Edgar Filing: Midstates Petroleum Company, Inc.

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, 2014

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.)

4400 Post Oak Parkway, Suite 2600
Houston, Texas		77027
(Address of principal executive offices)		(Zip Code)

(713) 595-9400

(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 4, 2014 is shown below:

Class		Number of shares outstanding
Common stock, $0.01 par value		70,457,656

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MIDSTATES PETROLEUM COMPANY, INC.

QUARTERLY REPORT ON

FORM 10-Q

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2014

TABLE OF CONTENTS

	Page

Glossary of Oil and Natural Gas Terms	3

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements	4
Condensed Consolidated Balance Sheets at September 30, 2014 and December 31, 2013 (unaudited)	4
Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2014 and 2013 (unaudited)	5
Condensed Consolidated Statements of Changes in Stockholders’ Equity for the Nine Months Ended September 30, 2014 and 2013 (unaudited)	6
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2014 and 2013 (unaudited)	7

Notes to Unaudited Condensed Consolidated Financial Statements	8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	22

Item 3. Quantitative and Qualitative Disclosures About Market Risk	38

Item 4. Controls and Procedures	40

PART II - OTHER INFORMATION

Item 1. Legal Proceedings	42

Item 1A. Risk Factors	42

Item 6. Exhibits	42

SIGNATURES	43

EXHIBIT INDEX	44

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GLOSSARY OF OIL AND NATURAL GAS TERMS

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

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

Boe/day: Barrels of oil equivalent per day.

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

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

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

Mcf: One thousand cubic feet of natural gas.

MMBoe: One million barrels of oil equivalent.

MMBtu: One million British thermal units.

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

NYMEX: The New York Mercantile Exchange.

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

Reasonable certainty: A high degree of confidence.

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

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

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

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

Wellbore: The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.

Working interest: The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on a cash, penalty, or carried basis.

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PART I - FINANCIAL INFORMATION

MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands, except share amounts)

	September 30, 2014			December 31, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	25,717		$	33,163
Accounts receivable:
Oil and gas sales	97,304			102,483
Joint interest billing	31,138			42,631
Other	11,120			1,090
Commodity derivative contracts	7,333			700
Deferred income taxes	983			11,837
Other current assets	1,256			693
Total current assets	174,851			192,597

PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of full-cost accounting	3,319,257			3,060,661
Other property and equipment	12,805			11,113
Less accumulated depreciation, depletion, amortization and impairment	(1,274,168		)	(976,880		)
Net property and equipment	2,057,894			2,094,894

OTHER ASSETS:
Commodity derivative contracts	436			19
Other noncurrent assets	46,788			54,597
Total other assets	47,224			54,616

TOTAL	$	2,279,969		$	2,342,107

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	13,511		$	21,493
Accrued liabilities	233,147			204,381
Commodity derivative contracts	2,429			27,880
Total current liabilities	249,087			253,754

LONG-TERM LIABILITIES:
Asset retirement obligations	20,935			26,308
Commodity derivative contracts	101			3,651
Long-term debt	1,669,150			1,701,150
Deferred income taxes	4,341			15,291
Other long-term liabilities	2,078			1,954
Total long-term liabilities	1,696,605			1,748,354

COMMITMENTS AND CONTINGENCIES (Note 13)

STOCKHOLDERS’ EQUITY:
Preferred stock, $0.01 par value, 49,675,000 shares authorized; no shares issued or outstanding	—			—
Series A mandatorily convertible preferred stock, $0.01 par value, $380,204 and $358,550 liquidation value at September 30, 2014 and December 31, 2013, respectively; 8% cumulative dividends; 325,000 shares issued and outstanding	3			3
Common stock, $0.01 par value, 300,000,000 shares authorized; 70,606,079 shares issued and 70,169,242 shares outstanding at September 30, 2014 and 68,925,745 shares issued and 68,807,043 shares outstanding at December 31, 2013	705			689
Treasury stock	(2,386		)	(664		)
Additional paid-in-capital	878,176			871,047
Retained deficit	(542,221		)	(531,076		)
Total stockholders’ equity	334,277			339,999

TOTAL	$	2,279,969		$	2,342,107

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

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MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share amounts)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2014			2013			2014			2013
REVENUES:
Oil sales	$	125,430		$	119,049		$	372,925		$	268,903
Natural gas liquid sales	22,989			18,939			71,528			39,656
Natural gas sales	24,607			18,775			74,986			42,034
Gains (losses) on commodity derivative contracts - net	50,978			(45,296		)	(3,162		)	(42,999		)
Other	757			38			1,136			941

Total revenues	224,761			111,505			517,413			308,535

EXPENSES:
Lease operating and workover	16,965			21,784			56,813			53,230
Gathering and transportation	3,902			2,583			9,697			2,583
Severance and other taxes	5,780			8,080			19,059			20,614
Asset retirement accretion	406			421			1,335			988
Depreciation, depletion, and amortization	73,109			74,789			211,084			169,595
Impairment in carrying value of oil and gas properties	—			—			86,471			—
General and administrative	9,879			13,911			34,997			40,209
Acquisition and transaction costs	1,283			194			3,894			11,686
Other	2,346			614			3,285			614

Total expenses	113,670			122,376			426,635			299,519

OPERATING INCOME (LOSS)	111,091			(10,871		)	90,778			9,016

OTHER INCOME (EXPENSE):
Interest income	10			7			29			17
Interest expense — net of amounts capitalized	(34,288		)	(25,950		)	(102,048		)	(53,438		)

Total other income (expense)	(34,278		)	(25,943		)	(102,019		)	(53,421		)

INCOME (LOSS) BEFORE TAXES	76,813			(36,814		)	(11,241		)	(44,405		)

Income tax (expense) benefit	(2,216		)	13,208			96			16,188

NET INCOME (LOSS)	$	74,597		$	(23,606	)	$	(11,145	)	$	(28,217	)

Preferred stock dividend	(1,908		)	(2,569		)	(9,334		)	(9,254		)
Participating securities - Series A Preferred Stock	(23,973		)	—			—			—
Participating securities - Non-vested Restricted Stock	(2,524		)	—			—			—


NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	46,192		$	(26,175	)	$	(20,479	)	$	(37,471	)

Basic and diluted net income (loss) per share attributable to common shareholders	$	0.69		$	(0.40	)	$	(0.31	)	$	(0.57	)
Basic and diluted weighted average number of common shares outstanding	66,598			65,821			66,340			65,740

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

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MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

(In thousands)

	Series A Preferred Stock		Common Stock		Treasury Stock			Additional Paid-in- Capital		Retained Deficit/ Accumulated Loss			Total Stockholders’ Equity
Balance as of December 31, 2013	$	3	$	689	$	(664	)	$	871,047	$	(531,076	)	$	339,999
Share-based compensation	—		16		—			7,129		—			7,145
Acquisition of treasury stock	—		—		(1,722		)	—		—			(1,722		)
Net loss	—		—		—			—		(11,145		)	(11,145		)
Balance as of September 30, 2014	$	3	$	705	$	(2,386	)	$	878,176	$	(542,221	)	$	334,277

	Series A Preferred Stock		Common Stock		Treasury Stock			Additional Paid-in- Capital		Retained Deficit/ Accumulated Loss			Total Stockholders’ Equity
Balance as of December 31, 2012	$	3	$	666	$	—		$	863,891	$	(187,091	)	$	677,469
Share-based compensation	—		20		—			6,048		—			6,068
Acquisition of treasury stock	—		—		(605		)	—		—			(605		)
Net loss	—		—		—			—		(28,217		)	(28,217		)
Balance as of September 30, 2013	$	3	$	686	$	(605	)	$	869,939	$	(215,308	)	$	654,715

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

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MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Nine Months Ended September 30,
	2014			2013

CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(11,145	)	$	(28,217	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Losses on commodity derivative contracts — net	3,162			42,999
Net cash paid for commodity derivative contracts not designated as hedging instruments	(39,213		)	(16,002		)
Asset retirement accretion	1,335			988
Depreciation, depletion, and amortization	211,084			169,595
Impairment in carrying value of oil and gas properties	86,471			—
Share-based compensation, net of amounts capitalized to oil and gas properties	5,358			4,921
Deferred income taxes	(96		)	(16,188		)
Amortization of deferred financing costs	6,018			4,156
Change in operating assets and liabilities:
Accounts receivable — oil and gas sales	5,179			(52,598		)
Accounts receivable — JIB and other	10,551			(13,544		)
Other current and noncurrent assets	1,815			(2,622		)
Accounts payable	503			(3,027		)
Accrued liabilities	30,921			89,666
Other	124			(186		)

Net cash provided by operating activities	$	312,067		$	179,941

CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment	(435,363		)	(437,521		)
Investment in acquired property	—			(621,748		)
Proceeds from the sale of oil and gas properties	150,530			—

Net cash used in investing activities	$	(284,833	)	$	(1,059,269	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings	99,000			946,450
Repayment of long-term borrowings	(131,000		)	(34,300		)
Deferred financing costs	(958		)	(26,142		)
Acquisition of treasury stock	(1,722		)	(605		)

Net cash (used in) provided by financing activities	$	(34,680	)	$	885,403

NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(7,446		)	6,075

Cash and cash equivalents, beginning of period	$	33,163		$	18,878

Cash and cash equivalents, end of period	$	25,717		$	24,953

SUPPLEMENTAL INFORMATION:
Non-cash transactions — investments in property and equipment accrued - not paid	$	98,000		$	100,500
Cash paid for interest, net of capitalized interest of $10.5 million and $24.6 million, respectively	63,538			11,671

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

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

1. Organization and Business

Midstates Petroleum Company, Inc., through its wholly owned subsidiary Midstates Petroleum Company LLC, engages in the business of drilling for, and production of, oil, natural gas liquids (“NGL”) 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”). Pursuant to the terms of a corporate reorganization that was completed in connection with the closing of Midstates Petroleum Company, Inc.’s initial public offering on April 25, 2012, all of the interests in Midstates Petroleum Holdings LLC were exchanged for newly issued common shares of Midstates Petroleum Company, Inc., and as a result, Midstates Petroleum Company LLC became a wholly owned subsidiary of Midstates Petroleum Company, Inc. and Midstates Petroleum Holdings LLC ceased to exist as a separate entity. The terms “Company,” “we,” “us,” “our,” and similar terms when used in the present tense, prospectively or for historical periods since April 25, 2012, refer to Midstates Petroleum Company, Inc. and its subsidiary, and for historical periods prior to April 25, 2012, refer to Midstates Petroleum Holdings LLC and its subsidiary, unless the context indicates otherwise. The term “Holdings LLC” refers solely to Midstates Petroleum Holdings LLC prior to the corporate reorganization.

On May 31, 2013, the Company closed on the acquisition of producing properties and undeveloped acreage in the Anadarko Basin in Texas and Oklahoma from Panther Energy Company, LLC and its partners for approximately $618 million in cash (the “Anadarko Basin Acquisition”), before customary post-closing adjustments. The Company funded the purchase price with a portion of the net proceeds from the private placement of $700 million in aggregate principal amount of 9.25% senior unsecured notes due 2021, which also closed on May 31, 2013 (“2021 Senior Notes”).

On March 5, 2014, the Company executed a Purchase and Sale Agreement (“PSA”) to sell all of its ownership interest in developed and undeveloped acreage in the Pine Prairie field area of Evangeline Parish, Louisiana to a private buyer for a purchase price of $170 million in cash, subject to standard post-closing adjustments (the “Pine Prairie Disposition”). The PSA had an effective date of November 1, 2013. Acreage subject to the transaction did not include acreage and production in the western part of Louisiana in Beauregard or Calcasieu Parishes or other undeveloped acreage held outside the Pine Prairie field. The sale closed on May 1, 2014.

The Company has oil and gas operations and properties in Oklahoma, Texas and Louisiana. At September 30, 2014, the Company operated oil and natural gas properties as one reportable segment engaged in the exploration, development and production of oil, natural gas liquids and natural gas. The Company’s management evaluated performance based on one reportable segment as there were not significantly different economic or operational environments within its oil and natural gas properties.

2. 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, 2013 included in the Company’s Annual Report on Form 10-K as filed with the SEC on March 24, 2014.

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.

Recent Accounting Pronouncements

The Company reviewed recently issued accounting pronouncements that became effective during the nine months ended September 30, 2014, and determined that none would have a material impact on the Company’s condensed consolidated financial statements, with the exception of ASU 2014-09, “Revenue from Contracts with Customers ” and ASU 2014-15, “Presentation of Financial Statements - Going Concern,” (both effective for annual reporting periods beginning after December 15, 2016), which the Company is still evaluating.

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3. 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, 2014 and December 31, 2013, all of the Company’s commodity derivative contracts were with seven bank counterparties and were classified as Level 2 in the fair value input hierarchy.

Derivative instruments listed below are presented gross and include collars and 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 4 for additional information on the Company’s derivative instruments and balance sheet presentation.

