At December 31, 2014
	(in thousands)
Revolving credit facility, due 2018	$	435,150	$	435,150
Senior notes, due 2020	600,000		600,000
Senior notes, due 2021	700,000		700,000
Long-term debt	$	1,735,150	$	1,735,150

Reserve-based Credit Facility

As of March 31, 2015, the Company’s credit facility consisted of a $750 million Credit Facility with a borrowing base supported by the Company’s Mississippian Lime and Anadarko Basin oil and gas assets. The borrowing base was reaffirmed on March 24, 2015 at $525 million, with no reduction upon the closing in April of the Sale of Dequincy. At March 31, 2015, the Company had drawn $435.2 million on the Credit Facility and had outstanding letters of credit obligations totaling $1.4 million.

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. At March 31, 2015 and 2014, the weighted average interest rate was 3.0% and 2.7%, 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.

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 holding at least two thirds of the outstanding loans and other obligations.

Under the terms of the Credit Facility, the Company is required to repay the amount by which the principal balance of its outstanding loans and its letter of credit obligations exceed its redetermined borrowing base. The Company is permitted to make such repayment in six equal successive monthly payments commencing 30 days following the administrative agent’s notice regarding such borrowing base reduction.

The Credit Facility, as amended, contains, among other standard affirmative and negative covenants, financial covenants including a maximum ratio of net debt to EBITDA (i.e. leverage ratio) and a minimum current ratio (as defined therein) of not less than 1.0 to 1.0. Pursuant to the Sixth Amendment, the Company is required to maintain a leverage ratio of not more than 4.5 to 1.0 through December 31, 2015 and 4.0 to 1.0 for each quarter thereafter. The Credit Facility also limits the Company’s ability to make any dividends, distributions or redemptions.

As of March 31, 2015, the Company was in compliance with the current ratio and the ratio of net consolidated indebtedness to EBITDA covenants as set forth in the Credit Facility. The Company’s current ratio at March 31, 2015 was 1.0 to 1.0. As calculated for covenant compliance purposes, the Company’s current assets exceeded its current liabilities by approximately $1.5 million at March 31, 2015. At March 31, 2015, the Company’s leverage ratio was 3.7 to 1.0.

Based upon the recent amendments to the Credit Facility, the Company believes its carrying amount at March 31, 2015 approximates its fair value (Level 2) due to the variable nature of the applicable interest rate and current secured financing terms available to the Company.

2020 Senior Notes

On October 1, 2012, the Company issued $600 million in aggregate principal amount of 10.75% senior notes due in a private placement 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 notes with identical terms other than registration under the Securities Act and the omission of restrictions on transfer, registration rights and provisions for additional interest (the “2020 Senior Notes”). The 2020 Senior Notes were co-issued on a joint and several basis by the Company and its wholly owned subsidiary, Midstates Sub. The Company does not have any operations or independent assets other than its 100% ownership interest in Midstates Sub and there are no other subsidiaries of the Company. The 2020 Senior Notes Indenture does not create any restricted assets within Midstates Sub, nor does it impose any significant restrictions on the ability of Midstates Sub to pay dividends or make loans to the Company or limit the ability of the Company to advance loans to Midstates Sub.

The 2020 Senior Notes Indenture contains covenants that, among other things, restrict the Company’s ability to: (i) incur additional indebtedness, guarantee indebtedness or issue certain preferred shares; (ii) make loans, investments and other restricted payments; (iii) pay dividends on or make other distributions in respect of, or repurchase or redeem, capital stock; (iv) create or incur certain liens;

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(v) sell, transfer or otherwise dispose of certain assets; (vi) enter into certain types of transactions with the Company’s affiliates; (vii) consolidate, merge or sell substantially all of the Company’s assets; (viii) prepay, redeem or repurchase certain debt; (ix) alter the business the Company conducts and (x) enter into agreements restricting the ability of the Company’s current and any future subsidiaries to pay dividends.

The estimated fair value of the 2020 Senior Notes was $302.3 million as of March 31, 2015 (Level 2 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities. The effective annual interest rate for the 2020 Senior Notes was approximately 11.1% for the three months ended March 31, 2015 and 2014.

2021 Senior Notes

On May 31, 2013, the Company issued $700 million in aggregate principal amount of 9.25% senior notes due 2021. In October 2013, these notes were exchanged for an equal principal amount of notes with identical terms other than registration under the Securities Act and the omission of restrictions on transfer, registration rights and provisions for additional interest (the “2021 Senior Notes”).

The 2021 Senior Notes rank pari passu in right of payment with the 2020 Senior Notes.

The 2021 Senior Notes were co-issued on a joint and several basis by the Company and its wholly owned subsidiary, Midstates Sub. The 2021 Senior Notes indenture does not create any restricted assets within Midstates Sub, nor does it impose any significant restrictions on the ability of Midstates Sub to pay dividends or make loans to the Company or limit the ability of the Company to advance loans to Midstates Sub.

The terms of the covenants in the 2021 Senior Notes Indenture are substantially identical to those of the 2020 Senior Notes discussed above.

The estimated fair value of the 2021 Senior Notes was $339.5 million as of March 31, 2015 (Level 2 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities. The effective annual interest rate for the 2021 Senior Notes was approximately 9.6% for the three months ended March 31, 2015 and 2014.

11. Preferred Stock

Series A Preferred Stock

In connection with the Company’s acquisition of its Mississippian Lime properties, on September 28, 2012, the Company designated 325,000 shares of Series A Mandatorily Convertible Preferred Stock (the “Series A Preferred Stock”) with an initial liquidation preference of $1,000 per share and an 8% per annum dividend, payable semiannually at the Company’s option in cash or through an increase in the liquidation preference.  The Series A Preferred Shares are convertible after October 1, 2013, in whole but not in part and at the option of the holders of a majority of the outstanding shares of Series A Preferred Stock, into a number of shares of the Company’s common stock calculated by dividing the then-current liquidation preference by the conversion price of $13.50 per share and, if not previously converted, are mandatorily convertible at September 30, 2015 into shares of the Company’s common stock at a conversion price no greater than $13.50 per share and no less than $11.00 per share, with the ultimate conversion price dependent upon the volume weighted average price of the Company’s common stock during the 15 trading days immediately prior to September 30, 2015.  The Series A Preferred Stock was issued on October 1, 2012.

On March 30, 2015, the Company elected to pay the $13 million semi-annual dividend due on that date through an increase in the Series A Preferred Stock liquidation preference to $1,217. As a result, the Company will be obligated to issue between 5,215,718 and 6,401,108 additional shares of common stock upon conversion of the Series A Preferred stock, with the ultimate number of shares dependent upon the conversion price then in effect as described above.

The following table demonstrates the number of shares to be issued upon conversion through March 31, 2015 at the respective conversion rates based upon the current liquidation preference:

	Conversion at $13.50/share	Conversion at $11.00/share
Number of Common Shares Issuable Upon Conversion	29,289,792	35,946,563

Share Activity

The aggregate number of shares of Series A Preferred Stock outstanding at March 31, 2015 and December 31, 2014 was 325,000.

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12. Equity and Share-Based Compensation

Common Shares

Share Activity

The following table summarizes changes in the number of outstanding shares during the three months ended March 31, 2015:

	Number of Shares
	Common Stock		Treasury Stock
Share count as of December 31, 2014	70,491,732		(534,677	)
Grants of restricted stock	2,459,754		—
Forfeitures of restricted stock	(511,079	)	—
Acquisition of treasury stock	—		(254,881	)
Share count as of March 31, 2015	72,440,407		(789,558	)

The Company’s 2012 Long Term Incentive Unit Plan (discussed below) 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.

