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 June 30, 2015

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

For the transition period from to

Commission File Number: 001-35512

MIDSTATES PETROLEUM COMPANY, INC.

(Exact name of registrant as specified in its charter)

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

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

(918) 947-8550

(Registrant’s telephone number, including area code)

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

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

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

Large accelerated filer o		Accelerated filer x

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

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

The number of shares outstanding of our common stock at August 3, 2015 is shown below:

Class		Number of shares outstanding
Common stock, $0.01 par value		6,889,043

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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)

	June 30, 2015			December 31, 2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	151,037		$	11,557
Accounts receivable:
Oil and gas sales	67,338			69,161
Joint interest billing	19,484			42,407
Other	16,758			22,193
Commodity derivative contracts	35,858			126,709
Other current assets	2,388			1,098
Total current assets	292,863			273,125

PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of full-cost accounting	3,558,960			3,442,681
Other property and equipment	14,734			13,454
Less accumulated depreciation, depletion, amortization and impairment	(2,119,458		)	(1,333,019		)
Net property and equipment	1,454,236			2,123,116

OTHER ASSETS:
Deferred income taxes	9,579			35,821
Other noncurrent assets	39,560			43,731
Total other assets	49,139			79,552

TOTAL	$	1,796,238		$	2,475,793

LIABILITIES AND EQUITY (DEFICIT)
CURRENT LIABILITIES:
Accounts payable	$	8,818		$	22,783
Accrued liabilities	155,221			183,831
Commodity derivative contracts	1,867			—
Deferred income taxes	9,579			44,862
Total current liabilities	175,485			251,476

LONG-TERM LIABILITIES:
Asset retirement obligations	17,737			21,599
Long-term debt	1,924,412			1,735,150
Other long-term liabilities	1,401			1,706
Total long-term liabilities	1,943,550			1,758,455

COMMITMENTS AND CONTINGENCIES (Note 15)

STOCKHOLDERS’ EQUITY (DEFICIT):
Preferred stock, $0.01 par value, 49,675,000 shares authorized; no shares issued or outstanding	—			—
Series A mandatorily convertible preferred stock, $0.01 par value, $403,320 and $387,808 liquidation value at June 30, 2015 and December 31, 2014, respectively; 8% cumulative dividends; 325,000 shares issued and outstanding	3			3
Common stock, $0.01 par value, 100,000,000 shares authorized; 7,257,007 shares issued and 7,164,968 shares outstanding at June 30, 2015 and 7,049,173 shares issued and 6,995,705 shares outstanding at December 31, 2014	73			70
Treasury stock	(3,021		)	(2,592		)
Additional paid-in-capital	886,284			882,528
Retained deficit	(1,206,136		)	(414,147		)
Total stockholders’ (deficit) equity	(322,797		)	465,862

TOTAL	$	1,796,238		$	2,475,793

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 June 30,						For the Six Months Ended June 30,
	2015			2014			2015			2014
REVENUES:
Oil sales	$	67,498		$	131,273		$	126,755		$	247,495
Natural gas liquid sales	10,239			23,020			21,249			48,539
Natural gas sales	15,995			24,994			35,167			50,379
Gains (losses) on commodity derivative contracts - net	(19,293		)	(31,467		)	2,079			(54,140		)
Other	315			170			678			379

Total revenues	74,754			147,990			185,928			292,652

EXPENSES:
Lease operating and workover	21,758			19,721			45,020			39,848
Gathering and transportation	3,931			2,940			7,369			5,795
Severance and other taxes	2,505			5,632			6,069			13,279
Asset retirement accretion	390			432			835			929
Depreciation, depletion, and amortization	55,255			71,074			113,683			137,975
Impairment in carrying value of oil and gas properties	498,389			—			673,056			86,471
General and administrative	11,461			13,434			23,115			25,118
Acquisition and transaction costs	251			2,483			251			2,611
Debt restructuring costs	34,398			—			36,141			—
Other	—			609			73			939

Total expenses	628,338			116,325			905,612			312,965

OPERATING INCOME (LOSS)	(553,584		)	31,665			(719,684		)	(20,313		)

OTHER INCOME (EXPENSE):
Interest income	27			9			36			19
Interest expense — net of amounts capitalized	(44,880		)	(33,813		)	(81,382		)	(67,760		)

Total other expense	(44,853		)	(33,804		)	(81,346		)	(67,741		)