	Fair Value Measurements at September 30, 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	$	—	$	6,557	$	—	$	6,557
Commodity derivative gas swaps	—		2,421		—		2,421
Commodity derivative oil collars	—		30		—		30
Commodity derivative gas collars	—		15		—		15
Commodity derivative differential swaps	—		221		—		221
Total assets	$	—	$	9,244	$	—	$	9,244

Liabilities:
Commodity derivative oil swaps	$	—	$	3,924	$	—	$	3,924
Commodity derivative gas swaps	—		75		—		75
Commodity derivative gas collars	—		6		—		6
Total liabilities	$	—	$	4,005	$	—	$	4,005

	Fair Value Measurements at December 31, 2013
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in thousands)
Assets:
Commodity derivative NGL swaps	$	—	$	469	$	—	$	469
Commodity derivative gas swaps	—		488		—		488
Commodity derivative oil collars	—		64		—		64
Commodity derivative gas collars	—		751		—		751
Commodity derivative differential swaps	—		806		—		806
Total assets	$	—	$	2,578	$	—	$	2,578

Liabilities:
Commodity derivative oil swaps	$	—	$	32,209	$	—	$	32,209
Commodity derivative NGL swaps	—		74		—		74
Commodity derivative gas swaps	—		809		—		809
Commodity derivative oil collars	—		272		—		272
Commodity derivative gas collars	—		26		—		26
Total liabilities	$	—	$	33,390	$	—	$	33,390

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4. 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 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.

Inherent in the Company’s portfolio of commodity derivative contracts are certain business risks, including market risk and credit risk. Market risk is the risk that the price of the commodity will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract. The Company does not require collateral from its counterparties but does attempt to minimize its credit risk associated with derivative instruments by entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. In addition, to mitigate its risk of loss due to default, the Company has entered into agreements with its counterparties on its derivative instruments that allow the Company to offset its asset position with its liability position in the event of default by the counterparty. Due to the netting arrangements, had the Company’s counterparties failed to perform under existing commodity derivative contracts, the maximum loss at September 30, 2014 would have been approximately $7.8 million.

Commodity Derivative Contracts

As of September 30, 2014, the Company had the following open commodity derivative contract positions:

	Hedged Volume	Weighted-Average Fixed Price

Oil (Bbls):
WTI Swaps — 2014	1,097,000				$	89.04
WTI Swaps — 2015	2,908,000				$	89.42

WTI Collars — 2014	40,200	$	86.49	-	$	97.71

WTI to LLS Basis Differential Swaps — 2014 (1)	91,500				$	5.35

Natural Gas (MMBtu):
Swaps — 2014 (2)	4,508,000				$	4.17
Swaps — 2015	18,250,000				$	4.13

Collars — 2014	194,001	$	3.39	-	$	4.57

(1) The Company enters into swap arrangements intended to fix the differential between the Louisiana Light Sweet (“LLS”) pricing and the West Texas Intermediate (“NYMEX WTI”) pricing.

(2) Includes 1,519,000 MMBtus in natural gas swaps that priced during the period, but had not cash settled as of September 30, 2014.

Balance Sheet Presentation

The following table summarizes the gross fair values of derivative instruments by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s unaudited condensed consolidated balance sheets at September 30, 2014 and December 31, 2013, respectively (in thousands):

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Type	Balance Sheet Location (1)	September 30, 2014			December 31, 2013
Oil Swaps	Derivative financial instruments — Current Assets	$	6,557		$	—
Oil Swaps	Derivative financial instruments — Current Liabilities	(3,823		)	(28,871		)
Oil Swaps	Derivative financial instruments — Non-Current Liabilities	(101		)	(3,338		)
NGL Swaps	Derivative financial instruments — Current Assets	—			469
NGL Swaps	Derivative financial instruments — Current Liabilities	—			(74		)
Gas Swaps	Derivative financial instruments — Current Assets	1,985			469
Gas Swaps	Derivative financial instruments — Non-Current Assets	436			19
Gas Swaps	Derivative financial instruments — Current Liabilities	(75		)	(496		)
Gas Swaps	Derivative financial instruments — Non-Current Liabilities	—			(313		)
Oil Collars	Derivative financial instruments — Current Assets	30			64
Oil Collars	Derivative financial instruments — Current Liabilities	—			(272		)
Gas Collars	Derivative financial instruments — Current Assets	15			751
Gas Collars	Derivative financial instruments — Current Liabilities	(6		)	(26		)
Basis Differential Swaps	Derivative financial instruments — Current Assets	221			806
Total derivative fair value at period end		$	5,239		$	(30,812	)

(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, 2014 and December 31, 2013, respectively (in thousands):

		September 30, 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	$	8,808	$	1,475	$	7,333
Commodity contracts	Derivative financial instruments - noncurrent	436		—		436
		$	9,244	$	1,475	$	7,769
Derivative liabilities:
Commodity contracts	Derivative financial instruments - current	$	3,904	$	1,475	$	2,429
Commodity contracts	Derivative financial instruments - noncurrent	101		—		101
		$	4,005	$	1,475	$	2,530

		December 31, 2013
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	$	2,559	$	1,859	$	700
Commodity contracts	Derivative financial instruments - noncurrent	19		—		19
		$	2,578	$	1,859	$	719
Derivative liabilities:
Commodity contracts	Derivative financial instruments - current	$	29,739	$	1,859	$	27,880
Commodity contracts	Derivative financial instruments - noncurrent	3,651		—		3,651
		$	33,390	$	1,859	$	31,531

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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 realized net losses 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,
	2014			2013			2014			2013
	(in thousands)						(in thousands)
Realized net losses	$	(7,265	)	$	(9,927	)	$	(39,213	)	$	(16,002	)
Unrealized net gains (losses)	58,243			(35,369		)	36,051			(26,997		)
Gains (losses) on commodity derivative contracts - net	$	50,978		$	(45,296	)	$	(3,162	)	$	(42,999	)

5. Property and Equipment

	September 30, 2014			December 31, 2013
	(in thousands)
Oil and gas properties, on the basis of full-cost accounting:
Proved properties	$	3,194,225		$	2,817,062
Unevaluated properties	125,032			243,599
Other property and equipment	12,805			11,113
Less accumulated depreciation, depletion, amortization and impairment	(1,274,168		)	(976,880		)
Net property and equipment	$	2,057,894		$	2,094,894

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, 2014 and 2013, the Company capitalized the following amounts (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013

Internal costs capitalized to oil and gas properties (1)	$	2,771	$	2,822	$	9,159	$	6,218

(1) Inclusive of $0.6 million and $0.5 million of qualifying share-based compensation expense for the three months ended September 30, 2014 and 2013, respectively. For the nine months ended September 30, 2014 and 2013, inclusive of $1.8 million and $1.1 million of qualifying share-based compensation expense, respectively.

The Company accounts for its oil and gas properties under the full cost method. Under the full cost method, proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion of the Company’s reserve quantities are sold such that it results in a significant alteration of the relationship between capitalized costs and remaining proved reserves, in which case a gain or loss is generally recognized in income.

The Company performs a 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 unproved and unevaluated properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanying condensed consolidated statements of operations.

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At September 30, 2014 and September 30, 2013 capitalized costs did not exceed the ceiling and an impairment to oil and gas properties was not required; however, the Company’s ceiling test calculation at September 30, 2014 indicated that the Company’s capitalized costs were within 5% of the ceiling. An impairment of $83.5 million (after tax) to oil and gas properties was recorded during the nine months ended September 30, 2014 as a result of the capitalized costs exceeding the ceiling at March 31, 2014.

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 and amortization (“DD&A”), 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, 2014 and 2013, respectively:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2014		2013		2014		2013		2014		2013		2014		2013
	(in thousands)				(per Boe)				(in thousands)				(per Boe)
Depletion expense	$	72,337	$	74,345	$	23.27	$	28.39	$	208,864	$	168,190	$	24.22	$	28.68
Depreciation on other property	772		444		0.25		0.17		2,220		1,405		0.26		0.23
Depreciation, depletion, and amortization	$	73,109	$	74,789	$	23.52	$	28.56	$	211,084	$	169,595	$	24.48	$	28.91

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 $125.0 million at September 30, 2014 compared to $243.6 million at December 31, 2013, decreasing primarily due to property transfers related to the Anadarko Basin ($63.2 million) and Mississippian Lime ($51.5 million) areas.

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.

Anadarko Basin Acquisition—May 2013

On May 31, 2013, the Company closed on the acquisition of producing properties and undeveloped acreage in the Anadarko Basin in Texas and Oklahoma from Panther Energy Company, LLC and its partners for approximately $618 million in cash (before customary post-closing adjustments). The Company funded the purchase price of the Anadarko Basin Acquisition with a portion of the net proceeds from the private placement of $700 million in aggregate principal amount of 9.25% senior unsecured notes due 2021, which also closed on May 31, 2013. The fair value of, and the allocation to, the assets acquired and liabilities assumed in the Anadarko Basin Acquisition has been finalized and is shown in the following table (in thousands):

	Anadarko Basin Acquisition
Oil and gas properties
Proved	$	417,750
Unevaluated	207,606
Total assets acquired	$	625,356

Asset retirement obligations	6,296
Total liabilities assumed	$	6,296

Net assets acquired	$	619,060

The finalized balances in the table above include immaterial changes to the amounts originally allocated to oil and gas properties. These changes were required to reflect the final consideration paid after adjustment for certain post-closing purchase price amounts.

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Actual and Pro Forma Information

Revenues attributable to the Anadarko Basin Acquisition included in the Company’s unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2014 were $45.8 million and $148.2 million, respectively. Revenues attributable to the Anadarko Basin Acquisition included in the Company’s unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2013 was $45.6 million and $59.8 million, respectively.

The following table presents unaudited pro forma information for the Company as if the Anadarko Basin Acquisition had been completed on January 1, 2013 (in thousands, other than per share amounts):

	For the Nine Months Ended September 30, 2013

Revenues and other	$	378,591
Net loss	(21,401		)
Preferred stock dividends	(9,254		)
Loss attributable to common shareholders	$	(30,655	)
Net loss per common share - basic and diluted	$	(0.47	)

The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Anadarko Basin Acquisition and are factually supportable. The unaudited pro forma consolidated results are not necessarily indicative of what the Company’s consolidated results of operations actually would have been had the acquisition been completed on January 1, 2013. In addition, the unaudited pro forma consolidated results do not purport to project the future results of operations for the combined Company.

Pine Prairie Disposition

On March 5, 2014, the Company executed a PSA to sell all of its ownership interest in developed and undeveloped acreage in the Pine Prairie field area of Evangeline Parish, Louisiana to a private buyer for a purchase price of $170 million in cash, subject to standard post-closing adjustments. The PSA had an effective date of November 1, 2013. Acreage subject to the transaction did not include acreage and production in the western part of Louisiana in Beauregard and Calcasieu Parishes or other undeveloped acreage held outside the Pine Prairie field. On May 1, 2014, the Company closed on the sale for estimated net proceeds of $147.5 million, of which $131.0 million was used to reduce amounts outstanding under its revolving credit facility, with the remainder retained for transaction expenses and working capital purposes. The Company reduced the full cost pool subject to amortization by the amount of the net proceeds received and other standard post-closing adjustments. Accordingly, no gain or loss was recognized.

Exploration Agreement with PetroQuest

On June 25, 2014, the Company entered into an exploration agreement with PetroQuest Energy LLC (“PetroQuest”) with an effective date of May 1, 2014, in which the Company conveyed to PetroQuest an undivided 50% of its right, title and interest in and to the acreage and other interests in the Fleetwood prospect area in Louisiana.

With the execution of the agreement, PetroQuest paid $3.0 million in cash consideration and, on or before January 5, 2015, PetroQuest will pay additional cash of $7.0 million. As further consideration, PetroQuest granted a credit to the Company (or will pay on its behalf) of an additional non-interest bearing total sum of $14.0 million, to be credited or paid against the Company’s share of costs or expenses incurred to develop the prospect area, including but not limited to, all mineral lease acquisition or maintenance costs and all drilling, completion, equipping and facility costs. For any amounts not fully paid on or before December 31, 2015, the Company can elect to take the remaining portion in cash.

At September 30, 2014, the Company had a receivable of $7.0 million included in “Other accounts receivable”, which represented the additional cash the Company expects to receive on or before January 5, 2015 under the exploration agreement with PetroQuest.

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6. Other Noncurrent Assets

At September 30, 2014 and December 31, 2013 other noncurrent assets consisted of the following:

	September 30, 2014		December 31, 2013
	(in thousands)
Deferred financing costs	$	39,647	$	44,706
Field inventory	6,930		9,682
Other	211		209
Other noncurrent assets	$	46,788	$	54,597

During the nine months ended September 30, 2014, the Company has recorded approximately $5.2 million in adjustments to field inventory, either as a result of physical inventory counts, disposals, or market adjustments; this is offset by additional inventory added during the period of approximately $2.4 million. For the three and nine months ended September 30, 2014, the Company recorded $2.3 million and $3.3 million, respectively, of losses on sale of, or market value adjustments to, inventory. For the three and nine months ended September 30, 2013, the Company recorded $0.6 million of losses on sale of, or market value adjustments to, inventory.

7. Accrued Liabilities

At September 30, 2014 and December 31, 2013 accrued liabilities consisted of the following:

	September 30, 2014		December 31, 2013
	(in thousands)
Accrued oil and gas capital expenditures	$	86,809	$	87,202
Accrued revenue and royalty distributions	62,692		64,370
Accrued lease operating and workover expense	6,846		8,279
Accrued interest	53,833		21,341
Accrued taxes	8,113		4,386
Other	14,854		18,803
Accrued liabilities	$	233,147	$	204,381

8. Asset Retirement Obligations

Asset Retirement Obligations (“AROs”) represent the future abandonment costs of tangible assets, such as wells, service assets and other facilities. The fair value of the ARO at inception is capitalized as part of the carrying amount of the related long-lived assets. AROs approximated $20.9 million and $26.3 million as of September 30, 2014 and December 31, 2013, respectively, and the liability has been accreted to its present value as of September 30, 2014 and December 31, 2013.