Incentive Units

At March 31, 2015, 1,099 incentive units were issued and outstanding. These incentive units were issued prior to the Company’s initial public offering. In connection with the corporate reorganization that occurred immediately prior to the Company’s initial public offering, these incentive units were contributed to FR Midstates Interholding, LP (“FRMI”) in exchange for incentive units in FRMI. Holders of FRMI incentive units will receive, out of proceeds otherwise distributable to FRMI, a percentage interest in the amounts distributed to FRMI in excess of certain multiples of FRMI’s aggregate capital contributions and investment expenses (“FRMI Profits”). Although any future payments to the incentive unit holders will be made out of the proceeds otherwise distributable to FRMI and not by the Company, the Company will be required to record a non-cash compensation charge in the period any payment is made related to the FRMI incentive units. To date, no compensation expense related to the FRMI incentive units has been recognized by the Company, as any payout under the FRMI incentive units is not considered probable as the amount of FRMI Profits, if any, cannot be determined.

Share-based Compensation

2012 Long Term Incentive Plan

The 2012 Long Term Incentive Plan (the “2012 LTIP”) provides a means for the Company to attract and retain employees, directors and consultants, and a method whereby employees, directors and consultants of the Company who contribute to its success can acquire and maintain stock ownership or awards, the value of which is tied to the performance of the Company, thereby strengthening their concern for the welfare of the Company and their desire to remain employed.

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 December 31, 2014, a total of 8,638,435 common share Awards are authorized for issuance under the 2012 LTIP. 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, 2015, the Company had 4,110,542 non-vested shares of restricted common stock 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, 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.

The following table summarizes the Company’s non-vested share award activity for the three months ended March 31, 2015:

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	Shares		Weighted Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2014	3,062,015		$	5.28
Granted	2,459,754		$	1.25
Vested	(900,148	)	$	5.22
Forfeited	(511,079	)	$	5.44
Non-vested shares outstanding at March 31, 2015	4,110,542		$	2.86

Unrecognized expense, adjusted for estimated forfeitures, as of March 31, 2015 for all outstanding restricted stock awards, was $8.9 million and will be recognized over a weighted average period of 1.9 years.

At March 31, 2015, 1,832,381 shares remain available for issuance under the terms of the 2012 LTIP.

The share based compensation costs (net of amounts capitalized to oil and gas properties) recognized as general and administrative expense by the Company for the three months ended March 31, 2015 and 2014 were $0.8 million and $1.5 million, respectively, all related to the 2012 LTIP.

13. Income Taxes

The Company has recorded a tax benefit on its year-to-date pre-tax loss. The Company believes this methodology to be more appropriate at this time due to uncertainty in forecasting the annual effective tax rate (or benefit) on 2015 income (or loss) due to previously recorded property impairments, the effects of federal and state valuation allowance adjustments, and hedging volatility.

For the three months ended March 31, 2015, the Company’s effective tax rate was approximately 4.5%. The Company’s effective tax rate for the first quarter of 2015 differs from the federal statutory rate of 35% due to the effect of recurring permanent adjustments, state income taxes and changes in the valuation allowance. During 2015, the Company recorded $70.9 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, 2014, bringing the total valuation allowance to $74.7 million at March 31, 2015.

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.

14. Net Loss Per Share

The Company’s Series A Preferred Stock has 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, is 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 (loss) per share, pursuant to the two class method. In the calculation of basic earnings (loss) 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 income 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.

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, 2015 and 2014, respectively:

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	Three Months Ended March 31,
	2015			2014
Net loss	$	(193,554	)	$	(83,645	)
Preferred Dividend (1)	(131		)	(2,620		)
Net loss attributable to shareholders	$	(193,685	)	$	(86,265	)
Participating securities - Series A Preferred Stock (2)	—			—
Participating securities - Non-vested Restricted Stock (2)	—			—
Net loss attributable to common shareholders	$	(193,685	)	$	(86,265	)
Weighted average shares outstanding	67,261			65,987
Net loss per share	$	(2.88	)	$	(1.31	)

(1)Calculation of the preferred stock dividend is discussed in Note 11.

(2)As these shares are participating securities that participate in earnings, but are not required to participate in losses, this calculation demonstrates that there is not an allocation of the loss to the non-vested restricted stockholders.

The aggregate number of common shares outstanding at March 31, 2015 was 71,650,849 of which 4,110,542 were non-vested restricted shares.

15. 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.

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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, 2014, 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 16, 2015, 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”). These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. 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. In particular, the factors discussed in this report on Form 10-Q, and detailed in our annual report filed on Form 10-K dated and filed with the SEC on March 16, 2015, could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such 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;

·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;

·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; and

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

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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. The price of oil and natural gas declined significantly in late 2014 and early 2015. Any continued or extended decline in oil and natural gas prices could have a material adverse effect on our financial position, results of operations, cash flows and access to capital. 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. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” and elsewhere in this quarterly report.

Overview

We are an independent exploration and production company focused on the application of modern drilling and completion techniques to oil-prone resources in the United States. Our operations originally focused on the Upper Gulf Coast Tertiary trend onshore in Louisiana, which we refer to as our “Gulf Coast” operating area. We began operations in the Mississippian Lime trend in Oklahoma with the October 1, 2012 closing of our acquisition (“Eagle Property Acquisition”) of interests in producing oil and natural gas assets, unevaluated leasehold acreage in Oklahoma and related hedging instruments from Eagle Energy Production, LLC (“Eagle Energy”). On May 31, 2013, the Company closed on the acquisition of producing properties and undeveloped acreage in the Anadarko Basin in Texas and Oklahoma from Panther Energy Company, LLC and its partners for approximately $618 million in cash (the “Anadarko Basin Acquisition”), before customary post-closing adjustments. Subsequent to the closing of the Eagle Property Acquisition and the Anadarko Basin Acquisition, the Company has oil and gas operations and properties in Louisiana, Oklahoma and Texas.

We were 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”), a wholly-owned subsidiary of Midstates Petroleum Holdings LLC.  With the completion of our initial public offering on April 25, 2012, we became a publicly traded company. Our common stock is listed on the NYSE under the ticker symbol “MPO.” 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 receive for that production. The amount we realize for our production depends predominantly upon commodity prices and our related commodity price hedging activities, 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 Development – Sale of Dequincy Assets

On April 21, 2015, we closed on the sale of ownership interest in developed and undeveloped acreage in the Dequincy area located in Beauregard and Calcasieu Parishes, Louisiana for $44 million to Pintail Oil and Gas LLC. The net proceeds of approximately $42 million, which was net of customary closing adjustments, will be reflected as a reduction of oil and natural gas properties, with no gain or loss recognized. The proceeds from the sale will be used to pay down a portion of the outstanding borrowings under our revolving credit facility and for general corporate purposes.

Risks, Uncertainties and Going Concern

As of March 31, 2015, we had available cash of approximately $11.9 million and availability under our Credit Facility of approximately $88.4 million.  As discussed above, we closed on the sale of our Dequincy assets on April 21, 2015 for net proceeds of approximately $42.0 million (net of customary purchase price adjustments).  The terms of the Credit Facility were amended in March 2015 to allow the divestiture of these assets with no associated reduction in the borrowing base of the Credit Facility.

As a result of substantial declines in oil and gas prices during the latter half of 2014 and continuing into the first part of 2015, our liquidity outlook has been impacted.  Decreases in commodity prices directly impact our revenues and associated operating cash flows and consequently our ability to fund our capital program and service our debt.  Our interest payment obligations are substantial, and we are required to pay approximately $32 million in interest on the 2020 Senior Notes on each of April 1 and October 1 and approximately $32 million in interest on the 2021 Senior Notes on each of June 1 and December 1. Our production volumes will decline as reserves are depleted, further impacting our liquidity, unless we expend capital resources in successful development and exploration activities or acquire properties with existing production.

