Edgar Filing: Midstates Petroleum Company, Inc.

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2015

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

For the transition period from to

Commission File Number: 001-35512

MIDSTATES PETROLEUM COMPANY, INC.

(Exact name of registrant as specified in its charter)

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

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

(918) 947-8550

(Registrant’s telephone number, including area code)

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

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

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

Large accelerated filer o		Accelerated filer 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 November 2, 2015 is shown below:

Class		Number of shares outstanding
Common stock, $0.01 par value		10,888,883

Table of Contents

MIDSTATES PETROLEUM COMPANY, INC.

QUARTERLY REPORT ON

FORM 10-Q

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2015

TABLE OF CONTENTS

			Page

Glossary of Oil and Natural Gas Terms			3

PART I - FINANCIAL INFORMATION

	Item 1. Financial Statements
		Condensed Consolidated Balance Sheets at September 30, 2015 and December 31, 2014 (unaudited)	4
		Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2015 and 2014 (unaudited)	5
		Condensed Consolidated Statements of Changes in Stockholders’ Equity (Deficit) for the Nine Months Ended September 30, 2015 and 2014 (unaudited)	6
		Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 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		24

	Item 3. Quantitative and Qualitative Disclosures About Market Risk		44

	Item 4. Controls and Procedures		45

	PART II - OTHER INFORMATION

	Item 1. Legal Proceedings		46

	Item 1A. Risk Factors		46

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		47

	Item 3. Defaults Upon Senior Securities		47

	Item 4. Mine Safety Disclosures		47

	Item 5. Other Information		47

	Item 6. Exhibits		47

SIGNATURES			48

EXHIBIT INDEX			49

Table of Contents

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.

Table of Contents

PART I - FINANCIAL INFORMATION

MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands, except share amounts)

	September 30, 2015			December 31, 2014
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	166,783		$	11,557
Accounts receivable:
Oil and gas sales	44,785			69,161
Joint interest billing	10,371			42,407
Other	14,609			22,193
Commodity derivative contracts	33,051			126,709
Other current assets	1,559			1,098
Total current assets	271,158			273,125

PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of full-cost accounting	3,615,661			3,442,681
Other property and equipment	15,065			13,454
Less accumulated depreciation, depletion, amortization and impairment	(2,651,068		)	(1,333,019		)
Net property and equipment	979,658			2,123,116

OTHER ASSETS:
Deferred income taxes	9,245			35,821
Other noncurrent assets	38,000			43,731
Total other assets	47,245			79,552

TOTAL	$	1,298,061		$	2,475,793

LIABILITIES AND EQUITY (DEFICIT)

CURRENT LIABILITIES:
Accounts payable	$	5,546		$	22,783
Accrued liabilities	160,162			183,831
Deferred income taxes	9,245			44,862
Total current liabilities	174,953			251,476

LONG-TERM LIABILITIES:
Asset retirement obligations	18,152			21,599
Long-term debt	1,916,021			1,735,150
Other long-term liabilities	4,946			1,706
Total long-term liabilities	1,939,119			1,758,455

COMMITMENTS AND CONTINGENCIES (Note 15)

STOCKHOLDERS’ EQUITY (DEFICIT):
Preferred stock, $0.01 par value, 49,675,000 shares authorized; no shares issued or outstanding at September 30, 2015 and December 31, 2014	—			—
Series A mandatorily convertible preferred stock, $0.01 par value, $387,808 liquidation value at December 31, 2014; 8% cumulative dividends; 325,000 shares issued and outstanding at December 31, 2014	—			3
Common stock, $0.01 par value, 100,000,000 shares authorized; 10,985,783 shares issued and 10,891,270 shares outstanding at September 30, 2015 and 7,049,173 shares issued and 6,995,705 shares outstanding at December 31, 2014	110			70
Treasury stock	(3,068		)	(2,592		)
Additional paid-in-capital	887,424			882,528
Retained deficit	(1,700,477		)	(414,147		)
Total stockholders’ equity (deficit)	(816,011		)	465,862

TOTAL	$	1,298,061		$	2,475,793

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

Table of Contents

MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share amounts)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2015			2014			2015			2014
REVENUES:
Oil sales	$	50,684		$	125,430		$	177,439		$	372,925
Natural gas liquid sales	8,498			22,989			29,747			71,528
Natural gas sales	17,375			24,607			52,543			74,986
Gains (losses) on commodity derivative contracts — net	33,368			50,978			35,447			(3,162		)
Other	438			757			1,106			1,136

Total revenues	110,363			224,761			296,282			517,413

EXPENSES:
Lease operating and workover	18,803			16,965			63,823			56,813
Gathering and transportation	4,017			3,902			11,386			9,697
Severance and other taxes	2,660			5,780			8,729			19,059
Asset retirement accretion	382			406			1,217			1,335
Depreciation, depletion, and amortization	44,714			73,109			158,397			211,084
Impairment in carrying value of oil and gas properties	486,895			—			1,159,951			86,471
General and administrative	6,677			9,879			29,792			34,997
Acquisition and transaction costs	5			1,283			256			3,894
Debt restructuring costs and advisory fees	—			—			36,141			—
Other	—			2,346			63			3,285

Total expenses	564,153			113,670			1,469,755			426,635

OPERATING INCOME (LOSS)	(453,790		)	111,091			(1,173,473		)	90,778

OTHER INCOME (EXPENSE):
Interest income	43			10			80			29
Interest expense — net of amounts capitalized	(40,595		)	(34,288		)	(121,978		)	(102,048		)

Total other expense	(40,552		)	(34,278		)	(121,898		)	(102,019		)

INCOME (LOSS) BEFORE TAXES	(494,342		)	76,813			(1,295,371		)	(11,241		)

Income tax (expense) benefit	—			(2,216		)	9,041			96

NET INCOME (LOSS)	$	(494,342	)	$	74,597		$	(1,286,330	)	$	(11,145	)

Preferred stock dividend	(148		)	(1,908		)	(948		)	(9,334		)
Participating securities — Series A Preferred Stock	—			(23,973		)	—			—
Participating securities — Non-vested Restricted Stock	—			(2,524		)	—			—

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(494,490	)	$	46,192		$	(1,287,278	)	$	(20,479	)

Basic and diluted net income (loss) per share attributable to common shareholders	$	(72.34	)	$	6.94		$	(189.90	)	$	(3.09	)
Basic and diluted weighted average number of common shares outstanding	6,835			6,659			6,779			6,634

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

Table of Contents

MIDSTATES PETROLEUM COMPANY, INC.

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

(Unaudited)

(In thousands)

	Series A Preferred Stock			Common Stock		Treasury Stock			Additional Paid-in- Capital			Retained Deficit			Total Stockholders’ Equity (Deficit)
Balance as of December 31, 2014	$	3		$	70	$	(2,592	)	$	882,528		$	(414,147	)	$	465,862
Share-based compensation	—			3		—			4,930			—			4,933
Acquisition of treasury stock	—			—		(476		)	—			—			(476		)
Net loss	—			—		—			—			(1,286,330		)	(1,286,330		)
Conversion of preferred shares	(3		)	37		—			(34		)	—			—
Balance as of September 30, 2015	$	—		$	110	$	(3,068	)	$	887,424		$	(1,700,477	)	$	(816,011	)

	Series A Preferred Stock		Common Stock		Treasury Stock			Additional Paid-in- Capital		Retained Deficit			Total Stockholders’ Equity
Balance as of December 31, 2013	$	3	$	69	$	(664	)	$	871,667	$	(531,076	)	$	339,999
Share-based compensation	—		2		—			7,143		—			7,145
Acquisition of treasury stock	—		—		(1,722		)	—		—			(1,722		)
Net loss	—		—		—			—		(11,145		)	(11,145		)
Balance as of September 30, 2014	$	3	$	71	$	(2,386	)	$	878,810	$	(542,221	)	$	334,277

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

Table of Contents

MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Nine Months Ended September 30,
	2015			2014

CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(1,286,330	)	$	(11,145	)
Adjustments to reconcile net loss to net cash provided by operating activities:
(Gains) losses on commodity derivative contracts — net	(35,447		)	3,162
Net cash received (paid) for commodity derivative contracts not designated as hedging instruments	129,105			(39,213		)
Asset retirement accretion	1,217			1,335
Depreciation, depletion, and amortization	158,397			211,084
Impairment in carrying value of oil and gas properties	1,159,951			86,471
Share-based compensation, net of amounts capitalized to oil and gas properties	3,813			5,358
Deferred income taxes	(9,041		)	(96		)
Amortization of deferred financing costs	9,791			6,018
Paid-in-kind interest expense	3,785			—
Amortization of deferred gain on debt restructuring	(8,979		)	—
Transaction costs for debt restructuring	34,398			—
Change in operating assets and liabilities:
Accounts receivable — oil and gas sales	18,183			5,179
Accounts receivable — JIB and other	28,293			6,064
Other current and noncurrent assets	(287		)	1,815
Accounts payable	(3,448		)	503
Accrued liabilities	33,036			30,921
Other	(545		)	124
Net cash provided by operating activities	$	235,892		$	307,580

CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment	(271,576		)	(430,876		)
Proceeds from the sale of oil and gas properties	40,168			150,530
Net cash used in investing activities	$	(231,408	)	$	(280,346	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings	625,000			—
Proceeds from revolving credit facility	33,000			99,000
Repayment of long-term borrowings	—			—
Repayment of revolving credit facility	(468,150		)	(131,000		)
Deferred financing costs	(4,234		)	(958		)
Transaction costs for debt restructuring	(34,398		)	—
Acquisition of treasury stock	(476		)	(1,722		)
Net cash provided by (used in) financing activities	$	150,742		$	(34,680	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	$	155,226		$	(7,446	)

Cash and cash equivalents, beginning of period	$	11,557		$	33,163

Cash and cash equivalents, end of period	$	166,783		$	25,717

SUPPLEMENTAL INFORMATION:
Non-cash investment in property and equipment	$	36,373		$	98,000
Non-cash exchange of third lien notes for 2020 senior notes and 2021 senior notes	524,121			—
Cash paid for interest, net of capitalized interest of $2.9 million and $10.5 million, respectively	70,711			63,583

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

Table of Contents

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

2. Liquidity and Capital Resources

As a result of substantial declines in oil, NGL, and natural gas prices during the latter half of 2014 and continuing into 2015, we expect lower operating cash flows than previously experienced and if commodity prices continue to remain low, our liquidity will be impacted as current hedging contracts expire. During the three and nine months ended September 30, 2015, the Company received cash payments on settled derivative contracts of $34.3 million and $129.1 million, respectively. These cash payments on settled derivative contracts increased our operating cash flows by approximately 54.7% during the nine months ended September 30, 2015. The weighted average fixed price of the Company’s derivative contracts for the second half of 2015 is lower than the weighted average fixed price for the first half of 2015, and the Company currently has no derivative contracts for any period subsequent to 2015. As such, unless new hedging contracts are put in place, cash payments from settled derivative contracts will not be received in 2016 and future periods due to the expiration of our current hedging contracts.

The interest payment obligations of the Company are substantial and the uncertainty associated with the Company’s future 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 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 reserve based revolving credit facility (the “Credit Facility”) waiving any default as a result of receiving such qualification. The accompanying financial statements do not include any adjustments that might result from the uncertainty associated with the Company’s ability to meet obligations as they come due.

As a result of the commodity price decline and the Company’s substantial debt burden, the Company took steps to increase its liquidity and amend certain debt covenants. On April 21, 2015, the Company closed on the sale of certain of its oil and gas properties in Beauregard and Calcasieu Parishes, Louisiana (the “Dequincy Divestiture”), for approximately $44.0 million, before customary post-closing adjustments. The net proceeds from the Dequincy Divestiture were retained for general corporate purposes.

On May 21, 2015, the Company sold $625.0 million of 10.0% Second Lien Senior Secured Notes due 2020 (the “Second Lien Notes”) and utilized the proceeds to repay the outstanding balance of the Credit Facility of approximately $468.2 million, with the remainder to be utilized for general corporate purposes. Further, the Company exchanged approximately $504.1 million of 12.0% Third Lien Senior Secured Notes due 2020 (the “Third Lien Notes”) for approximately $279.8 million of 10.75% Senior Unsecured Notes due 2020 (the “2020 Senior Notes”) and $350.3 million of 9.25% Senior Unsecured Notes due 2021 (the “2021 Senior Notes” together with the 2020 Senior Notes, the “Unsecured Notes”), representing an exchange at 80.0% of the exchanged Unsecured Notes’ par value. Additionally, on June 2, 2015, the Company exchanged approximately $20.0 million of Third Lien Notes for approximately $26.6 million of 2020 Senior Notes and $2.0 million of 2021 Senior Notes, representing an exchange at 70.0% of the exchanged Unsecured Notes’ par value. The Company also entered into a Seventh Amendment to the Credit Facility (“Seventh Amendment”) which provided that upon completion of the Second Lien Notes offering and Third Lien Notes exchange, the borrowing base of the Credit Facility would be reduced to $252.0 million. The Seventh Amendment also provided additional covenant flexibility. For further information regarding the Second Lien Notes, Third Lien Notes and updates to the Company’s debt covenants, see “— Note 10. Long-Term Debt.” The Dequincy Divestiture, the issuance of the Second Lien Notes and the exchange of the Third Lien Notes increased the Company’s cash balance, increased the amount of borrowings currently available under the Credit Facility, and as a result, increased the liquidity of the Company.

Table of Contents

Additionally, on October 14, 2015, the Company and Midstates Sub entered into the Ninth Amendment to the Credit Facility (the “Ninth Amendment”) which, among other items, reaffirmed the borrowing base at $252.0 million and provided flexibility for certain specified asset sales by confirming the amount of the reduction in the borrowing base if such sale occurs.