The Company evaluated its wells and determined a range of abandonment dates through 2071. At September 30, 2014, all asset retirement obligations represent long-term liabilities and are classified as such.

The following table reflects the changes in the Company’s AROs for the nine months ended September 30, 2014 (in thousands):

Asset retirement obligations at January 1, 2014	$	26,308
Liabilities incurred	991
Revisions	—
Liabilities settled	(47		)
Liabilities eliminated through asset sale (1)	(7,652		)
Current period accretion expense	1,335
Asset retirement obligations at September 30, 2014	$	20,935

(1) As a result of the Pine Prairie Disposition, AROs were reduced by approximately $7.7 million during the nine months ended September 30, 2014. See discussion of the Pine Prairie Disposition in Note 5.

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9. Long-Term Debt

The Company’s long-term debt as of September 30, 2014 and December 31, 2013 is as follows:

	At September 30, 2014		At December 31, 2013
	(in thousands)
Revolving credit facility, due 2018	$	369,150	$	401,150
Senior notes, due 2020	600,000		600,000
Senior notes, due 2021	700,000		700,000
Long-term debt	$	1,669,150	$	1,701,150

Reserve-based Credit Facility

The Company’s credit facility consists of a $750 million senior revolving credit facility (the “Credit Facility”) with a borrowing base supported by the Company’s Mississippian Lime and Anadarko Basin oil and gas assets. On September 30, 2014, the Company entered into an Assignment and Borrowing Base Increase Agreement that increased the borrowing base from $475 million to $525 million. At September 30, 2014, outstanding letters of credit obligations under the revolving credit facility total $1.4 million.

The Credit Facility matures on May 31, 2018 and borrowings thereunder are secured by substantially all of the Company’s oil and natural gas properties and bear interest at LIBOR plus an applicable margin, depending upon the Company’s borrowing base utilization, between 2.00% and 3.00% per annum. At September 30, 2014 and 2013, the weighted average interest rate was 2.8% and 2.5%, respectively.

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

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

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

The Credit Facility contains, among other standard affirmative and negative covenants, financial covenants including a maximum ratio of debt to EBITDA (i.e. leverage ratio) and a minimum current ratio (as defined therein) of not less than 1.0 to 1.0. The Company is required to maintain a leverage ratio of not more than 4.75 to 1.00 for the quarters ending September 30, 2014 and December 31, 2014, and 4.00 to 1.00 for each quarter thereafter.

As of September 30, 2014, the Company was in compliance with the minimum current ratio and the ratio of debt to EBITDA covenants as set forth in the Credit Facility. The Company’s current ratio at September 30, 2014 was 1.3 to 1.0. At September 30, 2014, the Company’s ratio of debt to EBITDA was 3.6 to 1.0.

Based upon the recent amendments to the Credit Facility, the Company believes its carrying amount at September 30, 2014 approximates its fair value (Level 2) due to the variable nature of the applicable interest rate and current financing terms available to the Company.

2020 Senior Notes

On October 1, 2012, the Company issued $600 million in aggregate principal amount of 10.75% senior notes due 2020 (the “2020 Senior Notes”) in a private placement conducted pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended (the “Securities Act”). The 2020 Senior Notes were co-issued on a joint and several basis by the Company and its wholly owned subsidiary, Midstates Sub. The Company does not have any operations or independent assets other than its 100% ownership interest in Midstates Sub and there are no other subsidiaries of the Company. The 2020 Senior Notes Indenture does not create any restricted assets within Midstates Sub, nor does it impose any significant restrictions on the ability of Midstates Sub to pay dividends or make loans to the Company or limit the ability of the Company to advance loans to Midstates Sub.

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

The estimated fair value of the 2020 Senior Notes was $619.5 million as of September 30, 2014 (Level 2 in the fair value measurement hierarchy based on the limited trading volume on the secondary market), based on quoted market prices for these same debt securities. The effective annual interest rate for the 2020 Senior Notes was approximately 11.1% for the three and nine months ended September 30, 2014 and 2013.

2021 Senior Notes

On May 31, 2013, the Company issued $700 million in aggregate principal amount of 9.25% senior notes due 2021 (the “2021 Senior Notes”). The proceeds from the offering of $700 million (net of the initial purchasers’ discount and related offering expenses) were used to fund the Anadarko Basin Acquisition and the related expenses, to pay the expenses related to an amendment to the Company’s revolving credit facility, to repay $34.3 million in outstanding borrowings under the Company’s Credit Facility, and for general corporate purposes.

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

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

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

The estimated fair value of the 2021 Senior Notes was $696.5 million as of September 30, 2014 (Level 2 in the fair value measurement hierarchy based on the limited trading volume on the secondary market), based on quoted market prices for these same debt securities. The effective annual interest rate for the 2021 Senior Notes was approximately 9.6% for the three and nine months ended September 30, 2014 and approximately 9.4% and 9.5% for the three and nine months ended September 30, 2013, respectively.

10. Equity and Share-Based Compensation

Common and Preferred Shares

The Company is authorized to issue up to a total of 300,000,000 shares of its common stock with a par value of $0.01 per share, and 50,000,000 shares of its preferred stock with a par value of $0.01 per share. Holders of the Company’s common shares are entitled to one vote for each share held of record on all matters submitted to a vote of stockholders and to receive ratably in proportion to the shares of common stock held by them any dividends declared from time to time by the Board of Directors. The common shares have no preferences or rights of conversion, exchange, pre-exemption or other subscription rights.

With respect to preferred shares, the Company is authorized, without further stockholder approval, to establish and issue from time to time one or more classes or series of preferred stock with such powers, preferences, rights, qualifications, limitations and restrictions as determined by its board of directors.

Series A Preferred Stock

In connection with the Eagle Property Acquisition, on September 28, 2012, the Company designated 325,000 shares of Series A Mandatorily Convertible Preferred Stock (the “Series A Preferred Stock”) with an initial liquidation preference of $1,000 per share and an 8% per annum dividend, payable semiannually at the Company’s option in cash or through an increase in the liquidation preference. The Series A Preferred Shares are convertible after October 1, 2013, in whole but not in part and at the option of the holders of a majority of the outstanding shares of Series A Preferred Stock, into a number shares of the Company’s common stock calculated by dividing the then-current liquidation preference by the conversion price of $13.50 per share and, if not previously converted, are mandatorily convertible at September 30, 2015 into shares of the Company’s common stock at a conversion price no

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greater than $13.50 per share and no less than $11.00 per share, with the ultimate conversion price dependent upon the volume weighted average price of the Company’s common stock during the 15 trading days immediately prior to September 30, 2015. The Series A Preferred Stock was issued on October 1, 2012.

On March 30, 2014, the Company elected to pay the $13 million semi-annual dividend due on that date through an increase in the Series A Preferred Stock liquidation preference to $1,125. As a result, the Company will be obligated to issue between 3,005,985 and 3,689,164 additional shares of common stock upon conversion of the Series A Preferred Stock, with the ultimate number of shares dependent upon the conversion price then in effect as described above.

On September 30, 2014, the Company elected to pay the $13 million semi-annual dividend due on that date through an increase in the Series A Preferred Stock liquidation preference to $1,170. As a result, the Company will be obligated to issue between 1,083,202 and 1,329,385 additional shares of common stock upon conversion of the Series A Preferred Stock, with the ultimate number of shares dependent upon the conversion price then in effect as described above.

For the three months ended September 30, 2014, the $1.9 million Series A Preferred Stock dividend (paid through the adjustment to the liquidation preference) was based upon the estimated fair value of 664,692 common shares that would have been issued had the Series A Preferred Stock dividend for the period converted into common shares using a conversion price of $11.00 per share.

For the nine months ended September 30, 2014, the $9.3 million Series A Preferred Stock dividend (paid through the adjustment to the liquidation preference) was based upon the estimated fair value of 1,968,512 common shares that would have been issued had the Series A Preferred Stock dividend for the period been converted into common shares using a conversion price of $11.00 per share.

Share Activity

The following table summarizes changes in the number of outstanding shares during the nine months ended September 30, 2014:

	Number of Shares
	Series A Preferred Stock	Common Stock		Treasury Stock
Share count as of December 31, 2013	325,000	68,925,745		(118,702	)
Grants of restricted stock	—	3,124,478		—
Forfeitures of restricted stock	—	(1,444,144	)	—
Acquisition of treasury stock	—	—		(318,135	)
Share count as of September 30, 2014	325,000	70,606,079		(436,837	)

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

Incentive Units

At September 30, 2014, 1,113 incentive units were issued and outstanding. These incentive units were issued prior to the Company’s initial public offering. In connection with the corporate reorganization that occurred immediately prior to the Company’s initial public offering, these incentive units were contributed to FR Midstates Interholding, LP (“FRMI”) in exchange for incentive units in FRMI. Holders of FRMI incentive units will receive, out of proceeds otherwise distributable to FRMI, a percentage interest in the amounts distributed to FRMI in excess of certain multiples of FRMI’s aggregate capital contributions and investment expenses (“FRMI Profits”). Although any future payments to the incentive unit holders will be made out of the proceeds otherwise distributable to FRMI and not by the Company, the Company will be required to record a non-cash compensation charge in the period any payment is made related to the FRMI incentive units. To date, no compensation expense related to the FRMI incentive units has been recognized by the Company, as any payout under the FRMI incentive units is not considered probable as the amount of FRMI Profits, if any, cannot be determined.

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Share-based Compensation, Post-Initial Public Offering

2012 Long Term Incentive Plan

On April 20, 2012, the Company established the 2012 Long Term Incentive Plan (the “2012 LTIP”) and filed a Form S-8 with the SEC, registering 6,563,435 shares of common stock for future issuance under the terms of the 2012 LTIP. On May 27, 2014, the Company filed a Form S-8 with the SEC, increasing the number of shares available for future issuance under the terms of the 2012 LTIP to 8,638,435 shares of common stock.

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

The 2012 LTIP provides for the granting of Options (Incentive and other), Restricted Stock Awards, Restricted Stock Units, Stock Appreciation Rights, Dividend Equivalents, Bonus Stock, Other Stock-Based Awards, Annual Incentive Awards, Performance Awards, or any combination of the foregoing (the “Awards”). Subject to certain limitations as defined in the 2012 LTIP, the terms of each Award are as determined by the Compensation Committee of the Board of Directors. As of September 30, 2014, a total of 8,638,435 common share Awards are authorized for issuance under the 2012 LTIP and shares of stock subject to an Award that expire, or are canceled, forfeited, exchanged, settled in cash or otherwise terminated, will again be available for future Awards under the 2012 LTIP.

Non-vested Stock Awards

At September 30, 2014, the Company had 3,520,836 non-vested shares of restricted common stock outstanding pursuant to the 2012 LTIP. Shares granted under the LTIP generally vest ratably over a period of three years (one-third on each anniversary of the grant); however, beginning in 2013, shares granted under the 2012 LTIP to directors are subject to one-year cliff vesting.

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

The following table summarizes the Company’s non-vested share award activity for the nine months ended September 30, 2014:

	Shares		Weighted Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2013	2,963,672		$	7.78
Granted	3,124,478		$	4.96
Vested	(1,123,170	)	$	7.61
Forfeited	(1,444,144	)	$	6.87
Non-vested shares outstanding at September 30, 2014	3,520,836		$	5.70

Unrecognized expense, adjusted for estimated forfeitures, as of September 30, 2014 for all outstanding restricted stock awards, was $14.8 million and will be recognized over a weighted average period of 2.1 years.

At September 30, 2014, 3,666,709 shares remain available for issuance under the terms of the 2012 LTIP.

11. Income Taxes

Prior to its corporate reorganization (See Note 1), the Company was a limited liability company and not subject to federal income tax or state income tax (in most states). Accordingly, no provision for federal or state income taxes was recorded prior to the corporate reorganization as the Company’s equity holders were responsible for income tax on the Company’s profits. In connection with the closing of the Company’s initial public offering, the Company merged into a taxable C-Corporation and became subject to federal and state 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 2014 income (or loss) due to previously recorded property impairments, the effects of federal and state valuation allowance adjustments, and hedging volatility.

For the nine months ended September 30, 2014, the Company’s effective tax rate was a benefit of approximately 0.9%. The Company’s effective tax rate for the third quarter of 2014 differs from the federal statutory rate of 35% due to the effect of state income taxes and changes in the valuation allowance. During 2014, the Company recorded $2.2 million in additional valuation

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allowance in light of the impairment of oil and gas properties and the tax gain related to the Pine Prairie Disposition, bringing the total valuation allowance to $48.1 million at September 30, 2014.

A valuation allowance has been recorded as management does not believe that it is more-likely-than-not that its NOLs are realizable except to the extent of future taxable income primarily related to the excess of book carrying value of properties over their respective tax bases. No other sources of future taxable income are considered in this judgment.