The borrowing base for our senior reserve based revolving credit facility (the “Credit Facility”) is substantially based upon the value of our proved reserves and our commodity hedging instruments as determined by the lenders based on their commodity price deck. Despite a significant downward revision of the value of our proved reserves, our borrowing base for our credit facility was reaffirmed on March 24, 2015 at $525 million without reduction. Our borrowing base for our Credit Facility could be reduced at our October 1 borrowing base redetermination date due to downward revisions in our lenders’ commodity price deck, which would reduce the value of our proved reserves calculated thereunder, and the expiration of our commodity hedging instruments. If such a reduction occurs, we could be required to repay any borrowings in excess of the redetermined borrowing base and our available liquidity would be reduced.

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The uncertainty associated with our ability to meet our commitments as they come due or to repay our outstanding debt raises substantial doubt about our ability to continue as a going concern. The accompanying consolidated financial statements do not include any adjustments related to the recoverability and classification of recorded assets or the amounts and classification of liabilities that might result from the uncertainty associated with our ability to meet our obligations as they come due.

As a result of the events and circumstances described above, we believe that our forecasted cash and expected available credit capacity will not be sufficient to meet our commitments as they come due and, absent a material improvement in oil and natural gas prices, we will not be able to remain in compliance with our current debt covenants unless we are able to successfully increase our liquidity. We will therefore need to complete certain transactions, including management of debt capital structure and additional potential asset sales, to have sufficient liquidity to satisfy these obligations.  As previously announced, in early 2015 we engaged Evercore and Kirkland & Ellis to assist with reviewing all options to improve our liquidity profile and strengthen our balance sheet. These efforts continue in earnest and we are considering all available strategic alternatives and financing possibilities, including, without limitation, the incurrence of additional secured indebtedness and the exchange or refinancing of existing obligations.   We can provide no assurance that the discussions will result in the completion of a transaction, or that any completed transaction will result in sufficient liquidity to satisfy our obligations.

Operations Update

Mississippian Lime

At March 31, 2015, our Mississippian Lime area assets consisted of approximately 81,200 net prospective acres in the Mississippian Lime trend, with 67,050 net acres in Woods and Alfalfa Counties of Oklahoma, which we currently believe is the core of the trend. We currently plan to develop these liquids rich properties using horizontal wells. We also own approximately 12,600 net acres in Lincoln County, Oklahoma, which currently produces from, and is also prospective in, the Hunton formation. As of March 31, 2015, we held an average working interest and average net revenue interest of 68% and 54%, respectively in this area.

For the three months ended March 31, 2015 and December 31, 2014, our average daily production from the Mississippian Lime area was as follows:

	Three Months Ended March 31, 2015	Three Months Ended December 31, 2014	Increase in Production
Average daily production:
Oil (Bbls)	10,675	10,060	6	%
Natural gas liquids (Bbls)	5,367	4,809	12	%
Natural gas (Mcf)	62,933	61,025	3	%
Net Boe/day	26,531	25,039	6	%

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 2015:

	Total Number of Gross Horizontal Wells Spud (1)	Total Number of Gross Horizontal Wells Brought into Production
Mississippian Lime	18	26

(1)  We had four rigs drilling in the Mississippian Lime horizontal well program at March 31, 2015. Of the 18 wells spud, six were producing, eight were awaiting completion and four were being drilled at quarter-end.

Overall production increased by 6% versus the fourth quarter of 2014 as a result of our drilling and completion activity. The first quarter of 2015 was also favorably impacted by 26 gross wells that were not online or completed at December 31, 2014, and were brought into production during the first quarter of 2015.

In the first quarter of 2015, we invested approximately $88.9 million on completions and drilling new wells.

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Anadarko Basin

At March 31, 2015, our Anadarko Basin assets consisted of approximately 114,200 net acres, of which 82,800 acres were located in Texas and 31,400 acres were located in western Oklahoma. We held an average working interest and average net revenue interest of 66% and 51%, respectively, in this area as of March 31, 2015.

For the three months ended March 31, 2015 and December 31, 2014, our average daily production from our Anadarko Basin area was as follows:

	Three Months Ended March 31, 2015	Three Months Ended December 31, 2014	Decrease in Production
Average daily production:
Oil (Bbls)	3,028	3,343	-9	%
Natural gas liquids (Bbls)	1,240	1,703	-27	%
Natural gas (Mcf)	12,734	13,749	-7	%
Net Boe/day	6,390	7,337	-13	%

During the three months ended March 31, 2015, we brought three wells online. We did not spud any wells in the Anadarko area during that time and did not have any operated drilling rigs in the area during the three months ended March 31, 2015.

Overall production decreased by 13% versus the fourth quarter of 2014 primarily due to base production declines and our decision to suspend our drilling in this area due to the commodity price environment.  During the first quarter of 2015, we invested approximately $3.2 million on completions and capital workover programs.

Gulf Coast

In our Gulf Coast region, our current acreage position and evaluation efforts are concentrated in Louisiana in the Wilcox interval of the Upper Gulf Coast Tertiary trend.

On May 1, 2014, we closed on the sale of producing properties and undeveloped acreage in the Pine Prairie Field area of Evangeline Parish, Louisiana for estimated net proceeds of $147.5 million in cash, after post-closing adjustments.

On April 21, 2015, we closed on the sale of producing properties and undeveloped acreage in the Dequincy area located in Beauregard and Calcasieu Parishes, Louisiana for net proceeds of approximately $42 million, net of customary closing adjustments. Following the sale of our Dequincy assets, we no longer have any proved reserves or producing properties in our Gulf Coast area. After giving effect to the sale of our Dequincy assets, we had approximately 33,350 net acres in the trend at March 31, 2015.

For the three months ended March 31, 2015 and December 31, 2014, our average daily production from the Gulf Coast area was as follows:

	Three Months Ended March 31, 2015	Three Months Ended December 31, 2014	Decrease in Production
Average daily production:
Oil (Bbls)	858	959	-11	%
Natural gas liquids (Bbls)	274	278	-1	%
Natural gas (Mcf)	664	911	-27	%
Net Boe/day	1,243	1,388	-10	%

Overall production decreased by 10% versus the fourth quarter of 2014, due to continued base production declines as we have devoted our capital to developing our Mississippian Lime asset.

In the first quarter of 2015, we invested approximately $0.9 million in the Gulf Coast area primarily for workovers and other projects intended to stem base production decline in the Dequincy area. No operated wells were spud or brought into production in our Gulf Coast area of operation during the first quarter of 2015; one well was spud during the quarter as part of the exploration agreement with PetroQuest.

Capital Expenditures

During the three months ended March 31, 2015, we incurred operational capital expenditures of $93.0 million, including capitalized interest, which consisted primarily of:

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	For the Three Months Ended March 31, 2015
Drilling and completion activities	$	91,051
Acquisition of acreage and seismic data	1,924
Operational capital expenditures incurred	$	92,975
Capitalized G&A, office, ARO & other	1,760
Capitalized interest	984
Total capital expenditures incurred	$	95,719

Operational capital expenditures by area were as follows:

	For the Three Months Ended March 31, 2015
Mississippian Lime	88,889
Anadarko Basin	3,164
Gulf Coast	922
Total operational capital expenditures incurred	$	92,975

We expect to invest between $250 million to $275 million of capital for exploration, development and lease and seismic acquisition during the year ended December 31, 2015.

Factors that Significantly Affect our Results

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

We generally hedge a portion of our expected future oil and gas production to reduce our exposure to fluctuations in commodity price. By removing a portion of commodity price volatility, we expect to reduce some of the variability in our cash flow from operations. See “Item 3. — Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Exposure” for discussion of our hedging and hedge positions.