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 Registration Statements on Form S-4 as filed with the SEC on October 2, 2015.

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.

Reverse Stock Split

On August 3, 2015, the Company completed a 1-for-10 reverse stock split of its outstanding common stock. To effect the reverse stock split, the Company filed a Certificate of Amendment to the Company’s Restated Certificate of Incorporation, which provides for the reverse stock split and for the corresponding reduction in the Company’s authorized capital stock to 100 million shares of common stock, $0.01 par value per share, following the reverse stock split. The condensed consolidated financial statements and notes to the condensed consolidated financial statements included in this document give retrospective effect to the reverse stock split for all prior periods presented.

Recently Issued Standards Not Yet Adopted

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

In April 2015, the FASB issued Accounting Standards Update 2015-03, “Interest — Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (Topic 835)” (“ASU 2015-03”). ASU 2015-03 requires debt issuance costs related to a recognized debt liability be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability. ASU 2015-03 is applied retrospectively and is effective for the Company beginning on January 1, 2016. The Company does not believe the adoption of ASU 2015-03 will have a material impact on its financial position, results of operations or cash flows.

In August 2015, the FASB issued Accounting Standards Update 2015-15, “Interest — Imputation of Interest: Presentation and Subsequent Measurement of Debt Issuance Associated with Line-of-Credit Arrangements” (“ASU 2015-15”). ASU 2015-15 addresses debt issuance costs associated with line-of-credit arrangements by allowing an entity to defer and present such debt issuance costs as an asset regardless of whether there are any outstanding borrowings under the line-of-credit arrangement. ASU 2015-15 is applied retrospectively and is effective for the Company beginning on January 1, 2016. The Company does not believe the adoption of ASU 2015-15 will have a material impact on its financial position, results of operations or cash flows.

Table of Contents

In September 2015, the FASB issued Accounting Standards Update 2015-16, “Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments” (“ASU 2015-16”). ASU 2015-16 simplifies measurement period adjustments associated with business combinations accounted for under FASB Accounting Standards Codification (“ASC”) 805, Business Combinations. ASU 2015-16 changes the accounting for measurement period adjustments by eliminating the requirement that such adjustments are made retrospectively. As a result, such measurement period adjustments will be recognized in the reporting period in which the adjustment was determined. ASU 2015-16 is applied prospectively to adjustments to provisional amounts that occur after the effective date. ASU 2015-16 is effective for the Company beginning on January 1, 2016. The Company does not believe the adoption of ASU 2015-16 will have a material impact on its financial position, results of operations or cash flows.

Correction of Operating and Investing Cash Flows for the Nine Months Ended September 30, 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 nine months ended September 30, 2014. The misstatement had no impact on the Condensed Consolidated Balance Sheet as of December 31, 2014, or on the Condensed Consolidated Statement of Operations for the three or nine months ended September 30, 2014. The impact of the correction is shown in the following table:

	For the Nine Months Ended September 30, 2014
Statement of Cash Flows	As Previously Reported			As Restated
	(in thousands)
Change in operating assets and liabilities:
Accounts receivable - JIB and other	$	10,551		$	6,064
Net cash provided by operating activities	312,067			307,580

Investment in property and equipment	(435,363		)	(430,876		)
Net cash used in investing activities	(284,833		)	(280,346		)

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 September 30, 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 consist of 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. See “— Note 5. Risk Management and Derivative Instruments” for additional information on the Company’s derivative instruments and balance sheet presentation.

Table of Contents

	Fair Value Measurements at September 30, 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	$	—	$	28,440	$	—	$	28,440
Commodity derivative gas swaps	—		4,611		—		4,611
Total assets	$	—	$	33,051	$	—	$	33,051

Liabilities:
Commodity derivative oil swaps	$	—	$	—	$	—	$	—
Commodity derivative gas swaps	—		—		—		—
Total liabilities	$	—	$	—	$	—	$	—

	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, NGL and natural gas prices. The Company believes it is prudent to manage the variability in cash flows by periodically entering into derivative financial instruments to economically hedge a portion of its crude oil, NGL and natural gas production. The Company utilizes various types of derivative financial instruments, including swaps and collars, to reduce fluctuations in cash flows resulting from changes in commodity prices. These derivative contracts are placed with major financial institutions that the Company believes are minimal credit risks. The oil, NGL and natural gas reference prices, upon which the commodity derivative contracts are based, reflect various market indices that management believes have a high degree of historical correlation with actual prices received by the Company for its crude oil, NGL and natural gas production. Although the Company has entered into derivative financial instruments in the past on an ongoing basis, as a result of the Company’s continued monitoring of commodity prices, the Company currently has no derivatives in place for any period subsequent to 2015.

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. At September 30, 2015, the Company had exposure of $33.1 million from counterparties failure to perform under existing commodity derivative contracts.

Table of Contents

Commodity Derivative Contracts

As of September 30, 2015, the Company had the following open commodity derivative contract positions:

	Hedged	Weighted-Average
	Volume	Fixed Price
Oil (Bbls):
WTI Swaps — 2015	1,104,000	$	71.56

Natural Gas (MMBtu):
Swaps — 2015(1)	4,600,000	$	4.13

(1) Includes 1,550,000 MMBtus in natural gas swaps that priced during the period, but had not cash settled as of September 30, 2015.

Balance Sheet Presentation

The following table summarizes the gross fair values of derivative instruments by the appropriate balance sheet classification; however, the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s unaudited condensed consolidated balance sheets at September 30, 2015 and December 31, 2014, respectively (in thousands):

Type	Balance Sheet Location (1)	September 30, 2015		December 31, 2014
Oil Swaps	Derivative financial instruments — Current Assets	$	28,440	$	106,450
Gas Swaps	Derivative financial instruments — Current Assets	4,611		20,259
Total derivative fair value at period end		$	33,051	$	126,709

(1) The fair values of commodity derivative instruments reported in the Company’s condensed 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 unaudited condensed consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the unaudited condensed consolidated balance sheets at September 30, 2015 and December 31, 2014, respectively (in thousands):

		September 30, 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	$	33,051	$	—	$	33,051
Commodity contracts	Derivative financial instruments - noncurrent	—		—		—
		$	33,051	$	—	$	33,051
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	—		—		—
		$	—	$	—	$	—

Table of Contents

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 net cash received (paid) for commodity derivative contracts and unrealized net gains (losses) recorded by the Company related to the change in fair value of the derivative instruments in “Gains (losses) on commodity derivative contracts — net” for the periods presented:

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2015			2014			2015			2014
	(in thousands)						(in thousands)
Net cash received (paid) for commodity derivative contracts	$	34,307		$	(7,265	)	$	129,105		$	(39,213	)
Unrealized net gains (losses)	(939		)	58,243			(93,658		)	36,051
Gains (losses) on commodity derivative contracts - net	$	33,368		$	50,978		$	35,447		$	(3,162	)

6. Property and Equipment

	September 30, 2015			December 31, 2014
	(in thousands)
Oil and gas properties, on the basis of full-cost accounting:
Proved properties	$	3,584,259		$	3,398,146
Unevaluated properties	31,402			44,535
Other property and equipment	15,065			13,454
Less accumulated depreciation, depletion, amortization and impairment	(2,651,068		)	(1,333,019		)
Net property and equipment	$	979,658		$	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 and nine months ended September 30, 2015 and 2014, the Company capitalized the following (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014

Internal costs capitalized to oil and gas properties (1)	$	1,632	$	2,771	$	6,547	$	9,159

(1) Inclusive of $0.3 million and $0.6 million of qualifying share-based compensation expense for the three months ended September 30, 2015 and 2014, respectively. For the nine months ended September 30, 2015 and 2014, inclusive of $1.1 million and $1.8 million, respectively, of qualifying share-based compensation expense.

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.

Table of Contents

The Company performs a 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 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 (“ARO”) 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 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 condensed consolidated statements of operations.

For the three months ended September 30, 2015, capitalized costs exceeded the ceiling and the Company recorded an impairment of oil and gas properties of $486.9 million. During the nine months ended September 30, 2015 and 2014, the Company recorded impairments of oil and gas properties of $1.2 billion and $86.5 million, respectively. Impairments for the nine months ended September 30, 2015 were 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. Subsequent to September 30, 2015, commodity prices have not only continued to be suppressed, but in many instances have declined further. As a result, the simple average of oil and natural gas prices as of the first day of each month for the trailing 12-months will continue to decline throughout the remainder of fiscal 2015, which will continue to negatively impact the discounted present value of the Company’s proved oil and gas reserves. Holding all other factors constant, if the simple average of oil and natural gas prices as of the first day of each month for the trailing 12-month period ended September 30, 2015 decreased by 20.0%, the Company’s ceiling test limitation related to the net book value of the Company’s proved oil and natural gas properties would have been reduced by 44.5%. The impact of price is only a single variable in the estimation of the present value of estimated future net revenues from projected production of oil and gas reserves of the Company. Other factors, such as cost estimates, performance revisions, and changes in development plans, among others, have a significant impact on future reserves and the present value of future cash flows.

Depreciation, depletion and amortization is calculated using the Units of Production Method (“UOP”). The UOP calculation multiplies the percentage of estimated proved reserves produced by the cost of those reserves. The result is to recognize expense at the same pace that the reservoirs are estimated to be depleting. The amortization base in the UOP calculation includes the sum of proved property costs net of accumulated depreciation, depletion, amortization and impairment, estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs that are not already included in oil and gas property, less related salvage value. The following table presents depletion expense related to oil and gas properties for the three and nine months ended September 30, 2015 and 2014, respectively:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2015		2014		2015		2014		2015		2014		2015		2014
	(in thousands)				(per Boe)				(in thousands)				(per Boe)
Depletion expense	$	43,814	$	72,337	$	14.60	$	23.27	$	155,778	$	208,864	$	17.01	$	24.22
Depreciation on other property	900		772		0.30		0.25		2,619		2,220		0.29		0.26
Depreciation, depletion, and amortization	$	44,714	$	73,109	$	14.90	$	23.52	$	158,397	$	211,084	$	17.30	24.48

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 $31.4 million and $44.5 million at September 30, 2015 and December 31, 2014, respectively.

Other Property and Equipment

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

Table of Contents

Sale of Dequincy Assets

On April 21, 2015, the Company closed the Dequincy Divestiture for $44.0 million to Pintail Oil and Gas LLC. The net proceeds, inclusive of amounts placed in escrow, were approximately $42.4 million, which was net of customary closing adjustments. This amount was reflected as a reduction of oil and natural gas properties, with no gain or loss recognized. The proceeds from the sale were retained for general corporate purposes.

7. Other Noncurrent Assets

At September 30, 2015 and December 31, 2014 other noncurrent assets consisted of the following:

	September 30, 2015		December 31, 2014
	(in thousands)
Deferred financing costs	$	32,251	$	37,807
Field inventory	5,583		5,713
Other	166		211
Other noncurrent assets	$	38,000	$	43,731

During the nine months ended September 30, 2015, approximately $4.6 million in deferred financing costs were impaired as a result of the Seventh Amendment to the Credit Facility. The Seventh Amendment is further discussed in “— Note 10. Long-Term Debt.”

8. Accrued Liabilities

At September 30, 2015 and December 31, 2014 accrued liabilities consisted of the following:

	September 30, 2015		December 31, 2014
	(in thousands)
Accrued oil and gas capital expenditures	$	31,936	$	76,398
Accrued revenue and royalty distributions	33,498		51,292
Accrued lease operating and workover expense	12,062		10,113
Accrued interest	67,997		21,521
Accrued taxes	5,219		4,226
Other	9,450		20,281
Accrued liabilities	$	160,162	$	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 AROs at inception is capitalized as part of the carrying amount of the related long-lived assets.

The following table reflects the changes in the Company’s AROs for the periods indicated:

	Nine Months Ended			Nine Months Ended
	September 30, 2015			September 30, 2014
	(in thousands)
Asset retirement obligations — beginning of period	$	21,599		$	26,308
Liabilities incurred	35			991
Revisions	—			—
Liabilities settled	—			(47		)
Liabilities eliminated through asset sales	(4,699		)	(7,652		)
Current period accretion expense	1,217			1,335
Asset retirement obligations — end of period	$	18,152		$	20,935

Table of Contents

10. Long-Term Debt

The Company’s long-term debt as of September 30, 2015 and December 31, 2014 is as follows (in thousands):

	December 31, 2014 Carrying Value		Borrowings		Repayments			Exchanges			Deferred Gain on Forgiven Debt			Amortization of Forgiven Debt			September 30, 2015 Carrying Value
Credit Facility	$	435,150	$	33,000	$	(468,150	)	$	—		$	—		$	—		$	—
2020 Senior Notes	600,000		—		—			(242,445		)	(63,930		)	—			293,625
2021 Senior Notes	700,000		—		—			(281,676		)	(70,672		)	—			347,652
Second Lien Notes	—		625,000		—			—			47,082			(2,899		)	669,183
Third Lien Notes	—		—		—			524,121			87,520			(6,080		)	605,561
Total debt	$	1,735,150	$	658,000	$	(468,150	)	$	—		$	—		$	(8,979	)	$	1,916,021
Current maturities	—		—		—			—			—			—			—
Total long-term debt	$	1,735,150	$	658,000	$	(468,150	)	$	—		$	—		$	(8,979	)	$	1,916,021

	September 30, 2015 Carrying Value		Unamortized Deferred Gain on Debt Forgiven			September 30, 2015 Principle Balance Outstanding
Credit Facility	$	—	$	—		$	—
2020 Senior Notes	293,625		—			293,625
2021 Senior Notes	347,652		—			347,652
Second Lien Notes	669,183		(44,183		)	625,000
Third Lien Notes	605,561		(81,440		)	524,121
Total debt	$	1,916,021	$	(125,623	)	$	1,790,398
Current maturities	—		—			—
Total long-term debt	$	1,916,021	$	(125,623	)	$	1,790,398

Debt Restructuring

On May 21, 2015, the Company issued $625.0 million of Second Lien Notes and utilized the proceeds to repay the outstanding balance of the Credit Facility in an amount of approximately $468.2 million, with the remainder to be utilized for general corporate purposes. Further, the Company exchanged approximately $504.1 million of Third Lien Notes for approximately $279.8 million of 2020 Senior Notes and $350.3 million of 2021 Senior Notes, representing an exchange at 80.0% of the exchanged Unsecured Notes’ par value. Additionally, on June 2, 2015, the Company exchanged approximately $20.0 million of Third Lien Notes for approximately $26.6 million of 2020 Senior Notes and $2.0 million of 2021 Senior Notes, representing an exchange at 70.0% of the exchanged Unsecured Notes’ par value. Approximately $63.9 million of the principal amount of 2020 Senior Notes and $70.7 million of the principal amount of 2021 Senior Notes was extinguished.