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

12. Earnings (Loss) Per Share

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

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

The following table (in thousands, except per share amounts) provides a reconciliation of net 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, 2014 and 2013, respectively:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Net income (loss)	$	74,597		$	(23,606	)	$	(11,145	)	$	(28,217	)
Preferred Dividend (1)	(1,908		)	(2,569		)	(9,334		)	(9,254		)
Net income (loss) attributable to shareholders	$	72,689		$	(26,175	)	$	(20,479	)	$	(37,471	)

Participating securities - Series A Preferred Stock	(23,973		)	—			—			—
Participating securities - Non-vested Restricted Stock	(2,524		)	—			—			—
Net income (loss) attributable to common shareholders	$	46,192		$	(26,175	)	$	(20,479	)	$	(37,471	)

Weighted average shares outstanding	66,598			65,821			66,340			65,740
Net income (loss) per share	$	0.69		$	(0.40	)	$	(0.31	)	$	(0.57	)

(1) Calculation of the preferred stock dividend is discussed in Note 10.

The aggregate number of common shares outstanding at September 30, 2014 was 70,169,242 of which 3,520,836 were non-vested restricted shares. The aggregate number of shares of Series A Preferred Stock outstanding at September 30, 2014 was 325,000, each with a liquidation preference of $1,170 representing on an as-converted basis approximately 34,564,003 common shares based upon a conversion price of $11.00 per share.

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13. Commitments and Contingencies

Contractual Obligations

At September 30, 2014, contractual obligations for drilling contracts, long-term operating leases and seismic contracts are as follows (in thousands):

	Total		2014		2015		2016		2017 and beyond

Drilling contracts	$	8,575	$	6,421	$	2,154	$	—	$	—
Non-cancellable office lease commitments	9,783		459		1,857		1,877		5,590
Seismic contracts	3,192		3,192		—		—		—
Net minimum commitments	$	21,550	$	10,072	$	4,011	$	1,877	$	5,590

For the three months ended September 30, 2014 and 2013, the Company expensed $0.6 and $0.5 million, respectively, for office rent. For the nine months ended September 30, 2014 and 2013, the Company expensed $1.8 and $1.3 million, respectively, for office rent.

In addition to the commitments noted in the above table, the Company is party to a gas transportation, gathering and processing contract (as amended and effective June 1, 2013) in the Mississippian Lime region, which includes certain minimum natural gas and NGL volume commitments. To the extent the Company does not deliver natural gas volumes in sufficient quantities to generate, when processed, the minimum levels of recovered NGL, the Company would be required to reimburse the counterparty an amount equal to the sum of the monthly shortfall, if any, multiplied by a fee of roughly $0.08 to $0.125 per gallon (subject to annual escalation). The NGL volume commitments range from 4,900 Bbls to 5,780 Bbls per day for each monthly accounting period over the remaining term of the contract. Additionally, the Company is obligated to deliver a total of 38,100,000 MMBtus and 76,200,000 MMBtus during the first 30 months and 60 months of the contract, respectively. During the first 30 months, any shortfall in delivered volumes would result in a payment to the counterparty equal to the shortfall amount multiplied by a fee of approximately $0.36 per MMBtu. During the first 60 months, any shortfall in delivered volumes would result in a payment to the counterparty equal to the shortfall amount multiplied by a fee of approximately $0.36 per MMBtu, provided that the Company would receive volumetric credit for any deficiency payment made after the initial 30 months. The Company is currently delivering at least the minimum volumes required under these contractual provisions and does not expect to incur any future volumetric shortfall payments during the term of this contract.

Commitments related to AROs are not included in the table above.

Litigation

The Company is involved in disputes or legal actions arising in the ordinary course of its business. Currently, it is not party to any legal proceedings that the Company believes, individually or in the aggregate, are reasonably expected to have a material adverse effect on its financial position, results of operations, or cash flows.

14. Subsequent Events

Dequincy Disposition

On October 2, 2014, the Company executed a Purchase and Sale Agreement (“Dequincy PSA”) for the sale of the Dequincy portion of its Gulf Coast assets in Louisiana to a private buyer for total consideration of $90 million, subject to customary purchase price adjustments. The Dequincy PSA includes the sale of Midstates’ ownership interest in developed and undeveloped acreage in the Dequincy area in Beauregard and Calcasieu Parishes, Louisiana and the El Grande pipeline that Midstates constructed and owned. The consideration for the sale consists of $80 million in cash, a 10% overriding royalty interest in new wells drilled on that acreage (capped at $8 million) and future payments based on increased throughput on the El Grande pipeline (capped at $2 million). The transaction does not include Midstates’ acreage and interests in the Fleetwood area of Louisiana. The net proceeds from the sale will be used to pay down outstanding borrowings under the Company’s revolving credit facility and for general corporate purposes. The transaction is expected to close in November 2014, subject to customary closing conditions.

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and notes thereto for the year ended December 31, 2013, and the related management’s discussion and analysis contained in our annual report on Form 10-K dated and filed with the Securities and Exchange Commission (“SEC”) on March 24, 2014, 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 the quarterly periods ended March 31, 2014 and June 30, 2014.

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, our quarterly reports on Form 10-Q for the quarters ended March 31, 2014 and June 30, 2014, and detailed in our annual report filed on Form 10-K dated and filed with the SEC on March 24, 2014, 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;

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

· costs of developing our properties and conducting other operations;

· general economic conditions;

· effectiveness of our risk management activities;

· environmental liabilities;

· counterparty credit risk;

· the outcome of pending and future litigation;

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

· developments in oil producing and natural gas producing countries;

· uncertainty regarding our future operating results; and

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

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All forward-looking statements speak only as of the date of this quarterly report. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions. Moreover, we operate in a very competitive and rapidly changing environment. 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 operations originally focused on the Upper Gulf Coast Tertiary trend onshore in Louisiana, which we refer to as our “Gulf Coast” operating area. We began operations in the Mississippian Lime trend in Oklahoma with the October 1, 2012 closing of our acquisition (“Eagle Property Acquisition”) of interests in producing oil and natural gas assets, unevaluated leasehold acreage in Oklahoma and related hedging instruments from Eagle Energy Production, LLC (“Eagle Energy”). On May 31, 2013, the Company closed on the acquisition of producing properties and undeveloped acreage in the Anadarko Basin in Texas and Oklahoma from Panther Energy Company, LLC and its partners for approximately $618 million in cash (the “Anadarko Basin Acquisition”), before customary post-closing adjustments. Subsequent to the closing of the Eagle Property Acquisition and the Anadarko Basin Acquisition, the Company has oil and gas operations and properties in Louisiana, Oklahoma and Texas.

We were incorporated pursuant to the laws of the State of Delaware on October 25, 2011 to become a holding company for Midstates Petroleum Company LLC (“Midstates Sub”), a wholly-owned subsidiary of Midstates Petroleum Holdings LLC. Pursuant to the terms of a corporate reorganization that was completed immediately prior to the closing of our initial public offering on April 25, 2012, all of the interests in Midstates Petroleum Holdings LLC were exchanged for our newly issued common shares, and as a result, Midstates Petroleum Company LLC became our wholly-owned subsidiary and Midstates Petroleum Holdings LLC ceased to exist as a separate entity.

With the completion of our initial public offering, we became a publicly traded company. Our common stock is listed on the NYSE under the ticker symbol “MPO.” The terms “Company,” “we,” “us,” “our,” and similar terms, when used in the present tense, prospectively or for historical periods since April 25, 2012 refer to us and our subsidiary, and for historical periods prior to April 25, 2012, refer to Midstates Petroleum Holdings LLC and its subsidiary, unless the context indicates otherwise.

Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital resources in successful development and exploration activities or acquire properties with existing 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.

Pine Prairie Disposition

On March 5, 2014, we executed a Purchase and Sale Agreement (“PSA”) to sell all of our ownership interest in developed and undeveloped acreage in the Pine Prairie field area of Evangeline Parish, Louisiana to a private buyer for a purchase price of $170 million in cash, subject to standard post-closing adjustments. The PSA had an effective date of November 1, 2013. Acreage subject to the transaction totaled 3,907 gross (3,757 net) acres, and did not include acreage and production in the western part of Louisiana in Beauregard and Calcasieu Parishes or other undeveloped acreage held outside the Pine Prairie field. On May 1, 2014, we closed on the sale for estimated net cash proceeds of $147.5 million, of which $131.0 million was used to reduce amounts outstanding under our revolving credit facility, with the remainder retained for transaction expenses and working capital purposes. Subsequent to May 1, 2014, our remaining Gulf Coast producing assets are located in Beauregard and Calcasieu Parishes.

Exploration Agreement with PetroQuest

On June 25, 2014, we entered into an exploration agreement with PetroQuest Energy LLC (“PetroQuest”) with an effective date of May 1, 2014, in which we conveyed to PetroQuest an undivided 50% of our right, title and interest in and to our acreage and other interests in the Fleetwood prospect area in Louisiana.

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With the execution of the agreement, PetroQuest paid us $3.0 million in cash consideration on July 3, 2014 and, on or before January 5, 2015, PetroQuest will pay additional cash of $7.0 million. As further consideration, PetroQuest granted us (or will pay on our behalf) an additional non-interest bearing total sum of $14.0 million, to be credited or paid against our share of cost or expenses incurred to develop the prospect area, including but not limited to, all mineral lease acquisition or maintenance costs and all drilling, completion, equipping and facility costs. For any amounts not fully paid or credited on or before December 31, 2015, we can elect to take the remaining portion in cash.

Dequincy Disposition

On October 2, 2014, we executed a Purchase and Sale Agreement (“Dequincy PSA”) for the sale of the Dequincy portion of our Gulf Coast assets in Louisiana to a private buyer for total consideration of $90 million, subject to customary purchase price adjustments. The Dequincy PSA includes the sale of our ownership interest in developed and undeveloped acreage (totaling 12,816 gross (12,676 net) acres) in the Dequincy area in Beauregard and Calcasieu Parishes, Louisiana and the 20-mile El Grande pipeline that we constructed and owned. The consideration for the sale consists of $80 million in cash, a 10% overriding royalty interest in new wells drilled on that acreage (capped at $8 million) and future payments based on increased throughput on the El Grande pipeline (capped at $2 million). During the third quarter 2014, the properties produced approximately 1,500 Boe/day. The transaction does not include our acreage and interests in the Fleetwood area of Louisiana and other undeveloped acreage in Louisiana. The net proceeds from the sale will be used to pay down outstanding borrowings under the revolving credit facility and for general corporate purposes. The transaction is expected to close in November 2014, subject to customary closing conditions.

Operations Update

Mississippian Lime

At September 30, 2014 our Mississippian Lime assets consisted of approximately 73,100 net prospective acres in the Mississippian Lime trend, with 69,000 net acres in Woods and Alfalfa Counties of Oklahoma, which we currently believe is the core of the trend. We currently plan to develop these liquids rich properties using horizontal wells. We also own approximately 12,400 net acres in Lincoln County, Oklahoma, which produces from, and is prospective in, the Hunton formation. At quarter-end, we held an average working interest in our Mississippian Lime and Hunton acreage of 68% and our operations consisted of approximately 263 gross active producing wells, 82% of which we operate.

For the three months ended September 30, 2014 and June 30, 2014, our average daily production from the Mississippian Lime area was as follows:

	Three Months Ended September 30, 2014	Three Months Ended June 30, 2014	Increase in Production

Average daily production:
Oil (Bbls)	9,228	8,221	12	%
Natural gas liquids (Bbls)	4,975	4,445	12	%
Natural gas (Mcf)	57,785	48,185	20	%
Net Boe/day	23,834	20,698	15	%

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 2014:

		Total Number of Gross Horizontal Wells Spud (1)		Total Number of Gross Horizontal Wells Brought into Production
Mississippian Lime		29		19

(1) We had seven rigs drilling in the Mississippian Lime horizontal well program at September 30, 2014. Of the 29 wells spud, six were producing, 16 were awaiting completion and seven were being drilled at quarter-end.

Overall production increased by 15% versus the second quarter of 2014 as a result of our increased drilling and completion activity. In addition, second quarter production was negatively impacted by significant weather related downtime and consequent delays in well completions.

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In the third quarter of 2014, we invested approximately $97.6 million on completions and drilling new wells.

Anadarko Basin

Our Anadarko Basin assets were acquired on May 31, 2013, and at September 30, 2014, consisted of approximately 130,100 net acres, of which 98,100 acres were located in Texas and 32,000 acres were located in western Oklahoma. At September 30, 2014, we held an average working interest in our Anadarko Basin acreage of 73% and our operations consisted of approximately 353 gross active producing wells, 65% of which we operate.

For the three months ended September 30, 2014 and June 30, 2014, our average daily production from our Anadarko Basin area was as follows:

	Three Months Ended September 30, 2014	Three Months Ended June 30, 2014	Increase (Decrease) in Production

Average daily production:
Oil (Bbls)	4,002	4,380	(9	)%
Natural gas liquids (Bbls)	1,888	1,780	6	%
Natural gas (Mcf)	15,577	16,348	(5	)%
Net Boe/day	8,486	8,885	(4	)%

The following table shows our total number of horizontal wells spud and brought into production in the Anadarko Basin area of operation during the third quarter of 2014:

		Total Number of Gross Horizontal Wells Spud (1)		Total Number of Gross Horizontal Wells Brought into Production
Anadarko Basin		6		10

(1) We had one rig drilling in the Anadarko Basin area at September 30, 2014. Of the six wells spud, four were producing, one was awaiting completion and one was being drilled at quarter-end.

Overall production decreased by 4% versus the second quarter of 2014 primarily due to base production declines and our decision to temporarily reduce our drilling rig count in this area. During the third quarter, we invested approximately $36.5 million on completions and new drilling, spud six wells and brought 10 wells online (comprised of one Cleveland well, four Cottage Grove wells, two Tonkawa wells and three Marmaton wells).