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; and

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

We follow the full cost method of accounting for our oil and gas properties.  In the first quarter of 2015, the results of our full cost “ceiling test” required us to recognize a before tax impairment of our oil and gas properties of $174.7 million. While this impairment did not impact cash flow from operating activities, it did reduce our earnings and shareholders’ equity.  We will likely be required to recognize additional impairments of oil and gas properties in future periods if we continue to experience an extended period of low commodity prices, which will result in a downward adjustment to our estimated proved reserves and the associated present value of

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estimated future net revenues, or if we incur actual development costs in excess of those estimates utilized in preparing our reserve reports.  Additionally, the expiration of unevaluated acreage leaseholds may increase the probability of future impairments, as the costs associated with the expiring leases would be immediately included in the full cost pool and become subject to the ceiling test limitation without any corresponding increase in reserves or future net revenues.

Results of Operations

The following tables summarize our revenue, production and price data for the periods indicated. Prior to May 1, 2014, our operating results include production, revenue and lease operating expenses attributable to our Pine Prairie field, the sale of which closed effective May 1, 2014.  Where applicable, in the following discussion, we have noted normalized production, revenue, lease operating expenses and percentages for prior periods as though the Pine Prairie Disposition occurred as of the beginning of that period.

Revenues

	For the Three Months Ended March 31
	2015					2014
	(in thousands)
REVENUES:
Oil sales	$	59,257		66	%	$	116,222		70	%
Natural gas liquid sales	11,010			12	%	25,519			15	%
Natural gas sales	19,172			22	%	25,385			15	%
Total oil, natural gas liquids, and natural gas sales	89,439			100	%	167,126			100	%
Net cash received (paid) for commodity derivative contracts	52,608			246	%	(14,810		)	65	%
Unrealized losses on commodity derivative contracts, net	(31,236		)	-146	%	(7,863		)	35	%
Gains (losses) on commodity derivative contracts - net	21,372			100	%	(22,673		)	100	%
Other	387					209
Total revenues	$	111,198				$	144,662

Production

	For the Three Months Ended March 31,
	2015	2014	% Change
PRODUCTION DATA:
Oil (MBbls)	1,310	1,208	8	%
Natural gas liquids (MBbls)	619	532	16	%
Natural gas (MMcf)	6,870	5,224	32	%
Oil equivalents (MBoe)	3,075	2,610	18	%
Oil (Boe/day)	14,561	13,417	9	%
Natural gas liquids (Boe/day)	6,881	5,912	16	%
Natural gas (Mcf/day)	76,331	58,048	31	%
Average daily production (Boe/d)	34,164	29,004	18	%

Prices

	For the Three Months Ended March 31,
	2015		2014		% Change
AVERAGE SALES PRICES:
Oil, without realized derivatives (per Bbl)	$	45.22	$	96.25	-53	%
Oil, with realized derivatives (per Bbl)	$	79.45	87.06		-9	%
Natural gas liquids, without realized derivatives (per Bbl)	$	17.78	47.96		-63	%
Natural gas liquids, with realized derivatives (per Bbl)	$	17.78	47.79		-63	%
Natural gas, without realized derivatives (per Mcf)	$	2.79	4.86		-43	%
Natural gas, with realized derivatives (per Mcf)	$	3.92	4.16		-6	%

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Three Months Ended March 31, 2015 as Compared to the Three Months Ended March 31, 2014

Oil, natural gas liquids and natural gas sales revenues

Our oil, NGL and natural gas sales revenues decreased by $77.7 million, or 46% to $89.4 million during the three months ended March 31, 2015, as compared to $167.1 million during the three months ended March 31, 2014. After normalizing for the Pine Prairie Disposition as if the disposition occurred on January 1, 2014, revenues decreased by $63.4 million, or 41%.

Our oil sales revenues decreased by $57.0 million, or 49%, to $59.2 million during the three months ended March 31, 2015, as compared to $116.2 million for the three months ended March 31, 2014. After normalizing for the Pine Prairie Disposition as if the disposition occurred on January 1, 2014, oil sales revenues decreased by $44.5 million and 43%. Oil volumes sold increased 1,144 Boe/day, or 9%, to 14,561 Boe/day for the three months ended March 31, 2015, from 13,417 Boe/day for the three months ended March 31, 2014. This increase in oil volumes sold was attributable to increased production quarter over quarter in the Mississippian Lime area of 4,594 Boe/day, partially offset by a 1,315 Boe/day decrease in production volumes from our Anadarko Basin area and a 2,135 Boe/day decrease in production from our Gulf Coast area, of which 1,357 Boe/day was related to Pine Prairie. The overall improvement in oil sales volumes of 1,144 Boe/day resulted in approximately $9.8 million in additional oil sales revenues. Average oil sales prices, without realized derivatives, decreased by $51.03 per barrel, or 53%, to $45.22 per barrel during the three months ended March 31, 2015 as compared to $96.25 per barrel for the three months ended March 31, 2014. This price variance resulted in a decrease in oil sales revenue of approximately $66.9 million during the three months ended March 31, 2015, as measured against the comparable period in 2014.

Our NGL sales revenues decreased by $14.5 million, or 57%, to $11.0 million during the three months ended March 31, 2015, as compared to $25.5 million for the three months ended March 31, 2014. After normalizing for the Pine Prairie Disposition as if the disposition occurred on January 1, 2014, NGL sales revenues decreased by $13.3 million, or 55%. NGL volumes sold increased 969 Boe/day, or 16%, to 6,881 Boe/day for the three months ended March 31, 2015, from 5,912 Boe/day for the three months ended March 31, 2014. This increase in NGL volumes sold was attributable to the increased production quarter over quarter in the Mississippian Lime area of 1,870 Boe/day, partially offset by a 453 Boe/day decrease in production volumes from our Anadarko Basin area and a 448 Boe/day decrease in production from our Gulf Coast area, of which 270 Boe/day was related to Pine Prairie. The overall improvement in NGL sales volumes of 969 Boe/day resulted in approximately $4.2 million in additional NGL sales revenues. Average NGL sales prices, without realized derivatives, decreased by $30.18 per barrel, or 63%, to $17.78 per barrel during the three months ended March 31, 2015 as compared to $47.96 per barrel for the corresponding period in 2014. This price variance resulted in a decrease in NGL sales revenue of approximately $18.7 million during the three months ended March 31, 2015 as measured against the comparable period in 2014.

Our natural gas sales revenues decreased by $6.2 million, or 24%, to $19.2 million during the three months ended March 31, 2015, as compared to $25.4 million for the three months ended March 31, 2014. After normalizing for the Pine Prairie Disposition as if the disposition occurred on January 1, 2014, natural gas sales revenues decreased $5.4 million, or 22%. Natural gas volumes sold increased 18,283 Mcf/day or 31%, to 76,331 Mcf/day for the three months ended March 31, 2015, from 58,048 Mcf/day for the three months ended March 31, 2014. This increase in natural gas volumes sold was attributable to increased production of 22,117 Mcf/day in the Mississippian Lime area, partially offset by a decrease in production of 1,306 Mcf/day from our Anadarko Basin area and 2,528 Mcf/day from our Gulf Coast area, of which 1,791 Mcf/day was related to Pine Prairie. The overall improvement in natural gas sales volumes of 18,283 Mcf/day resulted in approximately $8.0 million in additional natural gas sales revenues. Average natural gas sales prices, without realized derivatives, decreased by $2.07 per Mcf, or 43%, to $2.79 per Mcf during the three months ended March 31, 2015 as compared to $4.86 per Mcf for the three months ended March 31, 2014. This price variance resulted in a decrease in natural gas sales revenue of approximately $14.2 million during the three months ended March 31, 2015, as measured against the comparable period in 2014.

Gains/losses on commodity derivative contracts - net

Our mark-to-market (“MTM”) derivative positions moved from an unrealized loss of $7.9 million for the three months ended March 31, 2014 to an unrealized loss of $31.2 million for the three months ended March 31, 2015. The NYMEX WTI closing price on March 31, 2015 was $47.60 per barrel compared to a closing price of $101.58 per barrel on March 31, 2014. At March 31, 2015, our oil derivatives have contract prices that range from $83.15 to $92.61 per barrel and extend through the fourth quarter of 2015. (See Note 5 in Item 1. Financial Statements.)