Additionally, the Company and Midstates Sub entered into the Seventh Amendment to the Credit Facility which provided that upon completion of the offering of the Second Lien Notes and exchange of Third Lien Notes, the borrowing base of the Credit Facility would be reduced to $252.0 million. The Seventh Amendment also provided additional covenant flexibility. Further discussion regarding the Second Lien Notes, Third Lien Notes and Seventh Amendment can be found below. The exchanges of Third Lien Notes for the Unsecured Notes as well as the issuance of the Second Lien Notes were accounted for as a troubled debt restructuring. As the future cash flows of the modified debt instruments were greater than the carrying amount of the previous debt instruments, no gain was recognized. The amount of extinguished debt will be amortized over the remaining life of the Second Lien Notes and Third Lien Notes using the effective interest method and recognized as a reduction of interest expense. As a result, the Company’s reported interest expense will be significantly less than the contractual interest payments throughout the term of the Second Lien Notes and Third Lien Notes. All costs incurred related to the May 21, 2015 and June 2, 2015 exchanges, including restructuring costs as well as the direct issuance costs of the Second Lien Notes and Third Lien Notes, were expensed and are included within debt restructuring costs and advisory fees in our condensed consolidated statements of operations.

Table of Contents

Reserve-based Credit Facility

The Company maintains a $750.0 million Credit Facility with a current borrowing base of $252.0 million supported by the Company’s Mississippian Lime and Anadarko Basin oil and gas assets. At September 30, 2015, the Company had no amounts drawn on the Credit Facility and had outstanding letters of credit obligations totaling $2.1 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.

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

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. On October 14, 2015, the Company and Midstates Sub entered into the Ninth Amendment, which, among other items, reaffirmed the borrowing base at $252.0 million. The next borrowing base redetermination is scheduled for April 2016.

Under the terms of the Credit Facility, the Company is required to repay any amount by which the principal balance of its outstanding loans and its letter of credit obligations exceeds its redetermined borrowing base or grant liens on additional property having sufficient value to eliminate such excess. 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.

On March 24, 2015, the Company and Midstates Sub entered into a Sixth Amendment (the “Sixth Amendment”) to the Credit Facility. The Sixth Amendment amended 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 amended the mortgage requirements under the Credit Facility to provide for an increase from 80.0% to 90.0% for the percentage of properties included in the borrowing base that are required to be subject to mortgages for the benefit of the lenders.

On May 21, 2015, the Company and Midstates Sub entered into a Seventh Amendment to the Credit Facility. The Seventh Amendment provided that, with the completion of the offering of the Second Lien Notes and exchange of the Third Lien Notes (both discussed below), the Company’s borrowing base was reduced to approximately $252.0 million. The Seventh Amendment also eliminated the required ratio of net consolidated indebtedness to EBITDA covenant and added a ratio of Total Senior Indebtedness (as defined therein) to EBITDA of not more than 1.0:1.0, which is further discussed below under “— Debt Covenants.”

On August 5, 2015, the Company and Midstates Sub entered into an Eighth Amendment (the “Eighth Amendment”) to the Credit Facility. The Eighth Amendment increased the limitation on certain leases and lease agreements into which Midstates and Midstates Sub may enter into during any period of twelve consecutive calendar months of the life of such leases from $2.0 million to $3.5 million.

2020 Senior Notes

On October 1, 2012, the Company issued $600.0 million in aggregate principal amount of 2020 Senior Notes, conducted pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended (the “Securities Act”). In October 2013, these notes were exchanged for an equal principal amount of identical registered notes. The 2020 Senior Notes rank pari passu in right of payment with the 2021 Senior Notes, the Second Lien Notes and Third Lien 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 100.0% ownership interest in Midstates Sub and there are no other subsidiaries of the Company. The indenture governing the 2020 Senior Notes (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.

Table of Contents

At any time before October 1, 2016, the Company may redeem all or a part of the 2020 Senior Notes at a redemption price equal to 100.0% of the principal amount of 2020 Senior Notes redeemed plus the Applicable Premium (as defined in the 2020 Senior Notes Indenture) at the redemption date, plus any accrued and unpaid interest, if any, up to the redemption date. On or after October 1, 2016, the Company may redeem all or a part of the 2020 Senior Notes at varying redemption prices (expressed as percentages of principal amount) set forth in the 2020 Senior Notes Indenture plus accrued and unpaid interest, if any, on the 2020 Senior Notes redeemed, up to the redemption date. As discussed above, on May 21, 2015 and June 2, 2015, a total of approximately $306.4 million aggregate principal amount of 2020 Senior Notes were exchanged for Third Lien Notes.

Upon the occurrence of certain change of control events, as defined in the 2020 Senior Notes Indenture, each holder of the 2020 Senior Notes will have the right to require that the Company repurchase all or a portion of such holder’s 2020 Senior Notes in cash at a purchase price equal to 101.0% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

The estimated fair value of the 2020 Senior Notes as of September 30, 2015 was $58.7 million (Level 2 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities. The effective interest rate was 10.8% for the three and nine months ended September 30, 2015 and 11.1% for the three and nine months ended September 30, 2014.

2021 Senior Notes

On May 31, 2013, the Company issued $700.0 million in aggregate principal amount of 2021 Senior Notes. In October 2013, these notes were exchanged for an equal principal amount of identical registered notes. The 2021 Senior Notes rank pari passu in right of payment with the 2020 Senior Notes, Second Lien Notes and Third Lien 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 indenture governing the 2021 Senior Notes (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.

Prior to June 1, 2016, the Company may, under certain circumstances, redeem up to 35.0% of the aggregate principal amount of the 2021 Senior Notes with the net proceeds of any equity offerings at a redemption price of 109.25% of the principal amount of the 2021 Senior Notes redeemed, plus any accrued and unpaid interest, if any, up to the redemption date. In addition, at any time before June 1, 2016, the Company may redeem all or a part of the 2021 Senior Notes at a redemption price equal to 100.0% of the principal amount of the 2021 Senior Notes redeemed plus the Applicable Premium (as defined in the 2021 Senior Notes Indenture) at the redemption date, plus any accrued and unpaid interest, if any, up to, the redemption date. On or after June 1, 2016, the Company may redeem all or a part of the 2021 Senior Notes at varying redemption prices (expressed as percentages of principal amount) set forth in the 2021 Senior Notes Indenture plus accrued and unpaid interest, if any, on the 2021 Senior Notes redeemed, up to, the redemption date. As discussed above, on May 21, 2015 and June 2, 2015, a total of approximately $352.3 million aggregate principal amount of 2021 Senior Notes were exchanged for Third Lien Notes.

Upon the occurrence of certain change of control events, as defined in the 2021 Senior Notes Indenture, each holder of the 2021 Senior Notes will have the right to require that the Company repurchase all or a portion of such holder’s 2021 Senior Notes in cash at a purchase price equal to 101.0% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

The estimated fair value as of September 30, 2015 of the 2021 Senior Notes was $67.8 million (Level 2 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities. The effective interest rate was 9.3% for the three and nine months ended September 30, 2015 and 9.6% for the three and nine months ended September 30, 2014.

Table of Contents

Second Lien Notes

On May 21, 2015, the Company and Midstates Sub issued and sold $625.0 million aggregate principal amount of Second Lien Notes, in a private placement conducted pursuant to Rule 144A under the Securities Act. The Second Lien Notes mature on the earlier of June 1, 2020 or 12 months after the maturity date of the Company’s Credit Facility (including any extension or refinancing of such facility). The Second Lien Notes have an interest rate of 10.0% and interest is payable semi-annually on June 1 and December 1 of each fiscal year. The Second Lien Notes are unconditionally guaranteed, jointly and severally, on a senior secured basis by each of the Company’s future restricted subsidiaries (the “Guarantors”) and will be initially secured by second-priority liens on substantially all of the Company’s and Guarantors’ assets that secure the Company’s Credit Facility.

On May 21, 2015, in connection with the offering of Second Lien Notes, the Company and Midstates Sub entered into a registration rights agreement with the initial purchasers of the Second Lien Notes pursuant to which the Company and Midstates Sub are obligated, within 270 days after the issuance of the Second Lien Notes, to file with the Securities and Exchange Commission under the Securities Act a registration statement with respect to an offer to exchange the Second Lien Notes for substantially identical registered new notes. On October 16, 2015, the Company filed a prospectus pursuant to an effective registration statement and launched an exchange offer to exchange the Second Lien Notes for an equal principal amount of identical registered notes. The Company expects the exchange of the Second Lien Notes to be completed in November 2015.

The Second Lien Notes are senior secured obligations of the Company and rank effectively junior to its obligations under the Credit Facility, effectively senior to its existing and future unsecured indebtedness, effectively senior to the Company’s Third Lien Notes and all future junior lien obligations, effectively junior to all existing and future secured indebtedness secured by assets not constituting collateral under the Second Lien Notes, pari passu with all of the Company’s existing and future senior debt, structurally subordinated to all existing and future indebtedness of any non-Guarantor subsidiaries and senior to any existing or future subordinated debt.

Upon the occurrence of certain change of control events, as defined in the indenture governing the Second Lien Notes, each holder of the Second Lien Notes will have the right to require that the Company repurchase all or a portion of such holder’s 2020 Second Lien Notes in cash at a purchase price equal to 101.0% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

The estimated fair value of the Second Lien Notes was $453.1 million as of September 30, 2015 (Level 2 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities. The effective interest rate was 8.8% and 8.7% for the three months and nine months ended September 30, 2015, respectively.

Third Lien Notes

On May 21, 2015 and June 2, 2015, the Company issued approximately $504.1 million and $20.0 million, respectively, in aggregate principal amount of Third Lien Notes in a private placement and in exchange for an aggregate $306.4 million of the 2020 Senior Notes and $352.3 million of the 2021 Senior Notes. The Third Lien Notes are unconditionally guaranteed, jointly and severally, on a senior secured basis by each of the Guarantors. The Third Lien Notes are secured by third-priority liens on substantially all of the Company’s assets that secure the Credit Facility. The Third Lien Notes have an interest rate of 12.0%, consisting of cash interest of 10.0% and paid-in-kind interest of 2.0%, per annum and mature on the earlier of June 1, 2020 or 12 months after the maturity date of the Company’s Credit Facility (including any extension or refinancing of such facility). Cash interest is payable semi-annually on June 1 and December 1 of each fiscal year. Paid-in-kind interest, which is included in other long-term liabilities in our condensed consolidated balance sheets, increases the outstanding principal balance of the Third Lien Notes on June 1 and December 1 of each fiscal year.

On May 21, 2015, in connection with the issuance of the Third Lien Notes, the Company and Midstates Sub entered into a registration rights agreement with the initial purchasers of the Third Lien Notes pursuant to which the Company and Midstates Sub is obligated, within 270 days after the issuance of the Third Lien Notes, to file with the Securities and Exchange Commission under the Securities Act a registration statement with respect to an offer to exchange the Third Lien Notes for substantially identical registered new notes. On October 16, 2015, the Company filed a prospectus pursuant to an effective registration statement and launched an exchange offer to exchange the Third Lien Notes for an equal principal amount of identical registered notes. The Company expects the exchange of the Third Lien Notes to be completed in November 2015.

Table of Contents

The Third Lien Notes are senior secured obligations of the Company and rank effectively junior to its obligations under the Credit Facility and Second Lien Notes to the extent of the value of the collateral securing such indebtedness, effectively senior to its existing and future unsecured indebtedness to the extent of the value of the collateral securing the Third Lien Notes, effectively senior to all future junior lien obligations that rank below a third-priority basis to the extent of the value of the collateral securing the Third Lien Notes, effectively junior to all existing and future secured indebtedness secured by assets not constituting collateral under the Third Lien Notes, pari passu to all of the Company’s existing and future senior debt, structurally subordinated to all existing and future indebtedness of any non-Guarantor subsidiaries and senior in right of payment to any existing or future subordinated debt.

Upon the occurrence of certain change of control events, as defined in the indenture governing the Third Lien Notes, each holder of the Third Lien Notes will have the right to require that the Company repurchase all or a portion of such holder’s Third Lien Notes in cash at a purchase price equal to 101.0% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

The estimated fair value of the Third Lien Notes was $188.7 million as of September 30, 2015 (Level 2 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities. The effective interest rate was 8.8% and 8.9% for the three and nine months ended September 30, 2015, respectively.