Gulf Coast

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

As discussed above, we closed on the sale of producing properties and undeveloped acreage in the Pine Prairie Field area of Evangeline Parish, Louisiana on May 1, 2014 for estimated net proceeds of $147.5 million in cash, after post-closing adjustments. These assets contributed approximately 838 Boe/day to our average daily production through the nine months ended September 30, 2014.

On October 2, 2014, we executed the Dequincy PSA for the sale of the Dequincy portion of our Gulf Coast assets to a private buyer for total consideration of $90 million, subject to customary purchase price adjustments. The Dequincy PSA includes the sale of our ownership interest in developed and undeveloped acreage (totaling 12,816 gross (12,676 net) acres) in the Dequincy area in Beauregard and Calcasieu Parishes, Louisiana. During the third quarter 2014, these properties produced approximately 1,500 Boe/day.

At September 30, 2014, after the Pine Prairie Disposition and exploration agreement with PetroQuest, we had approximately 45,700 net acres in the trend. At September 30, 2014, we held an average working interest of 97% in our Gulf Coast acreage and our operations consisted of approximately 39 gross active producing wells, 100% of which we operate.

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For the three months ended September 30, 2014 and June 30, 2014, our average daily production from the Gulf Coast area was as follows:

	Three Months Ended September 30, 2014	Three Months Ended June 30, 2014	Decrease in Production

Average daily production:
Oil (Bbls)	1,066	1,688	(37	)%
Natural gas liquids (Bbls)	300	384	(22	)%
Natural gas (Mcf)	682	1,544	(56	)%
Net Boe/day	1,479	2,329	(36	)%

Overall production decreased by 36% versus the second quarter of 2014, as second quarter results included one month of production from the assets that were sold as part of the Pine Prairie Disposition. In addition, base production has continued to decline as we have devoted our capital to developing our Mississippian Lime and Anadarko Basin assets.

For the quarter ended September 30, 2014, we invested approximately $0.1 million in the Gulf Coast area. No wells were spud or brought into production in our Gulf Coast area of operation during the third quarter of 2014.

Capital Expenditures

During the three and nine months ended September 30, 2014, we incurred operational capital expenditures of $134.3 million and $410.1 million, respectively, which consisted primarily of:

	For the Three Months Ended September 30, 2014		For the Nine Months Ended September 30, 2014
Drilling and completion activities	$	130,638	$	395,017
Acquisition of acreage and seismic data	3,642		15,119
Operational capital expenditures incurred	$	134,280	$	410,136
Capitalized G&A, office, ARO & other	2,165		9,292
Capitalized interest	2,582		10,544
Total capital expenditures incurred	$	139,027	$	429,972

Operational capital expenditures by area were as follows:

	For the Three Months Ended September 30, 2014		For the Nine Months Ended September 30, 2014
Mississippian Lime	97,633		276,404
Anadarko Basin	36,544		128,356
Gulf Coast	103		5,376
Total operational capital expenditures incurred	$	134,280	$	410,136

We expect to invest between $500 million to $550 million of capital for exploration, development and lease and seismic acquisition during the year ended December 31, 2014.

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” beginning on page 38 for discussion of our hedging and hedge positions.

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

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

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

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

· facility or equipment availability and unexpected downtime;

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

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

We follow the full cost method of accounting for our oil and gas properties. In the fourth quarter of 2013 and again in the first quarter of 2014, the results of our full cost “ceiling test” required us to recognize an impairment of our oil and gas properties. While these impairments did not impact cash flow from operating activities, they did reduce our earnings and shareholders’ equity. We may be required to recognize additional impairments of oil and gas properties in future periods if we experience an extended period of low commodity prices, a downward adjustment to our estimated proved reserves or the present value of estimated future net revenues, or incur actual development costs in excess of those estimates utilized in preparing our reserve reports. Additionally, the expiration of unevaluated acreage leaseholds may increase the probability of future impairments, as the costs associated with the expiring leases would be immediately included in the full cost pool and become subject to the ceiling test limitation without any corresponding increase in reserves or future net revenues.

At September 30, 2014, our full cost ceiling test indicated that our capitalized costs were within five percent of the ceiling. While we hedge a portion of our commodity production to protect cash flow, those derivative contracts have not been designated as ASC 815 hedges and therefore we are not able to utilize the contract’s currently favorable pricing in calculating our ceiling test. As a result, the recent decline in oil prices during the fourth quarter of 2014 increases the likelihood of a full cost ceiling test impairment at year-end 2014.

Results of Operations

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

Revenues

	For the Three Months Ended September 30,										For the Nine Months Ended September 30,
	2014					2013					2014					2013
	(in thousands)										(in thousands)
REVENUES:
Oil sales	$	125,430		72	%	$	119,049		76	%	$	372,925		72	%	$	268,903		77	%
Natural gas liquid sales	22,989			13	%	18,939			12	%	71,528			14	%	39,656			11	%
Natural gas sales	24,607			15	%	18,775			12	%	74,986			14	%	42,034			12	%
Total oil, natural gas, and natural gas liquids sales	173,026			100	%	156,763			100	%	519,439			100	%	350,593			100	%

Realized losses on commodity derivative contracts, net	(7,265		)	-14	%	(9,927		)	22	%	(39,213		)	1240	%	(16,002		)	37	%
Unrealized gains (losses) on commodity derivative contracts, net	58,243			114	%	(35,369		)	78	%	36,051			-1140	%	(26,997		)	63	%
Gains (losses) on commodity derivative contracts - net	50,978			100	%	(45,296		)	100	%	(3,162		)	100	%	(42,999		)	100	%

Other	757					38					1,136					941

Total revenues	$	224,761				$	111,505				$	517,413				$	308,535

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Production

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2014	2013	% Change		2014	2013	% Change
PRODUCTION DATA:
Oil (MBbls)	1,315	1,139	15	%	3,823	2,650	44	%
Natural gas liquids (MBbls)	659	539	22	%	1,792	1,128	59	%
Natural gas (MMcf)	6,812	5,643	21	%	18,050	12,522	44	%
Oil equivalents (MBoe)	3,109	2,619	19	%	8,624	5,864	47	%

Oil (Boe/day)	14,296	12,382	15	%	14,003	9,705	44	%
Natural gas liquids (Boe/day)	7,163	5,860	22	%	6,566	4,130	59	%
Natural gas (Mcf/day)	74,044	61,336	21	%	66,116	45,867	44	%
Average daily production (Boe/d)	33,799	28,464	19	%	31,589	21,480	47	%

Prices

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2014		2013		% Change		2014		2013		% Change
AVERAGE SALES PRICES:
Oil, without realized derivatives (per Bbl)	$	95.37	$	104.51	-9	%	$	97.55	$	101.49	-4	%
Oil, with realized derivatives (per Bbl)	$	88.70	93.56		-5	%	$	88.32	93.88		-6	%
Natural gas liquids, without realized derivatives (per Bbl)	$	34.89	35.13		-1	%	$	39.90	35.17		13	%
Natural gas liquids, with realized derivatives (per Bbl)	$	35.12	35.77		-2	%	$	40.03	36.36		10	%
Natural gas, without realized derivatives (per Mcf)	$	3.61	3.33		9	%	$	4.15	3.36		24	%
Natural gas, with realized derivatives (per Mcf)	$	3.81	3.72		3	%	$	3.92	3.58		10	%

Three Months Ended September 30, 2014 as Compared to the Three Months Ended September 30, 2013

Oil, natural gas liquids and natural gas sales revenues

Our oil, NGL and natural gas sales revenues increased by $16.2 million, or 10% to $173.0 million during the three months ended September 30, 2014, as compared to $156.8 million during the three months ended September 30, 2013. After normalizing for the Pine Prairie Disposition, revenues increased by $38.2 million, or 28%.

Our oil sales revenues increased by $6.3 million, or 5%, to $125.4 million during the three months ended September 30, 2014, as compared to $119.1 million for the three months ended September 30, 2013. After normalizing for the Pine Prairie Disposition, oil sales revenues increased by $25.6 million and 26%. Oil volumes sold increased 1,914 Boe/day, or 15%, to 14,296 Boe/day for the three months ended September 30, 2014, from 12,382 Boe/day for the three months ended September 30, 2013. This increase in oil volumes sold was attributable to increased production quarter over quarter in the Mississippian Lime area of 4,147 Boe/day, and 312 Boe/day of additional production volumes from our Anadarko Basin area, partially offset by a decrease in volumes from our Gulf Coast region of 2,545 Boe/day, of which 1,910 Boe/day was related to the Pine Prairie Disposition. The overall improvement in oil sales volumes of 1,914 Boe/day resulted in approximately $18.4 million in additional oil sales revenues. Average oil sales prices, without realized derivatives, decreased by $9.14 per barrel, or 9%, to $95.37 per barrel during the three months ended September 30, 2014 as compared to $104.51 per barrel for the three months ended September 30, 2013. This price variance resulted in a decrease in oil sales revenue of approximately $12.0 million during the three months ended September 30, 2014, as measured against the comparable period in 2013.

Our NGL sales revenues increased by $4.1 million, or 22%, to $23.0 million during the three months ended September 30, 2014, as compared to $18.9 million for the three months ended September 30, 2013. After normalizing for the Pine Prairie Disposition, NGL sales revenues increased by $5.4 million, or 31%. NGL volumes sold increased 1,303 Boe/day, or 22%, to 7,163 Boe/day for the three months ended September 30, 2014, from 5,860 Boe/day for the three months ended September 30, 2013. This increase in NGL volumes sold was attributable to the increased production quarter over quarter in the Mississippian Lime area of 2,016 Boe/day, partially offset by a 40 Boe/day decrease in production volumes from our Anadarko Basin area and a 673 Boe/day decrease in production from our Gulf Coast area, of which 422 Boe/day was related to Pine Prairie. The overall improvement in NGL sales volumes of 1,303 Boe/day resulted in approximately $4.2 million in additional NGL sales revenues. Average NGL sales prices, without realized derivatives, decreased by $0.24 per barrel, or 1%, to $34.89 per barrel during the three months ended September 30, 2014 as compared to $35.13 per barrel for the corresponding period in 2013. This price variance resulted in a decrease in NGL sales revenue of approximately $0.1 million during the three months ended September 30, 2014 as measured against the comparable period in 2013.

Table of Contents

Our natural gas sales revenues increased by $5.8 million, or 31%, to $24.6 million during the three months ended September 30, 2014, as compared to $18.8 million for the three months ended September 30, 2013. After normalizing for the Pine Prairie Disposition, natural gas sales revenues increased $7.3 million, or 42%. Natural gas volumes sold increased 12,708 Mcf/day or 21%, to 74,044 Mcf/day for the three months ended September 30, 2014, from 61,336 Mcf/day for the three months ended September 30, 2013. This increase in natural gas volumes sold was attributable to increased production of 19,842 Mcf/day in the Mississippian Lime area, partially offset by a decrease in production of 1,139 Mcf/day from our Anadarko Basin area and 5,995 Mcf/day from our Gulf Coast area, of which 4,703 Boe/day was related to Pine Prairie. The overall improvement in natural gas sales volumes of 12,708 Mcf/day resulted in approximately $3.9 million in additional natural gas sales revenues. Average natural gas sales prices, without realized derivatives, increased by $0.28 per Mcf, or 8%, to $3.61 per Mcf during the three months ended September 30, 2014 as compared to $3.33 per Mcf for the three months ended September 30, 2013. This price variance resulted in an increase in natural gas sales revenue of approximately $1.9 million during the three months ended September 30, 2014, as measured against the comparable period in 2013.

Gains/losses on commodity derivative contracts - net

Our mark-to-market (“MTM”) derivative positions moved from an unrealized loss of $35.4 million for the three months ended September 30, 2013 to an unrealized gain of $58.2 million for the three months ended September 30, 2014. During the quarter ended September 30, 2014, the Company entered into eight additional oil trades that will price during 2015. The NYMEX WTI closing price on September 30, 2014 was $91.16 per barrel compared to a closing price of $102.33 per barrel on September 30, 2013 (the last day of trading for the period). At September 30, 2014, our oil derivatives have contract prices that range from $86.49 to $97.71 per barrel and extend through the fourth quarter of 2015. (See Note 4 in Item 1. Financial Statements.)

The realized loss on derivatives for the three months ended September 30, 2014 was $7.3 million, compared to a realized loss of $9.9 million for the three months ended September 30, 2013. The following table presents realized gain (loss) by type of commodity contract for the three months ended September 30, 2014:

	For the Three Months Ended September 30, 2014
	Realized Gain (Loss)			Average Sales Price
	(in thousands)
Oil commodity contracts	$	(8,776	)	$	88.70
Natural gas liquids commodity contracts	156			35.12
Natural gas commodity contracts	1,355			3.81
Realized losses on commodity derivative contracts, net	$	(7,265	)

Nine Months Ended September 30, 2014 as Compared to the Nine Months Ended September 30, 2013

Oil, natural gas liquids and natural gas sales revenues

Our oil, NGL and natural gas sales revenues increased by $168.8 million, or 48%, to $519.4 million during the nine months ended September 30, 2014, as compared to $350.6 million during the nine months ended September 30, 2013. After normalizing for the Pine Prairie Disposition, our oil, NGL and natural gas sales revenues increased by $232.9 million, or 87%, to $500.6 million during the nine months ended September 30, 2014, as compared to $267.7 during the nine months ended September 30, 2013.