Cash receipts for the settlements of derivatives were $52.6 million for the three months ended March 31, 2015 as compared to cash payments for the settlement of derivatives of $14.8 million during the three months ended March 31, 2014.  The following table presents cash receipts for the settlements of derivatives by type of commodity contract for the three months ended March 31, 2015:

	For the Three Months Ended March 31, 2015
	Total		Average Sales Price
	(in thousands)
Oil commodity contracts	$	44,857	$	79.45
Natural gas commodity contracts	7,751		3.92
Net cash received for commodity derivative contracts	$	52,608

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

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
	2015		2014		2015		2014
	(in thousands)				(per Boe)
EXPENSES:
Lease operating and workover	$	23,262	$	20,127	$	7.56	$	7.71
Gathering and transportation	3,438		2,855		1.12		1.09
Severance and other taxes	3,565		7,647		1.16		2.93
Asset retirement accretion	445		497		0.14		0.19
Depreciation, depletion, and amortization	58,428		66,901		19.00		25.63
Impairment of oil and gas properties	174,667		86,471		56.80		33.13
General and administrative	11,654		11,684		3.79		4.48
Acquisition and transaction costs	—		128		—		0.05
Advisory fees	1,743		—		0.57		—
Other	97		330		0.03		0.13
Total expenses	$	277,299	$	196,640	$	90.17	$	75.34

Three Months Ended March 31, 2015 as Compared to the Three Months Ended March 31, 2014

Lease operating and workover expenses

Lease operating and workover expenses increased $3.1 million, or 15%, to $23.2 million for the three months ended March 31, 2015 compared to $20.1 million for the three months ended March 31, 2014. After normalizing for the Pine Prairie Disposition, lease operating and workover expenses increased $5.5 million, or 31%, largely as a result of increased well count resulting in higher saltwater disposal costs (primarily in our Mississippian Lime area) and higher surface facilities maintenance and repairs in both the Mississippian Lime and Anadarko Basin areas. In the Anadarko Basin we experienced increased artificial lift maintenance and compressor rental costs. We have begun a program to reduce these costs by evaluating our artificial lift mechanisms in the Anadarko Basin and, where appropriate, replacing gas lifts with rod pump mechanisms, which should reduce these costs in future periods. Lease operating and workover expenses decreased to $7.56 per Boe for the three months ended March 31, 2015, a decrease of $0.15, or 2%, over the $7.71 per Boe for the three months ended March 31, 2014.

Gathering and transportation

Gathering and transportation expenses increased $0.5 million, or 17% to $3.4 million for the three months ended March 31, 2015 compared to $2.9 million for the three months ended March 31, 2014, due to a corresponding increase in production from our Mississippian Lime area.

Severance and other taxes

	Three Months Ended March 31
	2015			2014
Total oil, natural gas, and natural gas liquids sales	$	89,439		$	167,126
Severance taxes	1,782			5,809
Ad valorem and other taxes	1,783			1,838
Severance and other taxes	$	3,565		$	7,647
Severance taxes as a percentage of sales	2.0		%	3.5		%
Severance and other taxes as a percentage of sales	4.0		%	4.6		%

Severance taxes decreased $4.0 million, or 69%, to $1.8 million for the three months ended March 31, 2015, as compared to $5.8 million for the three months ended March 31, 2014. Severance taxes as a percentage of sales changed from 3.5% for the three months ended March 31, 2014 to 2.0% for the corresponding 2015 period due to lower effective severance tax rates in our Mississippian Lime and lower production period over period in the relatively higher tax Gulf Coast region. Ad valorem taxes were flat for the three months ended March 31, 2015 and 2014 at $1.8 million.

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

DD&A expense decreased $8.5 million, or 13%, to $58.4 million for the three months ended March 31, 2015 compared to $66.9 million for the three months ended March 31, 2014. The decrease in DD&A expense was driven by downward revisions in our proved undeveloped reserves from March 31, 2014, which decreased estimated finding and developments costs and as a result, reduced our DD&A expense. Consequently, the DD&A rate per Boe also decreased from $25.63 per Boe for the three months ended March 31, 2014 to $19.00 per Boe for the three months ended March 31, 2015.

Impairment of oil and gas properties

We recorded pre-tax impairment expense related to our oil and natural gas properties for the three months ended March 31, 2015 and 2014 of $174.7 million and $86.5 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, 2015 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.  The impairment expense for three months ended March 31, 2014 was largely due to the transfer of unevaluated property costs to the full cost pool during the first quarter of 2014. During the three months ended March 31, 2014, we transferred $21.4 million and $38.1 million related to Mississippian Lime and Anadarko Basin areas, respectively, as we released acreage that did not present the best near term development potential.

General and administrative (“G&A”)

Our G&A expenses were $11.7 million for the three months ended March 31, 2015 and 2014. In the three months ended March 31, 2015, approximately $1.7 million in G&A was attributable to severance related payments due to the Houston office closure.

Acquisition and transaction costs

We did not incur any acquisition and transaction costs for the three months ended March 31, 2015, compared to $0.1 million for the three months ended March 31, 2014. For the 2014 period, these costs represent our expenses related to the Pine Prairie Disposition.

Advisory fees

As discussed previously, we are analyzing options to improve our financial flexibility and provide additional long-term liquidity.  As part of that process, we have engaged various advisors to assist us.  For the three months ended March 31, 2015, the Company incurred approximately $1.7 million in fees associated with these advisors.  We expect to incur additional significant costs during the remainder of 2015 for such advisors.

Other

Other operating expenses for the three months ended March 31, 2015 were $0.1 million, compared to $0.3 million for the three months ended March 31, 2014.  Other operating expenses represent the loss on disposal of, or market value adjustments to, field equipment inventory.

Other Income (Expenses)

	For the Three Months Ended March 31,
	2015			2014
	(in thousands)
OTHER INCOME (EXPENSE)
Interest income	$	9		$	10
Interest expense	(37,487		)	(38,565		)
Capitalized Interest	984			4,618
Interest expense — net of amounts capitalized	(36,503		)	(33,947		)
Total other income (expense)	$	(36,494	)	$	(33,937	)

Interest expense

Three Months Ended March 31, 2015 as Compared to the Three Months Ended March 31, 2014

Interest expense for the three months ended March 31, 2015 and 2014 was $37.5 million and $38.6 million, respectively. Our average outstanding balance under our revolving credit facility was $435.2 million during the three months ended March 31, 2015, compared to $401.2 million for the three months ended March 31, 2014, and related to $3.3 million of the total interest expense of $37.5 million for the three months ended March 31, 2015. Of the remainder, $16.2 million was interest incurred under the 2021 Senior Notes, $16.1 million was interest incurred under the 2020 Senior Notes and $1.9 million represented amortization of deferred financing costs. Of the total interest expense for both periods, $1.0 million and $4.6 million was capitalized to oil and gas properties, resulting in $36.5 million and $33.9 million in interest expense, net of capitalized interest, for the three months ended March 31, 2015 and 2014, respectively.

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Provision for Income Taxes

Three Months Ended March 31, 2015 as Compared to the Three Months Ended March 31, 2014

Our income tax benefit was $9.0 million for the three months ended March 31, 2015 compared to a benefit of $2.3 million for the three months ended March 31, 2014. For the three months ended March 31, 2015, the Company’s effective tax rate was approximately 4.5%. The Company’s effective tax rate for the first quarter of 2015 differs from the federal statutory rate of 35% due to the effect of recurring permanent adjustments, state income taxes and changes in the valuation allowance.

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.

A valuation allowance has been recorded as management does not believe that it is more-likely-than-not that its NOLs 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.

Liquidity and Capital Resources

Our financial statements have been prepared on a going concern basis, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business. The content below and under “Risks, Uncertainties, and Going Concern” above addresses important factors affecting our financial condition, liquidity and capital resources and debt covenant compliance.