Debt Covenants

The indentures governing the 2020 Senior Notes, 2021 Senior Notes, Second Lien Notes and Third Lien Notes contain 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; (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.

Additionally, the Credit Facility, as amended, contains, among other standard affirmative and negative covenants, financial covenants including a maximum ratio of Total Senior Indebtedness to EBITDA (as defined therein) of not more than 1.0:1.0 and a minimum current ratio (as defined therein) of not less than 1.0 to 1.0. The Credit Facility also limits the Company’s ability to make any dividends, distributions or redemptions. The Company was in compliance with all debt covenants at September 30, 2015.

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 5.0% 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 the repayment of such other indebtedness.

· The indentures governing the 2020 Senior Notes, 2021 Senior Notes, Second Lien Notes and Third Lien 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 the repayment 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.

Table of Contents

11. Preferred Stock

Series A Preferred Stock

On October 1, 2012, the Company issued 325,000 shares of Series A Mandatorily Convertible Preferred Stock (“Series A Preferred Stock”) with an initial liquidation preference of $1,000 per share and an 8.0% per annum dividend, payable semiannually at the Company’s option in cash or through an increase in the liquidation preference. On March 30, 2015 and September 30, 2015, the Company elected to pay semi-annual dividends due of $15.2 million and $15.8 million, respectively, through an increase in the Series A Preferred Stock liquidation preference.

The Series A Preferred Shares were mandatorily convertible at September 30, 2015 into shares of the Company’s common stock at a conversion price of $110.00 per share, which was automatically adjusted to reflect the reverse stock split. Based on the liquidation preference at September 30, 2015, each Series A Preferred Share converted into approximately 11.5 shares of the Company’s common stock pursuant to the Certificate of Designation, which governed the Series A Preferred Stock. As a result, the Company issued 3,738,424 additional shares of common stock upon conversion of the Series A Preferred Stock.

12. Equity and Share-Based Compensation

Share Activity

The following table summarizes changes in the number of outstanding shares since December 31, 2014:

	Number of Shares
	Common Stock		Treasury Stock
Share count as of December 31, 2014	7,049,173		(53,467	)
Grants of restricted stock	268,677		—
Forfeitures of restricted stock	(70,481	)	—
Acquisition of treasury stock	—		(41,046	)
Fractional share adjustment	(10	)	—
Issuance of common stock for Series A Preferred Stock conversion	3,738,424		—
Share count as of September 30, 2015	10,985,783		(94,513	)

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

Share-based Compensation

2012 Long Term Incentive Plan

The 2012 LTIP provides for the granting of Options (incentive and other), Restricted Stock Awards, Restricted Stock Units, Stock Appreciation Rights, Dividend Equivalents, Bonus Stock, Other Stock-Based Awards, Annual Incentive Awards, Performance Awards, or any combination of the foregoing (the “Awards”). Subject to certain limitations as defined in the 2012 LTIP, the terms of each Award are as determined by the Compensation Committee of the Board of Directors. As of September 30, 2015 a total of 863,843 common share Awards are authorized for issuance and shares of stock subject to an Award that expire, or are canceled, forfeited, exchanged, settled in cash or otherwise terminated, will again be available for future Awards under the 2012 LTIP.

Table of Contents

Non-vested Stock Awards

At September 30, 2015, the Company had 356,438 non-vested shares of restricted common stock to directors, management and employees outstanding pursuant to the 2012 LTIP. Shares granted under the LTIP generally vest ratably over a period of three years (one-third on each anniversary of the grant); however, beginning in 2013, 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 nine months ended September 30, 2015:

	Shares		Weighted Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2014	306,201		$	52.76
Granted	268,677		$	12.29
Vested	(147,959	)	$	56.87
Forfeited	(70,481	)	$	42.47
Non-vested shares outstanding at September 30, 2015	356,438		$	21.99

Unrecognized expense, adjusted for estimated forfeitures, as of September 30, 2015 for all outstanding restricted stock awards was $5.0 million and will be recognized over a weighted average period of 1.7 years.

At September 30, 2015, 179,910 shares remain available for issuance under the terms of 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 and the effects of federal and state valuation allowance adjustments.

For the nine months ended September 30, 2015, the Company’s effective tax rate was a benefit of approximately 0.7%. The Company’s effective tax rate differs from the federal statutory rate of 35.0% due to the effect of state income taxes and changes in the valuation allowance. This year, the Company recorded $507.7 million in additional valuation allowance in light of the impairment of oil and gas properties, bringing the total valuation allowance to $511.6 million at September 30, 2015. A valuation allowance has been recorded as management does not believe that it is more-likely-than-not that the net operating loss (“NOL”) carryforwards 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 were 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 Income (Loss) Per Share

Prior to conversion on September 30, 2015, the Company’s Series A Preferred Stock had the non-forfeitable right to participate on an as converted basis at the conversion rate then in effect in any common stock dividends declared and as such, was considered a participating security. The Company’s non-vested stock awards, which are granted as part of the 2012 LTIP, contain non-forfeitable 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 income (loss) per share, pursuant to the two-class method. In the calculation of basic income (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 as such participating securities are not contractually obligated to do so.

Table of Contents

The computation of diluted income (loss) 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 income (loss) to preferred shareholders, common shareholders, and non-vested restricted shareholders for purposes of computing net income (loss) per share for the three and nine months ended September 30, 2015 and 2014, respectively:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Net income (loss)	$	(494,342	)	$	74,597		$	(1,286,330	)	$	(11,145	)
Preferred dividend (1)	(148		)	(1,908		)	(948		)	(9,334		)
Net income (loss) attributable to shareholders	$	(494,490	)	$	72,689		$	(1,287,278	)	$	(20,479	)

Participating securities - Series A Preferred Stock (2)	—			(23,973		)	—			—
Participating securities - Non-vested Restricted Stock (2)	—			(2,524		)	—			—
Net income (loss) attributable to common shareholders	$	(494,490	)	$	46,192		$	(1,287,278	)	$	(20,479	)

Weighted average shares outstanding	6,835			6,659			6,779			6,634
Net income (loss) per share	$	(72.34	)	$	6.94		$	(189.90	)	$	(3.09	)

(1) The Series A Preferred Stock converted into 3,738,424 common shares on September 30, 2015. For further information on the Series A Preferred Stock conversion and the calculation of the preferred stock dividend please see “— Note 11. Preferred Stock.”

(2) The Company’s participating securities participate in earnings but are not required to participate in losses of the Company. As such, this calculation does not allocate any loss to the non-vested restricted stockholders or Series A Preferred stockholders.

The aggregate number of common shares outstanding at September 30, 2015 was 10,891,270 of which 356,438 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.

Table of Contents

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 Registration Statements on Form S-4 filed with the SEC on October 2, 2015, as well as the unaudited condensed consolidated financial statements and notes thereto included in this quarterly report on Form 10-Q and our quarterly reports on Form 10-Q for quarterly periods ended March 31, 2015 and June 30, 2015.

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;

· cash flows and liquidity;

· financial strategy, budget, projections and operating results;

· oil and natural gas realized prices;

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

· availability of drilling and production equipment;

· availability of oilfield labor;

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

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

· availability and terms of capital;

· drilling of wells, including our identified drilling locations;

· successful results from our identified drilling locations;

· marketing of oil and natural gas;

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

· infrastructure for salt water disposal and electricity;

· current and future ability to dispose of salt water;

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

· costs of developing our properties and conducting other operations;

· general economic conditions;

· effectiveness of our risk management activities;

· environmental liabilities;

· counterparty credit risk;

· 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.

Table of Contents

All forward-looking statements speak only as of the date of this quarterly report. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this quarterly report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.

Overview

We are an independent exploration and production company focused on the application of modern drilling and completion techniques to oil-prone resources. Our common stock is listed on the New York Stock Exchange (“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, NGL and natural gas production and the prices 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 Developments

Debt Restructuring

On May 21, 2015, we conducted a debt restructuring transaction which included the issuance of $625.0 million of 10.0% Senior Secured Second Lien Notes due 2020 and utilized the proceeds to repay the outstanding balance of our reserve based revolving credit facility in an amount of approximately $468.2 million, with the remainder available for general corporate purposes. Further, we exchanged approximately $504.1 million of 12.0% Third Lien Senior Secured Notes due 2020 for approximately $279.8 million of 10.75% Senior Notes due 2020 and $350.3 million of 9.25% Senior Notes due 2021, representing an exchange at 80.0% of the exchanged Unsecured Notes’ par value. Additionally, on June 2, 2015, we exchanged approximately $20.0 million of Third Lien Notes for approximately $26.6 million of 2020 Senior Notes and $2.0 million of 2021 Senior Notes, representing an exchange at 70.0% of the exchanged Unsecured Notes’ par value. Approximately $63.9 million of the principal amount of 2020 Senior Notes and $70.7 million of the principal amount of 2021 Senior Notes were extinguished as a result of the exchanges occurring at a percentage of the Unsecured Notes’ par value.

Additionally, we entered into the Seventh Amendment which provided that upon completion of the offering of the Second Lien Notes and Third Lien Notes, the borrowing base of the Credit Facility would be reduced to $252.0 million. The Seventh Amendment also provided additional covenant flexibility. Further discussion regarding the Second Lien Notes, Third Lien Notes and Seventh Amendment can be found below under “—Liquidity and Capital Resources.”

Additionally, on October 14, 2015, we entered into the Ninth Amendment to the Credit Facility which, among other things, reaffirmed the borrowing base at $252.0 million and provided flexibility for certain specified asset sales by confirming the amount of the reduction in the borrowing base if any such sale should occur.

Dequincy Divestiture

On April 21, 2015, we closed the Dequincy Divestiture for $44.0 million to Pintail Oil and Gas LLC. The net proceeds, inclusive of amounts placed in escrow, were approximately $42.4 million, which was net of customary closing adjustments. This amount was reflected as a reduction of oil and natural gas properties, with no gain or loss recognized. The proceeds from the Dequincy Divestiture were retained for general corporate purposes. With the Dequincy Divestiture, we currently have no proved reserves or production in our Gulf Coast (Louisiana) operating area.

Table of Contents

Reverse Stock Split

On August 3, 2015, we completed a 1-for-10 reverse stock split of our outstanding common stock. To effect the reverse stock split, we filed a Certificate of Amendment to our Restated Certificate of Incorporation, which provides for the reverse stock split and for the corresponding reduction in our authorized capital stock to 100 million shares of common stock, $0.01 par value per share, following the reverse stock split. The information included in this quarterly report gives retrospective effect to the reverse stock split for all periods presented.

Series A Preferred Stock

On September 30, 2015, all 325,000 shares of the Series A Preferred Stock converted into shares of our common stock at a conversion price of $110.00 per share, which was automatically adjusted to reflect the reverse stock split. Each Series A Preferred Share converted into approximately 11.5 shares of our common stock, and as a result, we issued 3,738,424 additional shares of our common stock upon conversion of the Series A Preferred Stock.

Risks, Uncertainties and Going Concern

As a result of substantial declines in oil, NGLs and natural gas prices during the latter half of 2014 and continuing into 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. 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 and nine months ended September 30, 2015, we received cash payments on settled derivative contracts of $34.3 million and $129.1 million, respectively. These cash payments on settled derivative contracts increased our operating cash flows by approximately 54.7% during the nine months ended September 30, 2015. The weighted average fixed price of our derivative contracts for the second half of 2015 are lower than the weighted average fixed price for the first half of 2015, and we currently have no derivative contracts for any period subsequent to 2015. As such, unless new hedging contracts are put into place, cash payments from settled derivative contracts will not be received in 2016 or future periods due to the expiration of our current hedging contracts.

Our interest payment obligations are substantial and the uncertainty associated with our ability to meet future commitments as they come due or to repay outstanding debt raises substantial doubt about our ability to continue as a going concern. We received a going concern qualification from our 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. The accompanying financial statements do not include any adjustments that might result from the uncertainty associated with our ability to meet obligations as they come due.

As a result of the commodity price decline and our substantial debt burden, the Company took steps to increase its liquidity and amend certain debt covenants. As discussed above, we completed the Dequincy Divestiture on April 21, 2015, for approximately $42.4 million, inclusive of amounts placed in escrow and net of post-closing adjustments. The proceeds from the Dequincy Divestiture were retained for general corporate purposes.

Additionally, on May 21, 2015, we issued $625.0 million of Second Lien Notes and on May 21, 2015 and June 2, 2015 we exchanged an aggregate of approximately $524.1 million of Third Lien Notes for an aggregate of approximately $306.4 million of 2020 Senior Notes and $352.3 million of 2021 Senior Notes. Approximately $63.9 million of 2020 Senior Notes and $70.7 million of 2021 Senior Notes were extinguished as a result of the exchanges occurring at a percentage of the Unsecured Notes’ par value. For additional detail, please see “—Liquidity and Capital Resources” below.

We also entered into the Seventh Amendment which provided that upon completion of the Second Lien Notes offering and Third Lien Notes exchange, the borrowing base of the Credit Facility would be reduced to $252.0 million. The Seventh Amendment also provided additional covenant flexibility. On October 14, 2015, we entered into the Ninth Amendment which, among other things, reaffirmed the borrowing base at $252.0 million. Further discussion regarding the Second Lien Notes, Third Lien Notes, Seventh Amendment and Ninth Amendment can be found in “— Note 10. Long-Term Debt” to our condensed consolidated financial statements. Additionally, further discussion on liquidity can be found below under “—Liquidity and Capital Resources.”