Our oil sales revenues increased by $104.0 million, or 39%, to $372.9 million during the nine months ended September 30, 2014, as compared to $268.9 million for the nine months ended September 30, 2013. After normalizing for the Pine Prairie Disposition, our oil sales revenues increased by $160.3 million, or 82%, to $356.7 million during the nine months ended September 30, 2014, as compared to $196.4 million during the nine months ended September 30, 2013. Oil volumes sold increased 4,298 Boe/day, or 44%, to 14,003 Boe/day for the nine months ended September 30, 2014, from 9,705 Boe/day for the nine months ended September 30, 2013. This increase in oil volumes sold was attributable to increased production period over period in the Mississippian Lime area of 3,880 Boe/day and 2,574 Boe/day of additional production volumes from our Anadarko Basin area (the 2013 comparative period included only four months of results due to the timing of the Anadarko Basin Acquisition), partially offset by a decrease in volumes from our Gulf Coast region of 2,156 Boe/day, of which 2,419 Boe/day was related to Pine Prairie. The overall improvement in oil sales volumes of 4,298 Boe/day resulted in approximately $119.0 million in additional oil sales revenues. Average oil sales prices, without realized derivatives, decreased by $3.94 per barrel, or 4%, to $97.55 per barrel during the nine months ended September 30, 2014 as compared to $101.49 per barrel for the nine months ended September 30, 2013. This price variance resulted in a decrease in oil sales revenue of approximately $15.1 million during the nine months ended September 30, 2014 as measured against the comparable period in 2013.

Table of Contents

Our NGL sales revenues increased by $31.8 million, or 80%, to $71.5 million during the nine months ended September 30, 2014, as compared to $39.7 million for the nine months ended September 30, 2013. After normalizing for the Pine Prairie Disposition, our NGL sales revenues increased by $34.9 million, or 100%, to $69.9 million during the nine months ended September 30, 2014, as compared to $35.0 million during the nine months ended September 30, 2013. NGL volumes sold increased 2,436 Boe/day, or 59%, to 6,566 Boe/day for the nine months ended September 30, 2014, from 4,130 Boe/day for the nine months ended September 30, 2013. This increase in NGL volumes sold was attributable to the increased production period over period in the Mississippian Lime area of 2,028 Boe/day and 954 Boe/day of additional production volumes from our Anadarko Basin area (the 2013 comparative period included only four months of results due to the timing of the Anadarko Basin Acquisition), partially offset by a 546 Boe/day decrease in production from our Gulf Coast area, of which 467 Boe/day related to Pine Prairie. The overall improvement in NGL sales volumes of 2,436 Boe/day resulted in approximately $23.4 million in additional NGL sales revenues. Average NGL sales prices, without realized derivatives, increased by $4.73 per barrel, or 13%, to $39.90 per barrel during the nine months ended September 30, 2014 as compared to $35.17 per barrel for the corresponding period in 2013. This price variance resulted in an increase in NGL sales revenue of approximately $8.5 million during the nine months ended September 30, 2014 as measured against the comparable period in 2013.

Our natural gas sales revenues increased by $33.0 million, or 79%, to $75.0 million during the nine months ended September 30, 2014, as compared to $42.0 million for the nine months ended September 30, 2013. After normalizing for the Pine Prairie Disposition, our natural gas sales revenues increased by $37.7 million, or 104%, to $73.9 million during the nine months ended September 30, 2014, as compared to $36.2 million during the nine months ended September 30, 2013. Natural gas volumes sold increased 20,249 Mcf/day or 44%, to 66,116 Mcf/day for the nine months ended September 30, 2014, from 45,867 Mcf/day for the nine months ended September 30, 2013. This increase in natural gas volumes sold was attributable to increased production of 17,917 Mcf/day in the Mississippian Lime area and 8,003 Mcf/day of additional production volumes from our Anadarko Basin area (the 2013 comparative period included only four months of results from these properties due to the timing of the Anadarko Basin Acquisition), partially offset by a decrease in production of 5,671 Mcf/day from our Gulf Coast area, of which 5,601 Mcf/day related to Pine Prairie. The overall improvement in natural gas sales volumes of 20,249 Mcf/day resulted in approximately $18.6 million in additional oil sales revenues. Average natural gas sales prices, without realized derivatives, increased by $0.79 per Mcf, or 24%, to $4.15 per Mcf during the nine months ended September 30, 2014, as compared to $3.36 per Mcf for the nine months ended September 30, 2013. This price variance resulted in an increase in natural gas sales revenue of approximately $14.4 million during the nine months ended September 30, 2014 as measured against the comparable period in 2013.

Gains/losses on commodity derivative contracts - net

Our mark-to-market (“MTM”) derivative positions moved from an unrealized loss of $27.0 million for the nine months ended September 30, 2013 to an unrealized gain of $36.1 million for the nine months ended September 30, 2014. The NYMEX WTI closing price on September 30, 2014 was $91.16 per barrel compared to a closing price of $102.33 per barrel on September 30, 2013 (the last day of trading for the period). At September 30, 2014, our oil derivatives have contract prices that range from $86.49 to $97.71 per barrel and extend through the fourth quarter of 2015. (See Note 4 in Item 1. Financial Statements.)

The realized loss on derivatives for the nine months ended September 30, 2014 was $39.2 million compared to a realized loss of $16.0 million for the nine months ended September 30, 2013. The following table presents realized gain (loss) by type of commodity contract for the nine months ended September 30, 2014:

	For the Nine Months Ended September 30, 2014
	Realized Gain (Loss)			Average Sales Price
	(in thousands)
Oil commodity contracts	$	(35,258	)	$	88.32
Natural gas liquids commodity contracts	217			40.03
Natural gas commodity contracts	(4,172		)	3.92
Realized losses on commodity derivative contracts, net	$	(39,213	)

Table of Contents

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,
	2014		2013		2014		2013		2014		2013		2014		2013
	(in thousands)				(per Boe)				(in thousands)				(per Boe)
EXPENSES:
Lease operating and workover	$	16,965	$	21,784	$	5.46	$	8.32	$	56,813	$	53,230	$	6.59	$	9.08
Gathering and transportation	3,902		2,583		1.26		0.99		9,697		2,583		1.12		0.44
Severance and other taxes	5,780		8,080		1.86		3.09		19,059		20,614		2.21		3.52
Asset retirement accretion	406		421		0.13		0.16		1,335		988		0.15		0.17
Depreciation, depletion, and amortization	73,109		74,789		23.52		28.56		211,084		169,595		24.48		28.92
Impairment of oil and gas properties	—		—		—		—		86,471		—		10.03		—
General and administrative	9,879		13,911		3.18		5.31		34,997		40,209		4.06		6.86
Acquisition and transaction costs	1,283		194		0.41		0.07		3,894		11,686		0.45		1.99
Other	2,346		614		0.75		0.23		3,285		614		0.38		0.10
Total expenses	$	113,670	$	122,376	$	36.57	$	46.73	$	426,635	$	299,519	$	49.47	$	51.08

Three Months Ended September 30, 2014 as Compared to the Three Months Ended September 30, 2013

Lease operating and workover expenses

Lease operating and workover expenses decreased $4.9 million, or 22%, to $16.9 million for the three months ended September 30, 2014 compared to $21.8 million for the three months ended September 30, 2013. After normalizing for the Pine Prairie Disposition, lease operating and workover expenses decreased $0.4 million, or 2%. Lease operating expenses decreased $3.6 million, or 18%, to $16.4 million for the three months ended September 30, 2014 as compared to $20.0 million for the same period of 2013. After normalizing for the Pine Prairie Disposition, lease operating expenses were essentially flat, period over period. Workover expenses decreased $1.3 million, or 72%, to $0.5 million for the three months ended September 30, 2014 compared to $1.8 million for the three months ended September 30, 2013. After normalizing for the Pine Prairie Disposition, workover expenses decreased $0.7 million, or 58%; lower costs in the Dequincy field of the Gulf Coast region were the primary reason for the remaining decrease. Lease operating and workover expenses decreased to $5.46 per Boe for the three months ended September 30, 2014, a decrease of $2.86, or 34%, over the $8.32 per Boe for the three months ended September 30, 2013. This decrease was largely attributable to increased production during the 2014 period, the realization of expense benefits from investments to reduce salt water disposal costs in the Mississippian Lime area, the migration from diesel fired electric generators to sourcing electricity from the local power grid in the Mississippian Lime area, most of which were implemented in the second half of 2013 and the closing of the Pine Prairie Disposition on May 1, 2014 where production had relatively higher per Boe rates.

Gathering and transportation

Gathering and transportation expenses increased $1.3 million, or 50% to $3.9 million for the three months ended September 30, 2014 compared to $2.6 million for the three months ended September 30, 2013. These expenses are primarily attributable to an amended gas transportation, gathering and processing contract, which commenced during the third quarter of 2013 in the Mississippian Lime and included a $0.36 per Mmbtu gathering fee based upon wellhead volumes.

Severance and other taxes

	Three Months Ended September 30,
	2014			2013

Total oil, natural gas, and natural gas liquids sales	$	173,026		$	156,763

Severance taxes	4,321			6,273
Ad valorem and other taxes	1,459			1,807
Severance and other taxes	$	5,780		$	8,080

Severance taxes as a percentage of sales	2.5		%	4.0		%
Severance and other taxes as a percentage of sales	3.3		%	5.2		%

Table of Contents

Severance and other taxes decreased $2.3 million, or 28%, to $5.8 million for the three months ended September 30, 2014 compared to $8.1 million for the three months ended September 30, 2013. Severance taxes decreased $2.0 million, or 32%, to $4.3 million for the three months ended September 30, 2014, as compared to $6.3 million for the three months ended September 30, 2013. Severance taxes as a percentage of sales changed from 4.0% for the three months ended September 30, 2013 to 2.5% for the corresponding 2014 period due to lower effective severance tax rates in our Mississippian Lime and Anadarko areas and lower production period-over-period in the relatively higher tax Gulf Coast region, resulting from reduced drilling activity in 2014 and the Pine Prairie Disposition. Ad valorem taxes decreased $0.3 million, or 17%, to $1.5 million for the three months ended September 30, 2014, as compared to $1.8 million for the three months ended September 30, 2013, corresponding to reduced ad valorem taxes in the Gulf Coast area attributable to the Pine Prairie Disposition.

Depreciation, depletion and amortization (DD&A)

DD&A expense decreased $1.7 million, or 2%, to $73.1 million for the three months ended September 30, 2014 compared to $74.8 million for the three months ended September 30, 2013. The decrease in DD&A expense was driven by a lower depletable base as of September 30, 2014 as compared to September 30, 2013. The depletable base decreased largely due to full cost ceiling test impairments recorded at December 31, 2013 and March 31, 2014, partially offset by capital expenditures incurred throughout the year. Consequently, the DD&A rate also decreases from $28.56 per Boe for the three months ended September 30, 2013 to $23.52 per Boe for the three months ended September 30, 2014.

General and administrative (G&A)

Our G&A expenses decreased by $4.0 million, or 29%, to $9.9 million for the three months ended September 30, 2014, compared to $13.9 million for the three months ended September 30, 2013. The $4.0 million decrease period over period is primarily related to: $1.3 million in additional COPAS recoveries, $3.6 million less in transition services payments (in 2013, payments were made as a result of the Eagle Energy Acquisition and Anadarko Basin Acquisition) and $1.4 million less in other taxes, offset by an increase of $2.3 million in employee costs, professional services and other G&A costs.

Acquisition and transaction costs

Our acquisition and transaction costs were $1.3 million for the three months ended September 30, 2014, compared to $0.2 million for the three months ended September 30, 2013. For the 2014 period, these costs primarily represent our expenses related to the Pine Prairie Disposition discussed above. For the 2013 period, these costs represent our expenses related to the Anadarko Basin Acquisition, which closed in May 2013.

Other

Other operating expenses for the three months ended September 30, 2014 were $2.3 million, compared to $0.6 million for the three months ended September 30, 2013. Other operating expenses represent the loss on disposal of, or market value adjustments to, field equipment inventory.

Nine Months Ended September 30, 2014 as Compared to the Nine Months Ended September 30, 2013

Lease operating and workover expenses

Lease operating and workover expenses increased $3.6 million, or 7%, to $56.8 million for the nine months ended September 30, 2014 compared to $53.2 million for the nine months ended September 30, 2013. After normalizing for the Pine Prairie Disposition, our lease operating and workover expenses increased by $13.8 million, or 35%, to $53.1 million during the nine months ended September 30, 2014. Lease operating expenses increased $7.6 million, or 16%, to $53.9 million for the nine months ended September 30, 2014 as compared to $46.3 million for the related period in 2013. After normalizing for the Pine Prairie Disposition, our lease operating expenses increased by $16.9 million, or 50%. This increase was attributable to our Anadarko Basin Assets; the 2014 period included nine months of lease operating expense and the 2013 comparable period included only four months of lease operating expense due to the timing of the Anadarko Basin Acquisition. Workover expenses decreased $4.0 million, or 58%, to $2.9 million for the nine months ended September 30, 2014 compared to $6.9 million for the nine months ended September 30, 2013. After normalizing for the Pine Prairie Disposition, our workover expenses decreased by $3.1 million, or 55%. Lease operating and workover expenses decreased to $6.59 per Boe for the nine months ended September 30, 2014; a decrease of $2.49, or 27%, from the $9.08 per Boe for the nine months ended September 30, 2013. This decrease was primarily attributable to increased production during the 2014 period, the realization of expense benefits from our investments to reduce salt water disposal costs in the Mississippian Lime area, the migration from diesel fired electric generators to sourcing electricity from the local power grid in the Mississippian Lime area, most of which were implemented in the latter part of 2013 and the closing of the Pine Prairie Disposition on May 1, 2014, where production had relatively higher per Boe rates.