At March 31, 2015, our liquidity consisted of approximately $88.4 million of available borrowing capacity under our revolving credit facility and $12 million of cash and cash equivalents.

Expenditures for exploration and development of oil and natural gas properties and payments for interest related to our Credit Facility, our 2020 Senior Notes and our 2021 Senior Notes are the primary use of our capital resources and liquidity. We expect to invest between $250 million and $275 million of capital for exploration, development and lease and seismic acquisition during the year ending December 31, 2015. Additionally, we expect to capitalize between $4 million and $6 million of interest expense during that same period. The interest payment obligations are substantial, and the Company is required to pay approximately $32 million in interest on the 2020 Senior Notes on each of April 1 and October 1 and approximately $32 million in interest on the 2021 Senior Notes on each of June 1 and December 1. Our future success in growing proved reserves and production and meeting our interest obligations will be highly dependent on our ability to access additional outside sources of capital, via either the debt or equity markets, through growth in our reserve based credit facility or by securing other external sources of funding. As part of that process, in April 2015, we closed a purchase and sale agreement covering the sale of our remaining producing assets in Louisiana for total consideration of approximately $42 million cash, net of customary closing adjustments. The net proceeds will be used to repay a portion of our outstanding borrowings under our Credit Facility and for general corporate purposes.

We plan to continue pursuing additional options that would improve our financial flexibility and provide additional long term liquidity, including the sale of other non-core assets and possibly joint ventures or farm outs on our properties and management of our debt capital structure. As previously announced, in early 2015 we engaged Evercore and Kirkland & Ellis to assist with reviewing all options to improve our liquidity profile and strengthen our balance sheet. These efforts continue in earnest and we are considering all available strategic alternatives and financing possibilities, including, without limitation, the incurrence of additional secured indebtedness and the exchange or refinancing of existing obligations.  We can provide no assurance that the discussions will result in the completion of a transaction, or that any completed transaction will result in sufficient liquidity to satisfy our obligations.

Significant Sources of Capital

Reserve-based Credit Facility

Our credit facility consists of a $750 million senior revolving credit facility with a borrowing base supported by our Mississippian Lime and Anadarko Basin oil and gas assets. On September 30, 2014, we entered into an Assignment and Borrowing Base Increase Agreement that increased the borrowing base under the Credit Facility from $475 million to $525 million. The borrowing base was reaffirmed on March 24, 2015 at $525 million, with no reduction upon the closing in April of the Sale of Dequincy. At March 31, 2015 we had drawn $435.2 million on our Credit Facility and had outstanding letters of credit obligations totaling $1.4 million.

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, 2015 and 2014, the weighted average interest rate was 3.0% and 2.7%, 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.

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.

Under the terms of the Credit Facility, we are required to repay the amount by which the principal balance of our outstanding loans and our letter of credit obligations exceeds our redetermined borrowing base. We are permitted to make such repayment in six equal

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successive monthly payments commencing 30 days following the administrative agent’s notice regarding such borrowing base reduction.

The Credit Facility, as amended, contains, among other standard affirmative and negative covenants, financial covenants including a maximum ratio of debt to EBITDA (i.e. leverage ratio) and a minimum current ratio (as defined therein) of not less than 1.0 to 1.0. Pursuant to the Sixth Amendment, we are required to maintain a leverage ratio of not more than 4.5 to 1.0 through December 31, 2015 and 4.0 to 1.0 for each quarter thereafter. The Credit Facility also limits our ability to make any dividends, distributions or redemptions.

As of March 31, 2015, we were in compliance with the minimum current ratio and the ratio of net debt to EBITDA covenants as set forth in the Credit Facility. Our current ratio at March 31, 2015 was 1.0 to 1.0. As calculated for covenant compliance purposes, our current assets exceeded our current liabilities by approximately $1.5 million at March 31, 2015. At March 31, 2015, our ratio of debt to EBITDA was 3.7 to 1.0.

2020 Senior Notes

On October 1, 2012, we issued $600 million in aggregate principal amount of 10.75% senior notes due in a private placement 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 notes with identical terms other than registration under the Securities Act and the omission of restrictions on transfer, registration rights and provisions for additional interest (the “2020 Senior Notes”). The 2020 Senior Notes were co issued on a joint and several basis by us and our wholly owned subsidiary, Midstates Sub. We do not have any operations or independent assets other than our 100% ownership interest in Midstates Sub and we have no other subsidiaries. The 2020 Senior Notes Indenture does not create any restricted assets within Midstates Sub, nor does it impose any significant restrictions on the ability of Midstates Sub to pay dividends or make loans to us or limit our ability to advance loans to Midstates Sub.

The 2020 Senior Notes Indenture contains covenants that, among other things, restrict our ability to: (i) incur additional indebtedness, guarantee indebtedness or issue certain preferred shares; (ii) make loans, investments and other restricted payments; (iii) pay dividends on or make other distributions in respect of, or repurchase or redeem, capital stock; (iv) create or incur certain liens; (v) sell, transfer or otherwise dispose of certain assets; (vi) enter into certain types of transactions with our affiliates; (vii) consolidate, merge or sell substantially all of our assets; (viii) prepay, redeem or repurchase certain debt; (ix) alter the business we conduct and (x) enter into agreements restricting the ability of our current and any future subsidiaries to pay dividends.

2021 Senior Notes

On May 31, 2013, we issued $700 million in aggregate principal amount of 9.25% senior notes due 2021. In October 2013, these notes were exchanged for an equal principal amount of notes with identical terms other than registration under the Securities Act and the omission of restrictions on transfer, registration rights and provisions for additional interest (the “2021 Senior Notes”).

The 2021 Senior Notes rank pari passu in right of payment with the 2020 Senior Notes.

The 2021 Senior Notes were co issued on a joint and several basis by us and our wholly owned subsidiary, Midstates Sub. The 2021 Senior Notes indenture does not create any restricted assets within Midstates Sub, nor does it impose any significant restrictions on the ability of Midstates Sub to pay dividends or make loans to us or limit our ability to advance loans to Midstates Sub.

The terms of the in the 2021 Senior Notes Indenture are substantially identical to those of the 2020 Senior Notes discussed above.

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):

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	For the Three Months Ended March 31,
	2015			2014
Net cash provided by operating activities	$	113,017		$	105,409
Net cash used in investing activities	(111,167		)	(122,780		)
Net cash used in financing activities	(1,466		)	(1,144		)
Net change in cash	$	384		$	(18,515	)

Cash flows provided by operating activities

Net cash provided by operating activities was $113.0 million and $105.4 million for the three months ended March 31, 2015 and 2014, respectively. The increase in net cash provided by operating activities was primarily the result of higher net cash received for commodity derivative contracts and positive working capital changes.

Cash flows used in investing activities

Net cash used in investing activities was $111.2 million and $114.8 million during the three months ended March 31, 2015 and 2014, respectively. During the three months ended March 31, 2015, we invested $111.2 million in our drilling program, which focused on the Mississippian Lime area, compared to the $122.8 million we invested in our drilling program during the three months ended March 31, 2014.

Cash flows used in financing activities

Net cash used in financing activities was $1.5 million for the three months ended March 31, 2015, compared to $1.1 million used in financing activities for the three months ended March 31, 2014. During the three months ended March 31, 2015, we did not have any draws or repayments on the Credit Facility.  During three months ended March 31, 2014, there were no draws on the Credit Facility.

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, 2014. 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.

Other Items

Off-Balance Sheet Arrangements

We do not currently have any off-balance sheet arrangements.