Table of Contents

Operations Update

Mississippian Lime

For the three months ended September 30, 2015 and June 30, 2015, our average daily production from the Mississippian Lime area was as follows:

	Three Months Ended September 30, 2015	Three Months Ended June 30, 2015	Increase (Decrease) in Production

Average daily production:
Oil (Bbls)	10,131	10,828	(6.4	)%
Natural gas liquids (Bbls)	5,360	5,314	0.9	%
Natural gas (Mcf)	65,204	65,324	(0.2	)%
Net boe/day	26,358	27,029	(2.5	)%

The following table shows our total number of horizontal wells spud and brought into production in the Mississippian Lime area during the third quarter of 2015:

		Total Number of Gross Horizontal Wells Spud (1)		Total Number of Gross Horizontal Wells Brought into Production
Mississippian Lime		19		19

(1) We had three operated rigs drilling in the Mississippian Lime horizontal well program at September 30, 2015. Of the 19 wells spud, eight were producing, eight were awaiting completion and three were being drilled at quarter-end.

In the third quarter of 2015, we invested approximately $53.2 million on completions and drilling new wells.

Anadarko Basin

For the three months ended September 30, 2015 and June 30, 2015, our average daily production from our Anadarko Basin area was as follows:

	Three Months Ended September 30, 2015	Three Months Ended June 30, 2015	Increase (Decrease) in Production

Average daily production:
Oil (Bbls)	2,602	2,937	(11.4	)%
Natural gas liquids (Bbls)	1,427	1,404	1.6	%
Natural gas (Mcf)	13,337	13,468	(1.0	)%
Net boe/day	6,251	6,586	(5.1	)%

We did not spud any wells in the Anadarko Basin area and did not have any operated drilling rigs in the area during the third quarter of 2015.

Table of Contents

Capital Expenditures

During the three and nine months ended September 30, 2015, we incurred operational capital expenditures of $55.0 million and $218.4 million, respectively, which consisted primarily of:

	For the Three Months Ended September 30, 2015		For the Nine Months Ended September 30, 2015
	(in thousands)
Drilling and completion activities	$	53,145	$	213,545
Acquisition of acreage and seismic data	1,882		4,810
Operational capital expenditures incurred	$	55,027	$	218,355
Capitalized G&A, Office, ARO, & Other	3,328		7,664
Capitalized interest	858		2,924
Total capital expenditures incurred	$	59,213	$	228,943

Operational capital expenditures were incurred in the following areas:

	For the Three Months Ended September 30, 2015		For the Nine Months Ended September 30, 2015
	(in thousands)
Mississippian Lime	$	53,222	$	209,811
Anadarko Basin	1,805		6,461
Gulf Coast	—		2,083
Total capital expenditures incurred	$	55,027	$	218,355

We expect to invest between $265.0 million to $275.0 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. We plan to continue our strategy of hedging the risks associated with commodity price volatility; however, given the current low commodity price environment, we may limit the extent of our hedging program in the near-term as appropriate.

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 acquisitions. Our ability to make the necessary capital expenditures is dependent on cash flow from operations, continued access to and availability under our Credit Agreement, 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 and operational considerations.

Table of Contents

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 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. During the nine months ended September 30, 2015, the results of our full cost “ceiling test” required us to recognize $1.2 billion of impairments of our oil and gas properties. While these impairments did not impact cash flow from operating activities, they did reduce our earnings and stockholders’ equity, which resulted in a stockholders’ deficit of $816.0 million at September 30, 2015. We will likely be required to recognize additional impairments of oil and gas properties in future periods due to an extended period of low commodity prices, which would cause a downward adjustment to our estimated proved reserves or the present value of estimated future net revenues, or if we incur actual development costs in excess of those estimates utilized in preparing our reserve reports. Subsequent to September 30, 2015, commodity prices have not only continued to be suppressed, but in many instances have declined further. As a result, the simple average of oil and natural gas prices as of the first day of each month for the trailing 12-months will continue to decline throughout the remainder of fiscal 2015, which will continue to negatively impact the discounted present value of our proved oil and gas reserves. Holding all other factors constant, if the simple average of oil and natural gas prices as of the first day of each month for the trailing 12-month period ended September 30, 2015 decreased by 20.0%, our ceiling test limitation related to the net book value of our proved oil and natural gas properties would have been reduced by 44.5%. The impact of price is only a single variable in the estimation of the present value of estimated future net revenues from projected production of oil and gas reserves. Other factors, such as cost estimates, performance revisions, and changes in development plans, among others, have a significant impact on future reserves and the present value of future cash flows.

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.

Revenues

	For the Three Months Ended September 30,										For the Nine Months Ended September 30,
	2015					2014					2015					2014
	(in thousands)										(in thousands)
REVENUES:
Oil sales	$	50,684		66	%	$	125,430		72	%	$	177,439		68	%	$	372,925		72	%
Natural gas liquid sales	8,498			11	%	22,989			13	%	29,747			12	%	71,528			14	%
Natural gas sales	17,375			23	%	24,607			15	%	52,543			20	%	74,986			14	%
Total oil, natural gas liquids, and natural gas sales	76,557			100	%	173,026			100	%	259,729			100	%	519,439			100	%

Realized gain/(losses) on commodity derivative contracts, net	34,307			103	%	(7,265		)	(14	)%	129,105			364	%	(39,213		)	1240	%
Unrealized gains/(losses) on commodity derivative contracts, net	(939		)	(3	)%	58,243			114	%	(93,658		)	(264	)%	36,051			(1140	)%
Gains (losses) on commodity derivative contracts - net	33,368			100	%	50,978			100	%	35,447			100	%	(3,162		)	100	%

Other	438					757					1,106					1,136

Total revenues	$	110,363				$	224,761				$	296,282				$	517,413

Table of Contents

Production

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2015	2014	% Change		2015	2014	% Change
PRODUCTION DATA:
Oil (MBbls)	1,171	1,315	(11	)%	3,752	3,823	(2	)%
Natural gas liquids (MBbls)	624	659	(5	)%	1,860	1,792	4	%
Natural gas (MMcf)	7,226	6,812	6	%	21,282	18,050	18	%
Oil equivalents (MBoe)	3,000	3,109	(4	)%	9,159	8,624	6	%

Oil (Bbls/day)	12,733	14,296	(11	)%	13,744	14,003	(2	)%
Natural gas liquids (Bbls/day)	6,786	7,163	(5	)%	6,813	6,566	4	%
Natural gas (Mcf/day)	78,541	74,044	6	%	77,955	66,116	18	%
Average daily production (Boe/day)	32,609	33,799	(4	)%	33,550	31,589	6	%

Prices

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2015		2014		% Change		2015		2014		% Change
AVERAGE SALES PRICES:
Oil, without realized derivatives (per Bbl)	$	43.27	$	95.37	(55	)%	$	47.29	$	97.55	(52	)%
Oil, with realized derivatives (per Bbl)	$	66.94	$	88.70	(25	)%	$	76.13	$	88.32	(14	)%
Natural gas liquids, without realized derivatives (per Bbl)	$	13.61	$	34.89	(61	)%	$	15.99	$	39.90	(60	)%
Natural gas liquids, with realized derivatives (per Bbl)	$	13.61	$	35.12	(61	)%	$	15.99	$	40.03	(60	)%
Natural gas, without realized derivatives (per Mcf)	$	2.40	$	3.61	(34	)%	$	2.47	$	4.15	(40	)%
Natural gas, with realized derivatives (per Mcf)	$	3.32	$	3.81	(13	)%	$	3.45	$	3.92	(12	)%

Three Months Ended September 30, 2015 as Compared to the Three Months Ended September 30, 2014

Oil, natural gas liquids and natural gas sales revenues

Our oil, NGL and natural gas sales revenues decreased by $96.5 million, or 55.8%, to $76.6 million during the three months ended September 30, 2015, as compared to $173.0 million during the three months ended September 30, 2014. Lower revenue was primarily the result of decreases in oil, natural gas and NGL prices for the three months ended September 30, 2015 as compared to the three months ended September 30, 2014.

Our oil sales revenues decreased by $74.7 million, or 59.6%, to $50.7 million during the three months ended September 30, 2015, as compared to $125.4 million for the three months ended September 30, 2014. Oil volumes sold decreased 1,563 Bbls/d, or 10.9%, to 12,733 Bbls/d for the three months ended September 30, 2015, from 14,296 Bbls/d for the three months ended September 30, 2014. The decrease in oil volumes sold was primarily attributable to the Dequincy Divestiture, which impacted sales by 1,066 Bbls/d, as well as lower production from our Anadarko Basin area of 1,400 Bbls/d attributable to a decrease in drilling activity. These decreases were partially offset by increased production in the Mississippian Lime area of 903 Bbls/d.

Our NGL sales revenues decreased by $14.5 million, or 63.0%, to $8.5 million during the three months ended September 30, 2015, as compared to $23.0 million for the three months ended September 30, 2014. NGL volumes sold decreased 377 Bbls/day, or 5.3%, to 6,786 Bbls/d for the three months ended September 30, 2015, from 7,163 Bbls/d for the three months ended September 30, 2014. This decrease in NGL volumes sold was attributable to the Dequincy Divestiture, which decreased production by 300 Bbls/d, and reduced development drilling activity in our Anadarko Basin area, which resulted in lower NGL production of 461 Bbls/d. Increased production in the Mississippian Lime area of 384 Bbls/d substantially offset the NGL volume decreases in our Gulf Coast and Anadarko Basin areas.

Table of Contents

Our natural gas sales revenues decreased by $7.2 million, or 29.4%, to $17.4 million during the three months ended September 30, 2015, as compared to $24.6 million for the three months ended September 30, 2014. Natural gas volumes sold increased 4,497 Mcf/d or 6.1%, to 78,541 Mcf/d for the three months ended September 30, 2015, from 74,044 Mcf/d for the three months ended September 30, 2014. The increase in natural gas volumes sold was attributable to increased production of 7,419 Mcf/d in the Mississippian Lime area due to the development drilling program and, starting in October 2014, ethane rejection on the gas processing side, partially offset by a decrease in production of 682 Mcf/d due to the Dequincy Divestiture and reduced development drilling activity in our Anadarko Basin area, which resulted in lower natural gas production of 2,240 Mcf/d.

Gains/losses on commodity derivative contracts - net

Our mark-to-market (“MTM”) derivative positions moved from an unrealized gain of $58.2 million for the three months ended September 30, 2014 to an unrealized loss of $0.9 million for the three months ended September 30, 2015. The NYMEX WTI closing price on September 30, 2015 was $45.09 per barrel compared to a closing price of $91.16 per barrel on September 30, 2014.

Our realized gain on derivatives for the three months ended September 30, 2015 was $34.3 million, compared to a realized loss of $7.3 million for the three months ended September 30, 2014. The following table presents realized gains by type of commodity contract for the three months ended September 30, 2015:

	For the Three Months Ended September 30, 2015
	Realized Gain		Average Sales Price
	(in thousands)
Oil commodity contracts	$	27,726	$	66.94
Natural gas commodity contracts	6,581		$	3.32
Realized gains on commodity derivative contracts, net	$	34,307

Cash settlements, as presented in the table above, represent realized gains 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.

Nine Months Ended September 30, 2015 as Compared to the Nine Months Ended September 30, 2014

Oil, natural gas liquids and natural gas sales revenues

Our oil, NGL and natural gas sales revenues decreased by $259.7 million, or 50.0%, to $259.7 million during the nine months ended September 30, 2015, as compared to $519.4 million during the nine months ended September 30, 2014. Lower revenue was primarily the result of decreases in oil, natural gas and NGL prices for the nine months ended September 30, 2015 as compared to the nine months ended September 30, 2014.

Our oil sales revenues decreased by $195.5 million, or 52.4%, to $177.4 million during the nine months ended September 30, 2015, as compared to $372.9 million for the nine months ended September 30, 2014. Oil volumes sold decreased 259 Bbs/d, or 1.9%, to 13,744 Bbls/d for the nine months ended September 30, 2015, from 14,003 Bbls/d for the nine months ended September 30, 2014. This decrease in oil volumes sold was attributable to lower production due to the Dequincy Divestiture, which impacted sales by 1,565 Bbls/d, as well as lower production from our Anadarko Basin area of 1,386 Bbls/d, attributable to a decrease in drilling activity during the period and base production declines. These decreases were partially offset by increased production in the Mississippian Lime area of 2,692 Bbls/d.

Our NGL sales revenues decreased by $41.7 million, or 58.3%, to $29.8 million during the nine months ended September 30, 2015, as compared to $71.5 million for the nine months ended September 30, 2014. NGL volumes sold increased 247 Bbls/d, or 3.8%, to 6,813 Bbls/d for the nine months ended September 30, 2015, from 6,566 Bbls/d for the nine months ended September 30, 2014. This increase in NGL volumes was attributable to the increased production in the Mississippian Lime area of 1,041 Bbls/d. Increased production in our Mississippian Lime area was partially offset by a 430 Bbls/d decrease in production due to the Dequincy Divestiture and reduced development drilling activity in the Anadarko Basin, which contributed to a decrease of 364 Bbls/d.

Table of Contents

Our natural gas sales revenues decreased by $22.5 million, or 30.0%, to $52.5 million during the nine months ended September 30, 2015, as compared to $75.0 million for the nine months ended September 30, 2014. Natural gas volumes sold increased 11,839 Mcf/d or 17.9%, to 77,955 Mcf/d for the nine months ended September 30, 2015, from 66,116 Mcf/d for the nine months ended September 30, 2014. This increase in natural gas volumes sold was attributable to increased production of 15,558 Mcf/d in the Mississippian Lime area, partially offset by a decrease in production of 1,526 Mcf/d due to the Dequincy Divestiture and reduced development drilling activity in the Anadarko Basin, which contributed to a decrease of 2,193 Mcf/d.