Table of Contents

Gathering and transportation

Gathering and transportation expenses were $9.7 million for the nine months ended September 30, 2014 compared to $2.6 million for the nine months ended September 30, 2013. These expenses are primarily attributable to an amended gas transportation, gathering and processing contract, which commenced during the third quarter of 2013 in the Mississippian Lime that included a $0.36 per Mmbtu gathering fee based upon wellhead volumes.

Severance and other taxes

	Nine Months Ended September 30,
	2014			2013

Total oil, natural gas, and natural gas liquids sales	$	519,439		$	350,593

Severance taxes	14,483			16,487
Ad valorem and other taxes	4,576			4,127
Severance and other taxes	$	19,059		$	20,614

Severance taxes as a percentage of sales	2.8		%	4.7		%
Severance and other taxes as a percentage of sales	3.7		%	5.9		%

Severance and other taxes decreased $1.5 million, or 7%, to $19.1 million for the nine months ended September 30, 2014, compared to $20.6 million for the nine months ended September 30, 2013. Severance taxes decreased $2.0 million, or 12% to $14.5 million for the nine months ended September 30, 2014, as compared to $16.5 million for the nine months ended September 30, 2013. Severance taxes as a percentage of sales changed from 4.7% for the nine months ended September 30, 2013 to 2.8% for the corresponding 2014 period due to lower effective severance tax rates in our Mississippian Lime and Anadarko Basin areas and lower production period-over-period in the relatively higher tax Gulf Coast region, attributable to lower drilling activity in 2014 and the Pine Prairie Disposition. Ad valorem taxes increased $0.5 million, or 12%, to $4.6 million for the nine months ended September 30, 2014, as compared to $4.1 million for the nine months ended September 30, 2013, corresponding to a related increase in producing wells due to the Anadarko Basin Acquisition and increased development drilling, partially offset by reduced ad valorem taxes in the Gulf Coast area attributable to the Pine Prairie Disposition.

Depreciation, depletion and amortization (DD&A)

DD&A expense increased $41.5 million, or 24%, to $211.1 million for the nine months ended September 30, 2014 compared to $169.6 million for the nine months ended September 30, 2013. The increase in DD&A expense was primarily attributable to an increase in production of 47%, partially offset by a decrease in the DD&A rate. The DD&A rate for the nine months ended September 30, 2014 was $24.48 per Boe, compared to $28.92 per Boe for the nine months ended September 30, 2013. This reduction in the DD&A rate was due to a declining depletable base during the nine months ended September 30, 2014, primarily due to full cost ceiling test impairments recorded at December 31, 2013 and March 31, 2014, partially offset by capital expenditures incurred throughout the year.

Impairment of oil and gas properties

Our impairment of oil and gas properties pursuant to the full cost “ceiling test” was $86.5 million, net of taxes, for the nine months ended September 30, 2014. There was no impairment for the nine months ended September 30, 2013. The most significant factors affecting the impairment related to the transfer of unevaluated property costs to the full cost pool during the first quarter of 2014.

General and administrative (G&A)

Our G&A expenses decreased by $5.2 million, or 13%, to $35.0 million for the nine months ended September 30, 2014, compared to $40.2 million for the nine months ended September 30, 2013. The $5.2 million decrease period over period is primarily related to: $4.1 million in additional COPAS recoveries, $6.7 million less in transition services payments (in 2013 and part of 2014, payments were made as a result of the Eagle Energy Acquisition and Anadarko Basin Acquisition) and $2.6 million less in other taxes, partially offset by an increase of $8.2 million in employee costs, professional services and other G&A costs.

Acquisition and transaction costs

Our acquisition and transaction costs were $3.9 million for the nine months ended September 30, 2014, compared to $11.7 million for the nine months ended September 30, 2013. For the 2014 period, these costs represent our expenses related to the Pine Prairie Disposition discussed above. For the 2013 period, these costs represent our expenses related to the Anadarko Basin Acquisition discussed above.

Table of Contents

Other

Other operating expenses for the nine months ended September 30, 2014 were $3.3 million, compared to $0.6 million for the nine months ended September 30, 2013. These costs represent the loss on disposal of, or market value adjustments to, field equipment inventory.

Other Income (Expenses)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands)						(in thousands)
OTHER INCOME (EXPENSE)
Interest income	$	10		$	7		$	29		$	17

Interest expense	(36,870		)	(35,625		)	(112,592		)	(78,028		)
Capitalized Interest	2,582			9,675			10,544			24,590
Interest expense — net of amounts capitalized	(34,288		)	(25,950		)	(102,048		)	(53,438		)

Total other income (expense)	$	(34,278	)	$	(25,943	)	$	(102,019	)	$	(53,421	)

Interest expense

Three Months Ended September 30, 2014 as Compared to the Three Months Ended September 30, 2013

Interest expense for the three months ended September 30, 2014 and 2013 was $36.9 million and $35.6 million, respectively. Our average outstanding balance under our revolving credit facility was $362.5 million during the three months ended September 30, 2014, compared to $271.1 million for the three months ended September 30, 2013, and related to $2.8 million of the total interest expense of $36.9 million for the three months ended September 30, 2014. Of the remainder, $16.2 million was interest incurred under the 2021 Senior Notes, $16.1 million was interest incurred under the 2020 Senior Notes and $1.8 million represented amortization of deferred financing costs. Of the total interest expense for both periods, $2.6 million and $9.7 million was capitalized to oil and gas properties, resulting in $34.3 million and $25.9 million in interest expense, net of capitalized interest, for the three months ended September 30, 2014 and 2013, respectively.

Nine Months Ended September 30, 2014 as Compared to the Nine Months Ended September 30, 2013

Interest expense for the nine months ended September 30, 2014 and 2013 was $112.6 million and $78.0 million, respectively. The increase in interest expense was primarily due to the issuance of the 2021 Senior Notes in May 2013 in connection with the Anadarko Basin Acquisition. Our average outstanding balance under our revolving credit facility was $377.8 million during the nine months ended September 30, 2014, compared to $210.5 million for the nine months ended September 30, 2013, and related to $9.5 million of the total interest expense of $112.6 million for the nine months ended September 30, 2014. Of the remainder, $48.7 million was interest incurred under the 2021 Senior Notes, $48.4 million was interest incurred under the 2020 Senior Notes and $6.0 million represented amortization of deferred financing costs. Of the total interest expense for both periods, $10.5 million and $24.6 million was capitalized to oil and gas properties, resulting in $102.1 million and $53.4 million in interest expense, net of capitalized interest, for the nine months ended September 30, 2014 and 2013, respectively.

Provision for Income Taxes

Three Months Ended September 30, 2014 as Compared to the Three Months Ended September 30, 2013

Our income tax expense was $2.2 million for the three months ended September 30, 2014 and a benefit of $13.2 million for the three months ended September 30, 2013. For the three months ended September 30, 2014, the Company’s effective tax rate was an expense of approximately 2.9%. The Company’s effective tax rate for the third quarter of 2014 differs from the federal statutory rate of 35% due to state income taxes and the release of $28 million of valuation allowance due to changes in pre-tax book income during the quarter, IDC capitalization, and the tax gain related to the sale of Pine Prairie assets.

Nine Months Ended September 30, 2014 as Compared to the Nine Months Ended September 30, 2013

Our income tax benefit was $0.1 and $16.2 million for the nine months ended September 30, 2014 and 2013, respectively. For the nine months ended September 30, 2014, the Company’s effective tax rate was a benefit of approximately 0.9%. The Company’s effective tax rate for the nine months ended September 30, 2014 differs from the federal statutory rate of 35% due to the effect of state income

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taxes and changes in the valuation allowance. This year, the Company recorded $2.2 million in additional valuation allowance in light of the impairment of oil and gas properties and the tax gain related to the sale of the Pine Prairie assets, bringing the total valuation allowance to $48.1 million at September 30, 2014.

Liquidity and Capital Resources

At September 30, 2014, our liquidity was $181 million, consisting of $155 million of available borrowing capacity under our revolving credit facility and $26 million of cash and cash equivalents.

Expenditures for exploration and development of oil and natural gas properties are the primary use of our capital resources. We expect to invest between $500 million and $550 million of capital for exploration, development and lease and seismic acquisition during the year ended December 31, 2014. Additionally, we expect to capitalize between $13 and $15 million of interest expense during that same period. Our future success in growing proved reserves and production will be highly dependent on our ability to access additional outside sources of capital, via either the debt or equity markets, through growth in our reserve-based credit facility or by securing other external sources of funding. As part of that process, on May 1, 2014, we closed on the sale of all of our ownership interest in developed and undeveloped acreage in the Pine Prairie field area of Evangeline Parish, Louisiana to a private buyer for estimated net proceeds of $147.5 million, of which $131 million was used to reduce amounts outstanding under our revolving credit facility, with the remainder retained for transaction expenses and working capital purposes. On October 2, 2014, we executed the Dequincy PSA for the sale of the Dequincy portion of our Gulf Coast assets in Louisiana to a private buyer for total consideration of $90 million (including $80 million in cash), subject to customary post-closing adjustments. We intend to use the net cash proceeds from this transaction to repay outstanding borrowings on our credit facility and for general corporate purposes.

We believe that the expected net cash proceeds from the Dequincy Disposition discussed above, together with expected cash flow from operations and borrowings available under our amended Credit Facility combined with our commodity derivative contracts currently in place, will be sufficient to fund our current capital spending plans through 2015. However, a sustained material decline in oil, NGL and natural gas prices or a reduction in our oil and natural gas production and reserves would reduce our ability to fund our capital expenditure program and negatively impact our liquidity. We plan to continue pursuing additional strategic options that would improve our financial flexibility and provide additional long-term liquidity, including the sale of other non-core assets and possibly joint-ventures or farm-outs on our properties. Discussions are in various states of progress with a variety of interested third parties regarding assets sales or potential joint-ventures, but we are currently unable to predict the timing of any transaction and no assurance can be given that we will reach any agreement with a potential counterparty.

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 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

Our credit facility consists of a $750 million senior revolving credit facility (the “Credit Facility”) with a borrowing base supported by our Mississippian Lime and Anadarko Basin oil and gas assets. On September 30, 2014, we entered into an Assignment and Borrowing Base Increase Agreement that increased the borrowing base under the Credit Facility from $475 million to $525 million. At September 30, 2014, outstanding letters of credit obligations total $1.4 million.

The Credit Facility matures on May 31, 2018 and borrowings thereunder are secured by substantially all of our oil and natural gas properties and bear interest at LIBOR plus an applicable margin, depending upon our borrowing base utilization, between 2.00% and 3.00% per annum. At September 30, 2014 and 2013, the weighted average interest rate was 2.8% and 2.5%, respectively.

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

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

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

The Credit Facility contains, among other standard affirmative and negative covenants, financial covenants including a maximum ratio of debt to EBITDA (i.e. leverage ratio) and a minimum current ratio (as defined therein) of not less than 1.0 to 1.0. We are required to maintain a leverage ratio of not more than 4.75 to 1.00 for the quarters ending September 30, 2014 and December 31, 2014, and 4.00 to 1.00 for each quarter thereafter.

As of September 30, 2014, we were in compliance with the minimum current ratio and the ratio of debt to EBITDA covenants as set forth in the Credit Facility. Our current ratio at September 30, 2014 was 1.3 to 1.0. At September 30, 2014, our ratio of debt to EBITDA was 3.6 to 1.0.

2020 Senior Notes

On October 1, 2012, we issued $600 million in aggregate principal amount of 10.75% senior notes due 2020 (the “2020 Senior Notes”) in a private placement conducted pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended (the “Securities Act”). The 2020 Senior Notes were co issued on a joint and several basis by us and our wholly owned subsidiary, Midstates Sub. We do not have any operations or independent assets other than our 100% ownership interest in Midstates Sub and we have no other subsidiaries. The 2020 Senior Notes Indenture does not create any restricted assets within Midstates Sub, nor does it impose any significant restrictions on the ability of Midstates Sub to pay dividends or make loans to us or limit our ability to advance loans to Midstates Sub.

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

2021 Senior Notes

On May 31, 2013, we issued $700 million in aggregate principal amount of 9.25% senior notes due 2021 (the “2021 Senior Notes. The proceeds from the offering of $700 million (net of the initial purchasers’ discount and related offering expenses) were used to fund the Anadarko Basin Acquisition and the related expenses, to pay the expenses related to an amendment to the Company’s revolving credit facility, to repay $34.3 million in outstanding borrowings under our Credit Facility, and for general corporate purposes.

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

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

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

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our consolidated cash flows from operating, investing and financing activities for the periods presented. For information regarding the individual components of our cash flow amounts, please refer to the Unaudited Condensed Consolidated Statements of Cash Flows included under Item 1 of this quarterly report.

Our operating cash flows are sensitive to a number of variables, the most significant of which is the volatility of oil and gas prices. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of these commodities. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “Item 3. — Quantitative and Qualitative Disclosures About Market Risk” beginning on page 38.