Recently Issued Standards Not Yet Adopted

In April 2015, the FASB issued Accounting Standards Update 2015-03 “Interest-Imputation of Interest (Subtopic 835-30):  Simplifying the Presentation of Debt Issuance Costs” (“ASU 2015-03”).  ASU 2015-03 requires that debt issuance costs related to a recognized liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts.  The recognition and measurement guidance for debt issuance costs is not affected by ASU 2015-03.  ASU 2015-03 is effective retrospectively for us beginning on January 1, 2016.  We do not expect the reclassification of debt issuance costs on the Company’s consolidated balance sheet as a result of the adoption of ASU 2015-03 to have a material impact on its consolidated financial statements or 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 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

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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 Note 5 to our Consolidated Financial Statements.

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

We utilize derivative financial instruments to manage risks related to changes in oil and natural gas prices. As of March 31, 2015, we utilized fixed price swaps to reduce the volatility of oil prices on a portion of our future expected oil production.

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

The following is a summary of our commodity derivative contracts as of March 31, 2015:

	Hedged Volume	Weighted-Average Fixed Price
Oil (Bbls):
WTI Swaps — 2015	2,196,000	$	88.04
Natural Gas (MMBtu):
Swaps — 2015 (1)	13,750,000	$	4.13

(1)Includes 1,500,000 MMBtus in natural gas swaps that priced during the period, but had not cash settled as of March 31, 2015.

	For the Three Months Ended March 31, 2015
	(in thousands)
Derivative fair value at period end - asset (included in balance sheet)	$	95,473
Net cash received for commodity derivative contracts (included in the statement of operations)	$	52,608
Unrealized net loss (included in the statement of operations)	$	(31,236	)

At March 31, 2015 and December 31, 2014, all of our commodity derivative contracts were with seven bank counterparties. Our policy is to net derivative liabilities and assets where there is a legally enforceable master netting agreement with the counterparty.

Interest Rate Risk. At March 31, 2015, we had indebtedness outstanding under our Credit Facility of $435.2 million, which bore interest at floating rates, we had $600 million outstanding in 2020 Senior Notes (placed October 1, 2012), which bore interest at 10.75%, and we had $700 million outstanding in 2021 Senior Notes (placed May 31, 2013), which bore interest at 9.25%. The average annual interest rate incurred on the Credit Facility for the three months ended March 31, 2015 and 2014 was 3.0% and 2.7%, respectively.

A 1.0% increase in each of the average LIBOR and federal funds rate for the three months ended March 31, 2015 and 2014 would have resulted in an estimated $1.1 million and $1.0 million, respectively, increase in interest expense, of which a portion may be capitalized.

At March 31, 2015 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

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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, 2015, 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, 2015 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

See Part I, Item 1, Note 15 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.

Risk factors relating to us are contained below and in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2014.

We have received a continued listing standard from the NYSE for our common stock.  If we are unable to avoid the delisting of our common stock from the NYSE, it could have a substantial effect on our liquidity and results of operations.

On April 1, 2015, we received notification from the NYSE that the price of our common stock had fallen below the NYSE’s continued listing standard.  The NYSE requires that the average closing price of a listed company’s common stock not be less than $1.00 per share for a period of over 30 consecutive trading days.

Under NYSE rules, a company can avoid delisting if, during the six month period following receipt of the NYSE notice and on the last trading day of any calendar month, a company’s common stock price per share and 30 trading-day average share price is at least $1.00. During this six month period, a company’s common stock will continue to be traded on the NYSE, subject to compliance with other continued listing requirements.

The NYSE notification did not affect our business operations or our SEC reporting requirements and did not conflict with or cause an event of default under any of our material debt or other agreements.  Subsequent to April 1, 2015, we regained compliance with the NYSE continued listing requirement.

In the future, if our common stock ultimately were to be delisted for any reason, it could negatively impact us by (i) reducing the liquidity and market price of our common stock; (ii) reducing the number of investors willing to hold or acquire our common stock, which could negatively impact our ability to raise equity financing; (iii) limiting our ability to use a registration statement to offer and sell freely tradable securities, thereby preventing us from accessing the public capital markets; and (iv) impairing our ability to provide equity incentives to our employees.

Due to reduced commodity prices and lower operating cash flows, coupled with substantial interest payments, there is doubt about our ability to maintain adequate liquidity through 2015 and our ability to make interest payments in respect of our indebtedness.

During the second half of 2014 and into 2015, NYMEX-WTI oil prices fell from in excess of $100 per Bbl to below $50 per Bbl, the lowest price since 2009. The substantial reduction in oil and NGL prices has caused a reduction in our forecast of available liquidity and we may not have the ability to maintain our current borrowing base under our Credit Facility at its current levels or generate sufficient cash flows from operations and, therefore, sufficient liquidity to meet our anticipated working capital, debt service and other liquidity needs. As of March 31, 2015, we had available cash of approximately $12 million and availability under our Credit Facility of approximately $88 million. As of March 31, 2015, payments due on our contractual obligations during the remainder of the year were approximately $143.5 million. This includes approximately $129.3 million of interest payments on our 2020 Senior Notes and 2021 Senior Notes and other operating expenses such as fixed drilling commitments and operating leases. We believe that our forecasted cash and available credit capacity are not expected to be sufficient to meet our commitments as they come due over the next twelve months and that we will not be able to remain in compliance with our debt covenants unless we are able to successfully increase our liquidity. A sustained material decline in oil, NGL and natural gas prices or a reduction in our oil and natural gas production and reserves would reduce our ability to fund our capital expenditure program and negatively impact our liquidity on an ongoing basis. We expect we will need to

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complete certain transactions, including management of our debt capital structure and potential asset sales, to have sufficient liquidity to satisfy these obligations in the long-term.

We are currently evaluating strategic alternatives to address our liquidity issues and high debt levels. We cannot assure you that any of these efforts will be successful or will result in cost reductions or additional cash flows or the timing of any such cost reductions or additional cash flows. As previously announced, in early 2015 we engaged Evercore and Kirkland & Ellis to assist with reviewing all options to improve our liquidity profile and strengthen our balance sheet. These efforts continue in earnest and we are considering all available strategic alternatives and financing possibilities, including, without limitation, the incurrence of additional secured indebtedness and the exchange or refinancing of existing obligations. We cannot assure you that any refinancing or debt or equity restructuring would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all. Furthermore, we cannot assure you that any of our strategies will yield sufficient funds to meet our working capital or other liquidity needs, including for payments of interest and principal on our debt in the future, and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations.

If we are unable to repay or refinance our existing and future debt as it becomes due, we may be unable to continue as a going concern.

Our existing and future debt agreements could create issues as interest payments become due and the debt matures that will threaten our ability to continue as a going concern. For example, absent any action with respect to the repayment or refinancing of our existing indebtedness or any waivers or amendments to the agreements governing our existing indebtedness, our reserve based Credit Facility is scheduled to mature in 2018 and our senior notes are scheduled to mature in 2020 and 2021. Additionally, the borrowing base under our Credit Facility is subject to at least semi-annual redetermination and as a result, availability thereunder could be reduced and advances in excess of the new availability would need to be repaid. We have substantial interest payments due during the remainder of 2015, including approximately $129.3 million of total interest payments due on our senior notes. If we fail to satisfy our obligations with respect to our indebtedness or fail to comply with the financial and other restrictive covenants contained in our Credit Facility, the indentures governing our senior notes, or other agreements governing our indebtedness, an event of default could result, which would permit acceleration of such debt and which could result in an event of default under and acceleration of our other debt and could permit our secured lenders to foreclose on any of our assets securing such debt. Any accelerated debt would become immediately due and payable. While we will attempt to take appropriate mitigating actions to refinance any indebtedness prior to its maturity or otherwise extend the maturity dates, and to cure any potential defaults, there is no assurance that any particular actions with respect to refinancing existing indebtedness, extending the maturity of existing indebtedness or curing potential defaults in our existing and future debt agreements will be sufficient.

The consolidated financial statements included in our 2014 Annual Report 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 consolidated financial statements do not reflect any adjustments that might result if we are unable to continue as a going concern.