Gains/losses on commodity derivative contracts - net

Our MTM derivative positions moved from an unrealized gain of $36.1 million for the nine months ended September 30, 2014 to an unrealized loss of $93.7 million for the nine months ended September 30, 2015. The NYMEX WTI closing price on September 30, 2015 was $45.09 per barrel compared to a closing price of $91.16 per barrel on September 30, 2014.

The realized gain on derivatives for the nine months ended September 30, 2015 was $129.1 million compared to a realized loss of $39.2 million for the nine months ended September 30, 2014. The following table presents realized gain by type of commodity contract for the nine months ended September 30, 2015:

	For the Nine Months Ended September 30, 2015
	Realized Gain		Average Sales Price
	(in thousands)
Oil commodity contracts	$	108,210	$	76.13
Natural gas commodity contracts	20,895		$	3.45
Realized gains on commodity derivative contracts, net	$	129,105

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 September 30,								Nine Months Ended September 30,
	2015		2014		2015		2014		2015		2014		2015		2014
	(in thousands)				(per Boe)				(in thousands)				(per Boe)
EXPENSES:
Lease operating and workover	$	18,803	$	16,965	$	6.27	$	5.46	$	63,823	$	56,813	$	6.97	$	6.59
Gathering and transportation	4,017		3,902		1.34		1.26		11,386		9,697		1.24		1.12
Severance and other taxes	2,660		5,780		0.89		1.86		8,729		19,059		0.95		2.21
Asset retirement accretion	382		406		0.13		0.13		1,217		1,335		0.13		0.15
Depreciation, depletion, and amortization	44,714		73,109		14.90		23.52		158,397		211,084		17.30		24.48
Impairment of oil and gas properties	486,895		—		162.30		—		1,159,951		86,471		126.65		10.03
General and administrative	6,677		9,879		2.23		3.18		29,792		34,997		3.25		4.06
Acquisition and transaction costs	5		1,283		—		0.41		256		3,894		—		0.45
Debt restructuring costs and advisory fees	—		—		—		—		36,141		—		3.97		—
Other	—		2,346		—		0.75		63		3,285		—		0.38
Total expenses	$	564,153	$	113,670	$	188.06	$	36.57	$	1,469,755	$	426,635	$	160.46	$	49.47

Table of Contents

Three Months Ended September 30, 2015 as Compared to the Three Months Ended September 30, 2014

Lease operating and workover expenses

Lease operating and workover expenses increased $1.8 million, or 10.6%, to $18.8 million for the three months ended September 30, 2015 compared to $17.0 million for the three months ended September 30, 2014. The increase in lease operating and workover expenses was primarily due to workover activity related to production optimization projects, higher environmental compliance costs and higher costs associated with the increase in producing well count period over period, partially offset by lower lease operating expenses due to the Dequincy Divestiture. Lease operating and workover expenses increased to $6.27 per Boe for the three months ended September 30, 2015, an increase of $0.81, or 14.8%, over the $5.46 per Boe for the three months ended September 30, 2014, primarily for the reasons noted above.

Gathering and transportation

Gathering and transportation expenses were $4.0 million for the three months ended September 30, 2015, as compared to $3.9 million for the three months ended September 30, 2014. The increased expenses are primarily attributable to increased natural gas production in our Mississippian Lime area, which is subject to a transportation, gathering and processing contract.

Severance and other taxes

	Three Months Ended September 30,
	2015			2014

Total oil, natural gas, and natural gas liquids sales	$	76,557		$	173,026

Severance taxes	1,531			4,321
Ad valorem and other taxes	1,129			1,459
Severance and other taxes	$	2,660		$	5,780

Severance taxes as a percentage of sales	2.0		%	2.5		%
Severance and other taxes as a percentage of sales	3.5		%	3.3		%

Severance and other taxes decreased $3.1 million, or 54.0%, to $2.7 million for the three months ended September 30, 2015 compared to $5.8 million for the three months ended September 30, 2014. Severance taxes decreased $2.8 million, or 64.6%, to $1.5 million for the three months ended September 30, 2015, as compared to $4.3 million for the three months ended September 30, 2014. Severance taxes as a percentage of sales changed from 2.5% for the three months ended September 30, 2014 to 2.0% for the corresponding 2015 period primarily due to lower realized pricing in the 2015 period and the sale of our higher tax rate Louisiana properties.

Depreciation, depletion and amortization (DD&A)

DD&A expense decreased $28.4 million, or 38.8%, to $44.7 million for the three months ended September 30, 2015 compared to $73.1 million for the three months ended September 30, 2014. The decrease in DD&A expense was driven by ceiling impairments recorded during 2015 and increases in our proved reserve volumes from prior year. Additionally, our depletion rate has decreased from approximately 2.6% for the three months ended September 30, 2014 to 2.1% for the three months ended September 30, 2015, primarily as a result of increased proved reserves volumes from the prior year. The DD&A rate for 2015 was $14.90 per Boe, compared to $23.52 per Boe for 2014 as a result of the factors discussed above.

Impairment of oil and gas properties

As a result of our full-cost ceiling test, we recorded pre-tax impairment expense related to our oil and natural gas properties for the three months ended September 30, 2015 of $486.9 million. Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of capitalized costs associated with our oil and natural gas properties in our condensed consolidated balance sheets. The impairment expense for the three months ended September 30, 2015 was due to a decrease in the PV-10 value of our proven oil and natural gas reserves as a result of continued low commodity prices.

Table of Contents

General and administrative (G&A)

Our G&A expenses decreased by $3.2 million, or 32.4%, to $6.7 million for the three months ended September 30, 2015, compared to $9.9 million for the three months ended September 30, 2014. The decrease in G&A expenses is primarily due to lower stock compensation expense of $0.8 million and lower salaries and wages of $0.4 million due to lower headcount. G&A expense for the three months ended September 30, 2015 was also reduced by the capitalization of project related overhead costs, a portion of which will be recovered from third party working interest owners in wells we operate.

Acquisition and transaction costs

Our acquisition and transaction costs were $1.3 million for the three months ended September 30, 2014, representing our expenses related to the disposition of the Pine Prairie assets in Louisiana during 2014.

Other

Other operating expenses for the three months ended September 30, 2014 were $2.3 million and represent the loss on disposal of field equipment inventory deemed no longer essential to operations. No such expenses were incurred in the three months ended September 30, 2015.

Nine Months Ended September 30, 2015 as Compared to the Nine Months Ended September 30, 2014

Lease operating and workover expenses

Lease operating and workover expenses increased $7.0 million, or 12.3%, to $63.8 million for the nine months ended September 30, 2015 compared to $56.8 million for the nine months ended September 30, 2014. The increase in lease operating and workover expenses was primarily due to costs associated with higher environmental compliance costs and production optimization projects, partially offset by lower lease operating expenses due to the Dequincy Divestiture. Lease operating and workover expenses increased to $6.97 per Boe for the nine months ended September 30, 2015, an increase of $0.38 per Boe, or 5.8%, from the $6.59 per Boe for the nine months ended September 30, 2014, primarily for the reasons noted above.

Gathering and transportation

Gathering and transportation expenses were $11.4 million for the nine months ended September 30, 2015, as compared to $9.7 million for the nine months ended September 30, 2014. The increased expenses are due to increased natural gas production in our Mississippian Lime area, which is subject to a transportation, gathering and processing contract.

Severance and other taxes

	Nine Months Ended September 30,
	2015			2014
Total oil, natural gas, and natural gas liquids sales	$	259,729		$	519,439

Severance taxes	4,542			14,483
Ad valorem and other taxes	4,187			4,576
Severance and other taxes	$	8,729		$	19,059

Severance taxes as a percentage of sales	1.8		%	2.8		%
Severance and other taxes as a percentage of sales	3.4		%	3.7		%

Severance and other taxes decreased $10.4 million, or 54.5%, to $8.7 million for the nine months ended September 30, 2015, compared to $19.1 million for the nine months ended September 30, 2014. Severance taxes decreased $9.9 million, or 68.6%, to $4.5 million for the nine months ended September 30, 2015, as compared to $14.5 million for the nine months ended September 30, 2014. Severance taxes as a percentage of sales changed from 2.8% for the nine months ended September 30, 2014 to 1.8% for the corresponding 2015 period due to lower realized pricing as well as a refund received in 2015 for production taxes paid in prior periods of $0.6 million and the sale of our higher tax rate Louisiana properties.

Table of Contents

Depreciation, depletion and amortization

DD&A expense decreased $52.7 million, or 25.0%, to $158.4 million for the nine months ended September 30, 2015 compared to $211.1 million for the nine months ended September 30, 2014. The decrease in DD&A expense was driven by ceiling impairments recorded during 2015 and increases in our proved reserves volumes from the prior year. Additionally, our depletion rate has decreased from an average of approximately 2.3% for the nine months ended September 30, 2014 to an average of 2.0% for the nine months ended September 30, 2015, primarily as a result of increased proved reserves volumes. The DD&A rate for 2015 was $17.30 per Boe, compared to $24.48 per Boe for 2014 as a result of the factors discussed above.

Impairment of oil and gas properties

We recorded pre-tax impairment expense related to our oil and natural gas properties for the nine months ended September 30, 2015 and 2014 of $1.2 billion 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 capitalized costs associated with our oil and natural gas properties in our condensed consolidated balance sheets. The impairment expense for the nine months ended September 30, 2015 was due to a decrease in the PV-10 value of our proven oil and natural gas reserves as a result of low commodity prices. The impairment expense for nine months ended September 30, 2014 was largely due to the transfer of unevaluated property costs to the full cost pool during the first quarter of 2014. During the first quarter of 2014, we transferred $21.4 million and $38.1 million related to the Mississippian Lime and Anadarko Basin areas, respectively, as we released acreage that did not present the best near term development potential.

General and administrative

Our G&A expenses decreased by $5.2 million, or 14.9%, to $29.8 million for the nine months ended September 30, 2015, compared to $35.0 million for the nine months ended September 30, 2014. The decrease is primarily attributable to lower stock compensation expense of $1.6 million and lower salaries and wages of $0.4 million due to lower headcount, as well as a decrease in consulting expenses of $1.5 million. G&A expense for the nine months ended September 30, 2015 was also reduced by the capitalization of project related overhead costs, a portion of which will be recovered from third party working interest owners in wells we operate.

Acquisition and transaction costs

Our acquisition and transaction costs were $0.3 million for the nine months ended September 30, 2015 and were related to the Dequincy Divestiture, compared to $3.9 million for the nine months ended September 30, 2014, representing our expenses related to the Pine Prairie disposition in 2014.

Debt restructuring costs and advisory fees

During the 2015 period, we engaged various advisors to assist us in analyzing options to improve our financial flexibility and provide additional long-term liquidity. For the nine months ended September 30, 2015, we incurred approximately $36.1 million in fees associated with these advisors as well as issuance costs associated with the Second Lien Notes offering and Third Lien Notes exchange.

Other

Other operating expenses for the nine months ended September 30, 2015 and 2014 were $0.1 million and $3.3 million, respectively. For 2014, these costs represent the loss on disposal of field equipment inventory deemed no longer essential to operations.

Table of Contents

Other Income (Expense)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2015			2014			2015			2014
	(in thousands)						(in thousands)
OTHER INCOME (EXPENSE)
Interest income	$	43		$	10		$	80		$	29

Interest expense	(41,453		)	(36,870		)	(124,901		)	(112,592		)
Capitalized Interest	858			2,582			2,923			10,544
Interest expense — net of amounts capitalized	(40,595		)	(34,288		)	(121,978		)	(102,048		)

Total other expense	$	(40,552	)	$	(34,278	)	$	(121,898	)	$	(102,019	)

Interest expense

Three Months Ended September 30, 2015 as Compared to the Three Months Ended September 30, 2014

Interest expense for the three months ended September 30, 2015 and 2014 was $41.5 million and $36.9 million, respectively. The increase in interest expense was primarily due to the issuance of the Second Lien Notes on May 21, 2015 and Third Lien Notes on May 21, 2015 and June 2, 2015. The Second Lien Notes bear interest at 10.0% and a portion of the proceeds were used to repay outstanding borrowings under the Credit Facility. Additionally, the Third Lien Notes bear interest at 12.0% and were exchanged for a portion of the 2020 Senior Notes and 2021 Senior Notes, which had stated interest rates of 10.75% and 9.25%, respectively. Increased interest expense was partially offset by $7.2 million in amortization of the deferred gain on forgiven debt during the three months ended September 30, 2015. For the three months ended September 30, 2015 and 2014, approximately $0.9 million and $2.6 million, respectively, in interest expense was capitalized to oil and gas properties. Capitalized interest was lower due to a decrease in the balance of our unevaluated property from September 30, 2014.

Nine Months Ended September 30, 2015 as Compared to the Nine Months Ended September 30, 2014

Interest expense for the nine months ended September 30, 2015 and 2014 was $124.9 million and $112.6 million, respectively. The increase in interest expense was primarily due to the issuance of the Second Lien Notes on May 21, 2015 and Third Lien Notes on May 21, 2015 and June 2, 2015. The Second Lien Notes bear interest at 10.0% and a portion of the proceeds were used to repay outstanding borrowings under the Credit Facility. Additionally, the Third Lien Notes bear interest at 12.0% and were exchanged for a portion of the 2020 Senior Notes and 2021 Senior Notes, which had stated interest rates of 10.75% and 9.25%, respectively. Further, approximately $4.6 million in unamortized debt costs were impaired during the nine months ended September 30, 2015 as a result of the Seventh Amendment to the Credit Facility. Increased interest expense was partially offset by $9.0 million in amortization of the deferred gain on forgiven debt during the nine months ended September 30, 2015. For the nine months ended September 30, 2015 and 2014, approximately $2.9 million and $10.5 million, respectively, in interest expense was capitalized to oil and gas properties. Capitalized interest was lower due to a decrease in the balance of our unevaluated property from September 30, 2014

Provision for Income Taxes

Three Months Ended September 30, 2015 as Compared to the Three Months Ended September 30, 2014

We had no income tax benefit or expense for the three months ended September 30, 2015, compared to an expense of $2.2 million for the three months ended September 30, 2014. Our effective tax rate for the third quarter of 2015 differs from the federal statutory rate of 35.0% due primarily to the effect of recurring permanent adjustments, state income taxes and changes in the valuation allowance.