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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,
	2014			2013
Net cash provided by operating activities	$	312,067		$	179,941
Net cash used in investing activities	(284,833		)	(1,059,269		)
Net cash (used in) provided by financing activities	(34,680		)	885,403

Net change in cash	$	(7,446	)	$	6,075

Cash flows provided by operating activities

Net cash provided by operating activities was $312.1 million and $179.9 million for the nine months ended September 30, 2014 and 2013, respectively. The increase in net cash provided by operating activities was primarily the result of an increase in oil and natural gas revenues attributable to higher production and favorable working capital changes, partially offset by lower realized commodity prices.

Cash flows used in investing activities

Net cash used in investing activities was $284.8 million and $1.1 billion during the nine months ended September 30, 2014 and 2013, respectively. During the nine months ended September 30, 2014, $435.3 million was spent on our drilling program, offset by $147.5 million in proceeds received for the Pine Prairie Disposition and $3.0 million in proceeds received related to the Exploration Agreement with PetroQuest. During the nine months ended September 30, 2013, $437.5 million was spent on our drilling program and $621.7 million for the Anadarko Basin Acquisition.

Cash flows (used in) provided by financing activities

Net cash used in financing activities was $34.7 million for the nine months ended September 30, 2014, compared to $885.4 million provided by financing activities for the nine months ended September 30, 2013. During the nine months ended September 30, 2014, we had draws on the revolver of $99.0 million and repayments of $131.0 million. During nine months ended September 30, 2013, cash was sourced through the revolving credit facility, with draws of $246.5 million and repayments of $34.3 million, and $700 million from the 2021 Senior Notes placed in May 2013.

Critical Accounting Policies and Estimates

A discussion of our critical accounting policies and estimates is included in our Annual Report on Form 10-K for the year ended December 31, 2013. There have been no material changes to those policies.

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

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Other Items

Contractual Obligations

The following table summarizes our contractual obligations as of September 30, 2014 (in thousands):

			Payments Due by Period (1)
	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years

Revolving credit facility (2)	$	369,150	$	—	$	369,150	$	—	$	—
2020 Senior Notes (3)	987,000		64,500		193,500		129,000		600,000
2021 Senior Notes (3)	1,137,063		64,750		194,250		129,500		748,563
Drilling contracts (4)	8,575		8,575		—		—		—
Non-cancellable office lease commitments (4)	9,783		1,852		5,513		1,934		484
Seismic contracts (4)	3,192		3,192		—		—		—
Asset retirement obligations (5)	20,935		—		—		—		20,935
Net minimum commitments	$	2,535,698	$	142,869	$	762,413	$	260,434	$	1,369,982

(1) Less than one year includes commitments from October 2014 through September 2015; 1 to 3 years includes commitments from October 2015 through September 2018; 3 to 5 years includes commitments from October 2018 through September 2020; and 5+ years includes commitments from October 2020 and beyond.

(2) Amount excludes interest on our revolving credit facility as both the amount borrowed and applicable interest rates are variable. As of September 30, 2014, we had $369.2 million of indebtedness outstanding under our revolving credit facility. See Note 9 to our unaudited condensed consolidated financial statements.

(3) Amount includes approximately $64.5 million and $64.8 million of interest per year for our 2020 Senior Notes and 2021 Senior Notes, respectively; see Note 9 to our unaudited condensed consolidated financial statements.

(4) See Note 13 to our unaudited condensed consolidated financial statements for a description of drilling contract, operating lease and seismic contract obligations.

(5) Amounts represent our estimate of future asset retirement obligations on a discounted basis. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environments.

Off-Balance Sheet Arrangements

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

Recent Accounting Pronouncements

We reviewed recently issued accounting pronouncements that became effective during the nine months ended September 30, 2014, and determined that none would have a material impact on our condensed consolidated financial statements, with the exception of ASU 2014-09, “Revenue from Contracts with Customers” and ASU 2014-15, “Presentation of Financial Statements — Going Concern,” (both effective for annual reporting periods beginning after December 15, 2016), which we are still evaluating.

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

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We utilize derivative financial instruments to manage risks related to changes in oil prices. As of September 30, 2014, we utilized fixed price swaps, collars and basis differential swaps to reduce the volatility of oil prices on a portion of our future expected oil production.

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

The following is a summary of our commodity derivative contracts as of September 30, 2014:

	Hedged Volume	Weighted-Average Fixed Price

Oil (Bbls):
WTI Swaps — 2014	1,097,000				$	89.04
WTI Swaps — 2015	2,908,000				$	89.42

WTI Collars — 2014	40,200	$	86.49	-	$	97.71

WTI to LLS Basis Differential Swaps — 2014 (1)	91,500				$	5.35

Natural Gas (MMBtu):
Swaps — 2014 (2)	4,508,000				$	4.17
Swaps — 2015	18,250,000				$	4.13

Collars — 2014	194,001	$	3.39	-	$	4.57

(1) The Company enters into swap arrangements intended to fix the differential between the Louisiana Light Sweet (“LLS”) pricing and the West Texas Intermediate (“NYMEX WTI”) pricing.

(2) Includes 1,519,000 MMBtus in natural gas swaps that priced during the period, but had not cash settled as of September 30, 2014.

	For the Nine Months Ended September 30, 2014
	(in thousands)
Derivative fair value at period end - asset (included in balance sheet)	$	5,239
Realized net loss (included in the statement of operations)	$	(39,213	)
Unrealized net gain (included in the statement of operations)	$	36,051

At September 30, 2014 and December 31, 2013, 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.

In October 2014, the Company entered into additional commodity derivative transactions. On November 4, 2014 the Company had the following open commodity positions:

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	Hedged Volume	Weighted-Average Fixed Price

Oil (Bbls):
WTI Swaps — 2014	1,097,000				$	89.04
WTI Swaps — 2015	3,276,000				$	88.72

WTI Collars — 2014	40,200	$	86.49	-	$	97.71

WTI to LLS Basis Differential Swaps — 2014	91,500
					$	5.35
Natural Gas (MMBtu):
Swaps — 2014	4,508,000
Swaps — 2015	18,250,000				$	4.17
					$	4.13
Collars — 2014	194,001	$	3.39	-	$	4.57

Interest Rate Risk. At September 30, 2014, we had indebtedness outstanding under our credit facility of $369.2 million, which bore interest at floating rates, we had $600 million outstanding in 2020 Senior Notes (placed October 1, 2012), which bore interest at 10.75%, and we had $700 million outstanding in 2021 Senior Notes (placed May 31, 2013), which bore interest at 9.25%. The average annual interest rate incurred on the credit facility for the three months ended September 30, 2014 and 2013 was 2.8% and 2.5%, respectively. The average annual interest rate incurred on the credit facility for the nine months ended September 30, 2014 and 2013 was 2.8% and 2.5%, respectively.

A 1.0% increase in each of the average LIBOR and federal funds rate for the three months ended September 30, 2014 and 2013 would have resulted in an estimated $0.9 million and $0.7 million, respectively, increase in interest expense, of which a portion may be capitalized. A 1.0% increase in each of the average LIBOR and federal funds rate for the nine months ended September 30, 2014 and 2013 would have resulted in an estimated $2.8 million and $1.6 million, respectively, increase in interest expense, of which a portion may be capitalized.

We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. At September 30, 2014, we do not have any interest rate derivatives in place. In the future, we may utilize interest rate derivatives to mitigate our exposure to change in interest rates. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

During the period covered by this report, our management carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Our disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports we file with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to our management, including our Interim President and Chief Executive Officer and our Senior Vice President and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of September 30, 2014, these disclosure controls and procedures were not effective and did not ensure that the information required to be disclosed in our reports filed with the SEC is recorded, processed, summarized and reported on a timely basis, due to the existence of a material weakness identified as of December 31, 2013 as discussed below.

During the fourth quarter of 2013, management performed a comprehensive assessment of the design and operating effectiveness of internal control over financial reporting. In performing the assessment, management concluded that a material weakness existed in the Company’s internal controls over the preparation of oil and gas reserve estimates. Specifically, controls were not operating effectively over the validation of the accuracy and completeness of certain source data provided to the independent third party reserve engineers, or the performance of adequate management review of the independent third party reserves report to determine if reserves estimates were complete and consistent with management’s capital spending plans. These control deficiencies resulted in errors that, if not corrected, would have resulted in the misstatement of disclosures related to the value of oil and gas properties and associated reserves estimates, which impacts our calculation of depletion of the cost of our oil and gas properties and the amount of our impairment of oil and gas properties, and the standardized measures of oil and gas.

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Changes in Internal Control over Financial Reporting

During the quarter ended September 30, 2014, we have made changes in our internal control over financial reporting (specifically over the preparation of oil and gas reserve estimates) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We are continuing our efforts to strengthen our internal control over the preparation of oil and gas reserve estimates; however, our remediation efforts are not yet complete. Therefore, management has concluded that a material weakness continues to exist in our internal controls over financial reporting.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings

See Part I, Item 1, Note 13 to our unaudited condensed consolidated financial statements entitled “Commitments and Contingencies - Litigation,” which is incorporated in this item by reference.

Item 1A. Risk Factors

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

Risk factors relating to us are contained below and in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2013.

We could experience disruptions to our operations and difficulties retaining employees as a result of the expected relocation of our corporate headquarters.

The Company plans to relocate its corporate headquarters from Houston, Texas to Tulsa, Oklahoma in early 2015. The process of moving our headquarters is inherently complex and not part of our day to day operations. Thus, that process could cause significant disruption to our operations and cause the temporary diversion of management resources, all of which could have a material adverse effect on our business. We are in the process of developing a transition plan to provide for the move of the corporate operations, including relocation benefits for employees who may be transferring, and severance and retention benefits for employees who will not be continuing with the Company after the move. As part of the relocation, severance and retention plans, there will likely be an increase in general and administrative expenses in the fourth quarter of 2014 and the first quarter of 2015.

We may encounter difficulties retaining employees who would be requested to transfer to Tulsa. As a result of the larger amount of oil and gas activity in Houston as compared to Tulsa, our employees may pursue other opportunities in Houston rather than relocation. Similarly, we may have issues attracting new talent in Tulsa to replace our employees in Houston who are unwilling to relocate.

Item 6. Exhibits

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

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	MIDSTATES PETROLEUM COMPANY, INC.

Dated: November 6, 2014	/s/ Dr. Peter J. Hill
	Dr. Peter J. Hill
	Interim President and Chief Executive Officer
	(Principal Executive Officer)

Dated: November 6, 2014	/s/ Nelson M. Haight
	Nelson M. Haight
	Senior Vice President and Chief Financial Officer
	(Principal Financial and Accounting Officer)

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EXHIBIT INDEX

2.1		Master Reorganization Agreement, dated April 24, 2012, by and among the Company and certain of its affiliates, certain members of the Company’s management and certain affiliates of First Reserve Corporation (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on April 25, 2012, and incorporated herein by reference).
2.2		Purchase and Sale Agreement, dated as of April 3, 2013, by and among Midstates Petroleum Company LLC, Panther Energy Company, LLC, Red Willow Mid-Continent, LLC and Linn Energy Holdings, LLC (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on April 4, 2013, and incorporated herein by reference).
2.3		Purchase and Sale Agreement, dated as of March 5, 2014, by and among Midstates Petroleum Company LLC and Tana Exploration Company LLC (filed as Exhibit 2.1 to the Company’s Form 8-K filed on March 11, 2014 and incorporated herein by reference).
2.4		Purchase and Sale Agreement, dated as of October 2, 2014, by and among Midstates Petroleum Company LLC and Baseline Energy Resources, LLC (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on October 7, 2014, and incorporated herein by reference).
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 by reference.)
3.3		Amended and Restated Bylaws of Midstates Petroleum Company, Inc. (filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on April 25, 2012, and incorporated herein by reference).
3.4		Certificate of Designations of Series A Mandatorily Convertible Preferred Stock of Midstates Petroleum Company, Inc. (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on October 2, 2012, and incorporated herein by reference).
4.1		Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-1/A on February 29, 2012, and incorporated herein by reference).
4.2		Indenture, dated October 1, 2012, by and among the Company, Midstates Petroleum Company LLC and Wells Fargo Bank, National Association, as trustee, governing the 10.75% senior notes due 2020 (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on October 2, 2012, and incorporated herein by reference).
4.3		Registration Rights Agreement, dated October 1, 2012, by and among the Company, Midstates Petroleum Company LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers named therein, relating to the 10.75% senior notes due 2020 (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on October 2, 2012, and incorporated herein by reference).
4.4		Registration Rights Agreement, dated October 1, 2012, by and among the Company, Eagle Energy Production, LLC, FR Midstates Interholding, LP and certain other of the Company’s stockholders (filed as Exhibit 4.3 to the Company’s Current Report on Form 8-K filed on October 2, 2012, and incorporated herein by reference).
4.5		Indenture, dated May 31, 2013, by and among the Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC and the Well Fargo Bank, National Association, as trustee, governing the 9.25% senior notes due 2021 (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on June 3, 2013, and incorporated herein by reference).
4.6		Registration Rights Agreement, dated May 31, 2013, by and among the Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC and Morgan Stanley & Co. LLC and SunTrust Robinson Humphrey, Inc., as representatives of the several initial purchasers named therein, relating to the 9.25% senior notes due 2021 (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on June 3, 2013, and incorporated herein by reference).

10.1		Assignment and Borrowing Base Agreement, with respect to the Second Amended and Restated Credit Agreement, dated as of June 8, 2012, by and among Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC, SunTrust Bank as administrative agent and the other lender parties thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 2, 2014 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