We may not be able to obtain funding under our Credit Facility because of a decrease in our borrowing base or obtain funding in the capital markets on terms we find acceptable.

Historically, we have used our cash flows from operations and borrowings under our Credit Facility to fund our capital expenditures and have relied on the capital markets and asset monetization transactions to provide us with additional capital for large or exceptional transactions or to refinance debt obligations. As of March 31, 2015, we have a Credit Facility with approximately $88 million available and a borrowing base of $525 million. The borrowing base under our revolving 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. The next scheduled borrowing base redetermination date is October 1, 2015. Should prices for oil and natural gas remain weak or deteriorate, if we have a downward revision in estimates of our proved reserves, or if we sell oil and natural gas reserves, our borrowing base may be reduced. Any reduction in the borrowing base will reduce our available liquidity, and, if the reduction results in the outstanding amount under the facility exceeding the

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borrowing base, we will be required to repay the deficiency within 30 days or in six equal monthly installments thereafter, at our election. We may not have the financial resources in the future to make any mandatory deficiency principal prepayments required under our Credit Facility, which could result in an event of default. In the future, we may not be able to access adequate funding under our Credit Facility as a result of (i) a decrease in our borrowing base due to the outcome of a subsequent borrowing base redetermination, or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. Since the process for determining the borrowing base under our Credit Facility involves evaluating the estimated value of some of our oil and natural gas properties using pricing models determined by the lenders at that time, a decline in those prices used, or further downward reductions of our reserves, likely will result in a redetermination of our borrowing base and a decrease in the available borrowing amount at the time of the next scheduled redetermination. In such case, we would be required to repay any indebtedness in excess of the borrowing base.

Volatility in the public and private capital markets may make it more difficult to obtain funding. There is a risk that the cost of obtaining money from the credit markets may increase in the future as lenders and institutional investors may increase interest rates, impose tighter lending standards, refuse to refinance existing debt at maturity on terms similar to existing debt or at all, or reduce or cease to provide any new funding. Due to these factors, we cannot be certain that funding, if needed, will be available to the extent required, or on acceptable terms. If we are unable to access funding when needed on acceptable terms, we may not be able to fully implement our business plans, take advantage of business opportunities, respond to competitive pressures, or refinance our debt obligations as they come due, any of which could have a material adverse effect on our operations and financial results.

Our ability to access funds under our Credit Facility is based on a borrowing base, which is subject to periodic redeterminations based on our proved reserves and commodity prices that will be determined by our lenders using the bank pricing prevailing at such time.

Our level of indebtedness may increase and reduce our financial flexibility.

As of March 31, 2015, we had approximately $88 million available and a borrowing base of $525 million under our Credit Facility, $600 million in 2020 Senior Notes and $700 million in 2021 Senior Notes outstanding. In the future, we may incur significant additional indebtedness in order to make future acquisitions or to develop our properties.

Our current level of indebtedness could affect our operations in several ways, including the following:

·causing a significant portion of our cash flows to be used to service our indebtedness, thereby reducing the availability of cash flows for working capital, capital expenditures and other general business activities;

·increasing our vulnerability to general adverse economic and industry conditions;

·limiting our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

·placing us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, such competitors may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;

·causing our debt covenants to affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

·making it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then outstanding bank borrowings;

·impairing our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes; and

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·making it more difficult for us to satisfy our obligations under the indentures governing our Senior Notes.

A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control.

If we are unable to repay our debt out of our cash on hand, we could attempt to refinance such debt, obtain additional borrowings, sell assets or repay such debt with the proceeds from an equity offering. We cannot assure you that refinancing, additional borrowings, proceeds from the sale of assets or equity financing will be available to pay or refinance such debt. Factors that may affect our ability to raise cash through an offering of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions, our market value, our reserve levels and our operating performance at the time of such offering or other financing. The inability to repay or refinance our debt could have a material adverse effect on our operations and could result in a reduction in our capital program or lead us to pursue other alternatives to develop our assets.

In addition, our bank borrowing base is subject to periodic redeterminations on a semi-annual basis, effective October 1 and April 1 and up to one additional time per six-month period following each scheduled borrowing base redetermination, as may be requested by either us or the administrative agent under our Credit Facility. In the future we could be forced to repay a portion of our then outstanding bank borrowings due to future redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are unable to arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

We may be unable to maintain compliance with certain financial ratio covenants of our outstanding indebtedness which could result in an event of default that, if not cured or waived, would have a material adverse effect on our business, financial condition and results of operations.

Our Credit Facility requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. As of March 31, 2015, our ratio of net consolidated indebtedness to EBITDA was 3.7:1.0 and our ratio of current assets to current liabilities was 1.0:1.0. If liquidity concerns are not addressed in the near-term, we may breach the leverage covenant of our revolving credit facility which currently requires a maximum ratio of net consolidated indebtedness to EBITDA of 4.5:1.0 through December 31, 2015 and 4.0:1.0 thereafter. As of March 31, 2015, we are in compliance with our financial covenants; however, we cannot guarantee that we will be able to comply with such terms at all times in the future. Any failure to comply with the conditions and covenants in our Credit Facility that is not waived by our lenders or otherwise cured could lead to a termination of our Credit Facility, acceleration of all amounts due under our Credit Facility, or trigger cross-default provisions under other financing arrangements. These restrictions may limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our indebtedness impose on us.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Correction of Operating and Investing Cash Flows for the Years Ended December 31, 2014, 2013 and 2012

In the first quarter of 2015, the Company determined that it had incorrectly presented non-cash accrued capital expenditures in its Statements of Cash Flows since December 31, 2012. Management concluded the misstatement is immaterial to previously issued financial statements; however, the Company intends to correct the cash flow presentation prospectively in future filings. . There was no impact to the Consolidated Balance Sheets as of December 31, 2014 and 2013, or the Consolidated Statements of Operations for the years ended December 31, 2014, 2013 and 2012. The impact of the misstatement on the Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012 is shown in the table below (in thousands):

	For the Twelve Months Ended December 31,
	2014						2013						2012
Statement of Cash Flows	As Previously Reported			As Restated			As Previously Reported			As Restated			As Previously Reported			As Restated
Change in operating assets and liabilities:
accounts receivable - JIB and other	$	(13,603	)	$	(18,897	)	$	(28,488	)	$	(19,754	)	$	(11,019	)	$	15,972
Net cash provided by operating activities	356,838			351,544			227,102			235,836			137,249			164,240
Investment in property and equipment	(561,691		)	(556,397		)	(573,734		)	(582,468		)	(422,332		)	(449,323		)
Net cash used in investing activities	(409,558		)	(404,264		)	(1,193,846		)	(1,202,580		)	(773,608		)	(800,599		)

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 11, 2015	/s/ Frederic F. Brace
	Frederic F. Brace
	Interim President and Chief Executive Officer
	(Principal Executive Officer)
Dated: May 11, 2015	/s/ Nelson M. Haight
	Nelson M. Haight
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer and 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		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).
3.4		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).
10.1		Sixth Amendment to Second Amended and Restated Credit Agreement, dated as of June 8, 2012, by and among Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC, Sun Trust Bank as administrative agent and the other lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 25, 2015, and incorporated herein by reference).
10.2		Executive Employment Agreement, dated as of March 9, 2015, by and between Midstates Petroleum Company, Inc. and Frederic F. Brace (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K/A filed on April 3, 2015, and incorporated herein by reference).
31.1	*	Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
31.2	*	Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
32.1	**	Sarbanes-Oxley Section 906 certification of Principal Executive Officer and Principal Financial Officer
101.INS		XBRL Instance Document.

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101.SCH	XBRL Schema Document.
101.CAL	XBRL Calculation Linkbase Document.
101.DEF	XBRL Definition Linkbase Document.
101.LAB	XBRL Labels Linkbase Document
101.PRE	XBRL Presentation Linkbase Document.

*	Filed herewith
**	Furnished herewith

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