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

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 were considered in this judgment. During the three months ended September 30, 2015, we recorded $201.9 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 $511.6 million at September 30, 2015.

Table of Contents

Nine Months Ended September 30, 2015 as Compared to the Nine Months Ended September 30, 2014

Our income tax benefit was $9.0 million and $0.1 million for the nine months ended September 30, 2015 and 2014, respectively. For the nine months ended September 30, 2015, our effective tax rate was a benefit of approximately 0.7%. Our effective tax rate for the nine months ended September 30, 2015 differs from the federal statutory rate of 35.0% due to the effect of recurring permanent adjustments, state income taxes and changes in the valuation allowance.

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

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 were considered in this judgment. During the nine months ended September 30, 2015, we recorded $507.7 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 $511.6 million at September 30, 2015.

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 September 30, 2015, our liquidity consisted of approximately $166.8 million of cash and cash equivalents and $249.9 million of available borrowing capacity (net of outstanding letters of credit) under our Credit Facility. In October 2015, we completed our semi-annual redetermination and our borrowing base was reaffirmed at $252.0 million. We currently do not have any outstanding debt on our Credit Facility.

Expenditures for exploration and development of oil and natural gas properties and payments for interest related to our outstanding debt are the primary use of our capital resources and liquidity. We expect to invest a total of between $265 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 $4.0 million and $6.0 million of interest expense during that same period.

In April 2015, we completed the Dequincy Divestiture covering the sale of our remaining producing assets in Louisiana for total consideration of approximately $42.4 million cash, inclusive of amounts placed in escrow and net of customary post-closing adjustments. The net proceeds were retained for general corporate purposes.

On May 21, 2015, we issued $625.0 million of Second Lien Notes and utilized the proceeds to repay the outstanding balance of the Credit Facility in an amount of approximately $468.2 million, with the remainder to be utilized for general corporate purposes. Further, we exchanged approximately $504.1 million of Third Lien Notes for approximately $279.8 million of 2020 Senior Notes and $350.3 million of 2021 Senior Notes, representing an exchange at 80.0% of the exchanged Unsecured Notes’ par value. Additionally, on June 2, 2015, the Company exchanged approximately $20.0 million of Third Lien Notes for approximately $26.6 million of 2020 Senior Notes and $2.0 million of 2021 Senior Notes, representing an exchange at 70.0% of the exchanged Unsecured Notes’ par value. Approximately $63.9 million of the principal amount of 2020 Senior Notes and $70.7 million of the principal amount of 2021 Senior Notes were extinguished as a result of the exchanges occurring at a percentage of the Unsecured Notes’ par value.

Additionally, we and Midstates Sub also entered into the Seventh Amendment which provided that upon completion of the offering of the Second Lien Notes and Third Lien Notes exchange, the borrowing base of the Credit Facility would be reduced to $252.0 million. The Seventh Amendment also provided additional covenant flexibility. Pursuant to the Ninth Amendment, the borrowing base was affirmed at $252.0 million for the October 2015 borrowing base redetermination.

Table of Contents

Our interest payment obligations are substantial. The table below summarizes the cash interest payments on our various debt facilities (in thousands):

	2020 Senior Notes		2021 Senior Notes		Second Lien Notes		Third Lien Notes		Total
Remainder of 2015	$	10,521	$	16,079	$	32,986	$	27,663	$	87,249
2016	31,565		32,158		62,500		53,230		179,453
2017	31,565		32,158		62,500		54,300		180,523
2018	31,565		32,158		62,500		55,391		181,614
2019	31,565		32,158		62,500		56,504		182,727
2020	31,565		32,158		31,250		83,830		178,803
2021	—		16,079		—		—		16,079

The trading level of our debt is expressed as a percentage of the par value of the outstanding debt obligation, and our various outstanding debt obligations are currently trading at significant discounts to their par value. At September 30, 2015, our 2020 Senior Notes were trading at 20.0% of par value, our 2021 Senior Notes were trading at 19.5% of par value, our Second Lien Notes were trading at 72.5% of par value and our Third Lien Notes were trading at 36.0% of par value. The trading level or market value of our debt is based upon many factors, including expectations regarding the likelihood of future repayment and the amount recoverable in the event of a default, our ability to pay interest and the risk tolerance of each debt holder. At September 30, 2015, although the principal balance of our total debt was $1.8 billion, the fair market value of our debt, based upon quoted trading prices, was approximately $0.8 billion.

While the transaction completed in May 2015 significantly improved our current liquidity, our future success in growing proved reserves and production and meeting our interest obligations will be highly dependent upon several different factors, including our ability to access additional outside sources of capital, via either the debt or equity markets, through growth in our Credit Facility or by securing other external sources of funding. Though we have no current plans to do so, we may from time to time seek to retire, purchase or exchange our outstanding debt in open market purchases, privately negotiated transactions or otherwise. Such retirements, repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Significant Sources of Capital

Reserve-based Credit Facility

We maintain a $750.0 million Credit Facility with a current borrowing base of $252.0 million supported by our Mississippian Lime and Anadarko Basin oil and gas assets. At September 30, 2015, we had no amounts drawn on the Credit Facility and had outstanding letters of credit obligations totaling $2.1 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 the Company’s borrowing base utilization, between 2.00% and 3.00% per annum.

The borrowing base under the Credit Facility is subject to semiannual redeterminations in April and October and up to one additional time per six month period following each scheduled borrowing base redetermination, as may be requested by us or the administrative agent acting on behalf of lenders holding at least two-thirds of the outstanding loans and other obligations. On October 14, 2015, we and Midstates Sub entered into the Ninth Amendment to the Credit Facility. On October 14, 2015, the Company and Midstates Sub entered into the Ninth Amendment, which, among other items, reaffirmed the borrowing base of $252.0 million.

Under the terms of the Credit Facility, we are required to repay any amount by which the principal balance of our outstanding loans and our letter of credit obligations exceeds our redetermined borrowing base or grant liens on additional property having sufficient value to eliminate such excess. We are 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.

Table of Contents

On March 24, 2015, we and Midstates Sub entered into the Sixth Amendment to the Credit Facility. The Sixth Amendment amended 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 amended the mortgage requirements under the Credit Facility to provide for an increase from 80.0% to 90.0% for the percentage of properties included in the borrowing base that are required to be subject to mortgages for the benefit of the lenders.

On May 21, 2015, we and Midstates Sub entered into the Seventh Amendment to the Credit Facility. The Seventh Amendment provided that, with the completion of the offering of the Second Lien Notes and Third Lien Notes exchange (both discussed below), our borrowing base was reduced to approximately $252.0 million. The Seventh Amendment also eliminated the required ratio of net consolidated indebtedness to EBITDA covenant and added a ratio of Total Senior Indebtedness (as defined therein) to EBITDA of not more than 1.0:1.0.

On August 5, 2015, we and Midstates Sub entered into the Eighth Amendment to the Credit Facility. The Eighth Amendment increased the limitation on certain leases and lease agreements into which we may enter into during any period of twelve consecutive calendar months of the life of such leases from $2.0 million to $3.5 million.

2020 Senior Notes

On October 1, 2012, we issued $600.0 million in aggregate principal amount of 2020 Senior Notes conducted pursuant to Rule 144A and Regulation S under the Securities Act. In October 2013, these notes were exchanged for an equal principal amount of identical registered notes. The 2020 Senior Notes rank pari passu in right of payment with the 2021 Senior Notes, the Second Lien Notes and Third Lien 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 its 100.0% ownership interest in Midstates Sub and there are 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.

Any time before October 1, 2016, we may redeem all or a part of the 2020 Senior Notes at a redemption price equal to 100.0% of the principal amount of 2020 Senior Notes redeemed plus the Applicable Premium (as defined in the 2020 Senior Notes Indenture) at the redemption date, plus any accrued and unpaid interest, if any, up to the redemption date. On or after October 1, 2016, we may redeem all or a part of the 2020 Senior Notes at varying redemption prices (expressed as percentages of principal amount) set forth in the 2020 Senior Notes Indenture plus accrued and unpaid interest, if any, on the 2020 Senior Notes redeemed, up to the redemption date. On May 21, 2015 and June 2, 2015, a total of approximately $306.4 million aggregate principal amount of 2020 Senior Notes were exchanged for Third Lien Notes, as discussed above.

Upon the occurrence of certain change of control events, as defined in the 2020 Senior Notes Indenture, each holder of the 2020 Senior Notes will have the right to require that we repurchase all or a portion of such holder’s 2020 Senior Notes in cash at a purchase price equal to 101.0% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

2021 Senior Notes

On May 31, 2013, we issued $700.0 million in aggregate principal amount of 2021 Senior Notes. In October 2013, these notes were exchanged for an equal principal amount of identical registered notes. The 2021 Senior Notes rank pari passu in right of payment with the 2020 Senior Notes, Second Lien Notes and Third Lien 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 us or limit our ability to advance loans to Midstates Sub.

Table of Contents

Prior to June 1, 2016, we may, under certain circumstances, redeem up to 35.0% of the aggregate principal amount of the 2021 Senior Notes (less the amount of 2021 Senior Notes redeemed pursuant to the preceding paragraph) with the net proceeds of any equity offerings at a redemption price of 109.25% of the principal amount of the 2021 Senior Notes redeemed, plus any accrued and unpaid interest, if any, up to the redemption date. In addition, at any time before June 1, 2016, we may redeem all or a part of the 2021 Senior Notes at a redemption price equal to 100.0% of the principal amount of the 2021 Senior Notes redeemed plus the Applicable Premium (as defined in the 2021 Senior Notes Indenture) at the redemption date, plus any accrued and unpaid interest, if any, up to, the redemption date. On or after October 1, 2016, we may redeem all or a part of the 2021 Senior Notes at varying redemption prices (expressed as percentages of principal amount) set forth in the 2021 Senior Notes Indenture plus accrued and unpaid interest, if any, on the 2021 Senior Notes redeemed, up to, the redemption date. On May 21, 2015 and June 2, 2015, a total of approximately $352.3 million aggregate principal amount of 2021 Senior Notes were exchanged for Third Lien Notes, as discussed above.

Upon the occurrence of certain change of control events, as defined in the 2021 Senior Notes Indenture, each holder of the 2021 Senior Notes will have the right to require that we repurchase all or a portion of such holder’s 2021 Senior Notes in cash at a purchase price equal to 101.0% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

Second Lien Notes

On May 21, 2015, we and Midstates Sub issued and sold $625.0 million aggregate principal amount of Second Lien Notes in a private placement conducted pursuant to Rule 144A under the Securities Act. The Second Lien Notes mature on the earlier of June 1, 2020 or 12 months after the maturity date of the Company’s Credit Facility (including any extension or refinancing of such facility). The Second Lien Notes have an interest rate of 10.0% and interest is payable semi-annually on June 1 and December 1 of each fiscal year. The Second Lien Notes are unconditionally guaranteed, jointly and severally, on a senior secured basis by each of our future restricted subsidiaries (the “Guarantors”) and will be initially secured by second-priority liens on substantially all of our and the Guarantors’ assets that secure our Credit Facility.

On May 21, 2015, in connection with the offering of Second Lien Notes, we and Midstates Sub entered into a registration rights agreement with the initial purchasers of the Second Lien Notes pursuant to which the Issuers are obligated, within 270 days after the issuance of the Second Lien Notes, to file with the Securities and Exchange Commission under the Securities Act a registration statement with respect to an offer to exchange the Second Lien Notes for substantially identical registered new notes. On October 16, 2015, we filed a prospectus pursuant to an effective registration statement and launched an exchange offer to exchange the Second Lien Notes for an equal principal amount of identical registered notes. We expect the exchange of the Second Lien Notes to be completed in November 2015.

The Second Lien Notes are our senior secured obligations and rank effectively junior to our obligations under the Credit Facility, effectively senior to our existing and future unsecured indebtedness, effectively senior to our Third Lien Notes and all future junior lien obligations, effectively junior to all existing and future secured indebtedness secured by assets not constituting collateral under the Second Lien Notes, pari passu with all of our existing and future senior debt, structurally subordinated to all existing and future indebtedness of any non-Guarantor subsidiaries and senior to any existing or future subordinated debt.

Upon the occurrence of certain change of control events, as defined in the indenture governing the Second Lien Notes, each holder of the Second Lien Notes will have the right to require that we repurchase all or a portion of such holder’s 2020 Second Lien Notes in cash at a purchase price equal to 101.0% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

Third Lien Notes

On May 21, 2015 and June 2, 2015, we issued approximately $504.1 million and $20.0 million, respectively, in aggregate principal amount of Third Lien Notes in a private placement and in exchange for an aggregate of $306.4 million of the 2020 Senior Notes and $352.3 million of the 2021 Senior Notes. The Third Lien Notes are unconditionally guaranteed, jointly and severally, on a senior secured basis by each of the Guarantors. The Third Lien Notes are initially secured by third-priority liens on substantially all of the Company’s assets that secure the Credit Facility. The Third Lien Notes have an interest rate of 12.0%, consisting of cash interest of 10.0% and paid-in-kind interest of 2.0%, per annum and mature on the earlier of June 1, 2020 or 12 months after the maturity date of our Credit Facility (including any extension or refinancing of such facility). Cash interest is payable semi-annually on June 1 and December 1 of each fiscal year. Paid-in-kind interest increases the outstanding principal balance of the Third Lien Notes on June 1 and December 1 of each fiscal year.

Table of Contents

On May 21, 2015, in connection with the issuance of the Third Lien Notes, we entered into a registration rights agreement with the initial purchasers of the Third Lien Notes pursuant to which we are obligated, within 270 days after the issuance of the Third Lien Notes, to file with the Securities and Exchange Commission under the Securities Act a registration statement with respect to an offer to exchange the Third Lien Notes for substantially identical registered new notes. On October 16, 2015, we filed a prospectus pursuant to an effective registration statement and launched an exchange offer to exchange the Third Lien Notes for an equal principal amount of identical registered notes. We expect the exchange of the Third Lien Notes to be completed in November 2015.

The Third Lien Notes are our senior secured obligations and rank effectively junior to our obligations under the Credit Facility and Second Lien Notes to the extent of the value of the collateral securing such indebtedness, effectively senior to our existing and future unsecured indebtedness to the extent of the value of the collateral securing the Third Lien Notes, effectively senior to all future junior lien obligations that rank below a third-priority basis to the extent of the value of the collateral securing the Third Lien Notes, effectively junior to all existing and future secured indebtedness secured by assets not constituting collateral under the Third Lien Notes, equal in right of payment to all of our existing and future senior debt, structurally subordinated to all existing and future indebtedness of any non-Guarantor subsidiaries and senior in right of payment to any existing or future subordinated debt.

Upon the occurrence of certain change of control events, as defined in the indenture governing the Third Lien Notes, each holder of the Third Lien Notes will have the right to require that we repurchase all or a portion of such holder’s Third Lien Notes in cash at a purchase price equal to 101.0% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

Debt Covenants

The indentures governing the 2020 Senior Notes, 2021 Senior Notes, Second Lien Notes and Third Lien Notes contain 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.

Additionally, the Credit Facility, as amended, contains, among other standard affirmative and negative covenants, financial covenants including a maximum ratio of Total Senior Indebtedness to EBITDA (as defined therein) of not more than 1.0:1.0 and a minimum current ratio (as defined therein) of not less than 1.0 to 1.0. The Credit Facility also limits our ability to make any dividends, distributions or redemptions. We were in compliance with all debt covenants at September 30, 2015.

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”.

Table of Contents

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

	For the Nine Months Ended September 30,
	2015			2014
Net cash provided by operating activities	$	235,892		$	307,580
Net cash used in investing activities	(231,408		)	(280,346		)
Net cash provided by (used in) financing activities	150,742			(34,680		)

Net change in cash	$	155,226		$	(7,446	)

Cash flows provided by operating activities

Net cash provided by operating activities decreased by $71.7 million to $235.9 million for the nine months ended September 30, 2015 as compared to $307.6 million for the nine months ended September 30, 2014. The decrease in net cash provided by operating activities was primarily the result of a decrease in our oil and gas revenues of $259.7 million due to lower commodity pricing, partially offset by increased settlements of derivatives of $168.3 million and an increase in the change in our JIB receivables from prior year of $22.2 million.

Cash flows used in investing activities

Net cash used in investing activities was $231.4 million and $280.3 million during the nine months ended September 30, 2015 and 2014, respectively. The decrease in net cash used in investing activities was primarily the result of lower capital expenditures of $159.3 million partially offset by a decrease in proceeds from the sale of oil and gas properties of $110.4 million. During the 2014 period, the Company completed the Pine Prairie disposition for approximately $147.5 million in proceeds as compared to the Dequincy Divestiture that occurred during the 2015 period for approximately $40.2 million in proceeds. The decrease in our capital expenditures is a result of lower rig count during the 2015 period due to low commodity pricing.

Cash flows provided by (used in) financing activities

Net cash provided by financing activities was $150.7 million for the nine months ended September 30, 2015, as compared to cash used in financing activities of $34.7 million for the nine months ended September 30, 2014. The increase in net cash provided by financing activities was primarily the result of the issuance of the Second Lien Notes of $625.0 million and additional borrowings from the Credit Facility of $33.0 million partially offset by the repayment of the Credit Facility of $468.2 million and debt restructuring costs of $34.4 million during the 2015 period as compared to borrowings from the Credit Facility of $99.0 million and repayments of the Credit Facility of $131.0 million during the 2014 period.

Critical Accounting Policies and Estimates

A discussion of our critical accounting policies and estimates is included in our Registration Statements on Form S-4 filed with the SEC on October 2, 2015. There have been no material changes to those policies.

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

Table of Contents

Other Items

Off-Balance Sheet Arrangements

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

Recent Accounting Pronouncements

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

In April 2015, the FASB issued ASU 2015-03. ASU 2015-03 requires debt issuance costs related to a recognized debt liability be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability. ASU 2015-03 is applied retrospectively and is effective for us beginning on January 1, 2016. We do not believe the adoption of ASU 2015-03 will have a material impact on our financial position, results of operations or cash flows.

In August 2015, the FASB issued ASU 2015-15. ASU 2015-15 addresses debt issuance costs associated with line-of-credit arrangements by allowing an entity to defer and present such debt issuance costs as an asset regardless of whether there are any outstanding borrowings under the line-of-credit arrangement. ASU 2015-15 is applied retrospectively and is effective for us beginning on January 1, 2016. We do not believe the adoption of ASU 2015-15 will have a material impact on our financial position, results of operations or cash flows.

In September 2015, the FASB issued ASU 2015-16. ASU 2015-16 simplifies measurement period adjustments associated with business combinations accounted for under FASB ASC 805, Business Combinations. ASU 2015-16 changes the accounting for measurement period adjustments by eliminating the requirement that such adjustments are made retrospectively. As a result, such measurement period adjustments will be recognized in the reporting period in which the adjustment was determined. ASU 2015-16 is applied prospectively to adjustments to provisional amounts that occur after the effective date. ASU 2015-16 is effective for us beginning on January 1, 2016. We do not believe the adoption of ASU 2015-16 will have a material impact on our financial position, results of operations or cash flows.

Table of Contents

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The disclosures are not meant to be precise indicators of expected future losses or gains, but rather indicators of reasonably possible losses or gains. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. These derivative instruments are discussed in “Item 1.—Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements — Note 4. Risk Management and Derivative Instruments.”

Commodity Price Exposure. We are exposed to market risk as the prices of oil, NGLs and natural gas fluctuate due to changes in supply and demand. To partially reduce price risk caused by these market fluctuations, we have hedged in the past and in the long-term, expect to hedge a significant portion of our future production. However, given the current low commodity price environment, we may limit the extent of our hedging program in the near-term as appropriate. We currently have no derivative contracts for any period subsequent to 2015. As such, unless new hedging contracts are put in place, cash payments from settled derivative contracts will not be received in 2016 and future periods due to the expiration of all of our hedging contracts.

We utilize derivative financial instruments to manage risks related to changes in oil and natural gas prices. As of September 30, 2015, we utilized fixed price swaps to reduce the volatility of oil and natural gas prices on a portion of our future expected oil and natural gas 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 September 30, 2015:

	Hedged	Weighted-Average
	Volume	Fixed Price
Oil (Bbls):
WTI Swaps — 2015	1,104,000	$	71.56

Natural Gas (MMBtu):
Swaps — 2015(1)	4,600,000	$	4.13

(1) Includes 1,550,000 MMBtus in natural gas swaps that priced during the period, but had not cash settled as of September 30, 2015.

	As of and for the Nine Months Ended September 30, 2015
	(in thousands)
Derivative fair value at period end - asset (included in balance sheet)	$	33,051
Realized net gain (included in the statement of operations)	$	129,105
Unrealized net loss (included in the statement of operations)	$	(93,658	)

At September 30, 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 September 30, 2015, we had no indebtedness outstanding under our Credit Facility, $293.6 million outstanding in 2020 Senior Notes, which bear interest at 10.75%, $347.7 million outstanding in 2021 Senior Notes, which bear interest at 9.25%, $625.0 million outstanding in Second Lien Notes, which bear interest at 10.0% and $524.1 million in Third Lien Notes, which bear interest at 12.0%. At September 30, 2014, the weighted average interest rate for our Credit Facility was 2.8%.

A 1.0% increase in each of the average LIBOR and federal funds rate for the three and nine months ended September 30, 2014 would have resulted in an estimated $0.9 million and $2.8 million, respectively, increase in interest expense, of which a portion may be capitalized. There were no borrowings on the Credit Facility as of September 30, 2015.

At September 30, 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.

Table of Contents

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 provide reasonable assurance that information required to be disclosed in the reports we file with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to our management, including our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. As a result of the material weakness described below, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective at a reasonable level of assurance as of September 30, 2015. Notwithstanding such material weakness, management concluded that the financial statements and other financial information included in this report present fairly, in all material respects, the financial condition, results of operations and cash flows for all periods presented.

Material Weakness in Internal Control over Financial Reporting and Remediation Efforts

During the second quarter of 2015, we identified a material weakness in our internal control over financial reporting related to the review of our Consolidated Statements of Cash Flows. This material weakness resulted from errors in our restated amounts within our Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012, which were reported in Item 5. Other Information, of our Quarterly Report on Form 10-Q for the interim period ended March 31, 2015.

Although we continue to believe that these errors are immaterial, we previously revised the restated amounts for the years ended December 31, 2013 and 2012 in Item 5. Other Information, of our Quarterly Report on Form 10-Q for the interim period ended June 30, 2015. There continues to be 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. If not remediated, this material weakness could result in a material misstatement of the Consolidated Statements of Cash Flows.

Changes in Internal Control over Financial Reporting

Except for the remediation efforts described below, there were no changes in our internal control over financial reporting during the quarter ended September 30, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Upon identification of the errors in Item 5. Other Information, of our Quarterly Report on Form 10-Q for the interim period ended March 31, 2015, we began remediation efforts to improve our internal controls. We have implemented additional review procedures targeted to ensuring the completeness and accuracy of our Consolidated Statements of Cash Flows. Our remediation efforts are still in progress. The implementation of these changes to our control environment is ongoing, and our remediation efforts have not yet been subject to management’s testing.

Table of Contents

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

From time to time, we are party to various legal proceedings arising in the ordinary course of business. Although we cannot predict the outcomes of any such legal proceedings, our management believes that the resolution of currently pending legal actions will not have a material adverse effect on our business, results of operations and financial condition. See Part I, Item 1, Note 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 adverse effect on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.

Except as set forth below and in Part II, Item 1A of our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2015 and June 30, 2015, which are incorporated by reference herein, there have been no material changes to the risks described in Part I, Item 1A of our Registration Statements on Form S-4 filed with the SEC on October 2, 2015.

We have received several notices of non-compliance with 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. 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; however on July 16, 2015, we received another notification from the NYSE that the price of our common stock had fallen below the NYSE’s continued listing standard. On August 3, we announced a 1-for-10 reverse stock split of our common stock to cure the deficiency, and we subsequently regained compliance within the requisite time period. On August 13, 2015, we received another notification from the NYSE that our market capitalization and last reported stockholders’ equity had fallen below the NYSE’s continued listing standards. The NYSE requires that a listed company’s average total market capitalization not be less than $50.0 million for a period of over 30 consecutive trading days and that its last reported stockholder equity not be less than $50.0 million. In accordance with NYSE procedures, on September 25, 2015, we provided the NYSE a proposed business plan demonstrating how we intend to regain compliance with the NYSE’s continued listing standards within 18 months. In the event the NYSE does not accept the business plan or if we are unable to comply with our proposed plan, we will be subject to delisting procedures and suspension by the NYSE.

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.

Table of Contents

Studies by both state or federal agencies suggesting a correlation between earthquakes and oil and natural gas activities could result in increased regulatory and operational burdens.

In our Annual Report on Form 10-K for the year ended December 31, 2014, we stated that some concerns have been raised about the potential for earthquakes to occur from the use of underground injection control wells. On April 21, 2015, the Oklahoma Geologic Survey (“OGS”) issued a document entitled “Statement of Oklahoma Seismicity,” in which the agency states “[t]he OGS considers it very likely that the majority of recent earthquakes, particularly those in central and north-central Oklahoma, are triggered by the injection of produced water in disposal wells.” This development may result in additional levels of regulation, or increased complexity with respect to existing regulations, that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to inject produced water into disposal wells, and may increase our costs of compliance and conducting business.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

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

Table of Contents

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: November 5, 2015	/s/ Frederic F. Brace
	Frederic F. Brace
	Interim President and Chief Executive Officer
	(Principal Executive Officer)

Dated: November 5, 2015	/s/ Nelson M. Haight
	Nelson M. Haight
	Executive Vice President and Chief Financial Officer
	(Principal Financial and Accounting Officer)

Table of Contents

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).

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

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

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

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

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

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

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

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

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

Table of Contents

10.1		Eighth Amendment to Second Amended and Restated Credit Agreement, dated as of August 5, 2015, among Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC, as borrower, SunTrust Bank, N.A., as administrative agent, and the lenders and other parties thereto (filed as Exhibit 10.1to the Company’s Current Report on Form 8-K filed on August 10, 2015, and incorporated herein by reference).

10.2		Ninth Amendment to Second Amended and Restated Credit Agreement, dated as of October 14, 2015, among Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC, as borrower, SunTrust Bank, N.A., as administrative agent, and the lenders and other parties thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 20, 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.

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