LOSS BEFORE TAXES	(598,437		)	(2,139		)	(801,030		)	(88,054		)

Income tax benefit	—			41			9,041			2,311

NET LOSS	$	(598,437	)	$	(2,098	)	$	(791,989	)	$	(85,743	)

Preferred stock dividend	(669		)	(4,806		)	(800		)	(7,426		)
Participating securities - Series A Preferred Stock	—			—			—			—
Participating securities - Non-vested Restricted Stock	—			—			—			—

NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(599,106	)	$	(6,904	)	$	(792,789	)	$	(93,169	)

Basic and diluted net loss per share attributable to common shareholders	$	(88.44	)	$	(1.04	)	$	(117.45	)	$	(14.07	)
Basic and diluted weighted average number of common shares outstanding	6,774			6,645			6,750			6,622

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

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MIDSTATES PETROLEUM COMPANY, INC.

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

(Unaudited)

(In thousands)

	Series A Preferred Stock		Common Stock		Treasury Stock			Additional Paid-in-Capital		Retained Deficit			Total Stockholders’ Equity (Deficit)
Balance as of December 31, 2014	$	3	$	70	$	(2,592	)	$	882,528	$	(414,147	)	$	465,862
Share-based compensation	—		3		—			3,756		—			3,759
Acquisition of treasury stock	—		—		(429		)	—		—			(429		)
Net loss	—		—		—			—		(791,989		)	(791,989		)
Balance as of June 30, 2015	$	3	$	73	$	(3,021	)	$	886,284	$	(1,206,136	)	$	(322,797	)

	Series A Preferred Stock		Common Stock		Treasury Stock			Additional Paid-in-Capital		Retained Deficit			Total Stockholders’ Equity
Balance as of December 31, 2013	$	3	$	69	$	(664	)	$	871,667	$	(531,076	)	$	339,999
Share-based compensation	—		2		—			4,816		—			4,818
Acquisition of treasury stock	—		—		(1,491		)	—		—			(1,491		)
Net loss	—		—		—			—		(85,743		)	(85,743		)
Balance as of June 30, 2014	$	3	$	71	$	(2,155	)	$	876,483	$	(616,819	)	$	257,583

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)

	Six Months Ended June 30,
	2015			2014

CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(791,989	)	$	(85,743	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Losses (gains) on commodity derivative contracts — net	(2,079		)	54,140
Net cash received (paid) for commodity derivative contracts not designated as hedging instruments	94,797			(31,948		)
Asset retirement accretion	835			929
Depreciation, depletion, and amortization	113,683			137,975
Impairment in carrying value of oil and gas properties	673,056			86,471
Share-based compensation, net of amounts capitalized to oil and gas properties	2,897			3,668
Deferred income taxes	(9,041		)	(2,311		)
Amortization of deferred financing costs	8,356			4,197
Paid-in-kind interest expense	1,187			—
Amortization of deferred gain on debt restructuring	(1,775		)	—
Transaction costs for debt restructuring	34,398			––
Change in operating assets and liabilities:
Accounts receivable — oil and gas sales	139			(998		)
Accounts receivable — JIB and other	22,617			(1,557		)
Other current and noncurrent assets	(1,275		)	(1,094		)
Accounts payable	(2,793		)	4,756
Accrued liabilities	(4,058		)	4,365
Other	(305		)	711
Net cash provided by operating activities	$	138,650		$	173,561

CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment	(190,278		)	(275,547		)
Proceeds from the sale of oil and gas properties	40,284			147,519
Net cash used in investing activities	$	(149,994	)	$	(128,028	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from second lien notes	625,000			—
Proceeds from revolving credit facility	33,000			84,000
Repayment of revolving credit facility	(468,150		)	(131,000		)
Deferred financing costs	(4,199		)	(545		)
Transaction costs for debt restructuring	(34,398		)	—
Acquisition of treasury stock	(429		)	(1,491		)
Net cash provided by (used in) financing activities	$	150,824		$	(49,036	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	139,480			(3,503		)

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

Cash and cash equivalents, end of period	$	151,037		$	29,660

SUPPLEMENTAL INFORMATION:
Non-cash investment in property and equipment	$	61,728		$	115,000
Non-cash exchange of third lien notes for 2020 senior notes and 2021 senior notes	524,121			—
Cash paid for interest, net of capitalized interest of $2.1 million and $8.0 million, respectively	71,569			63,383

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 (“NGLs”) and natural gas. Midstates Petroleum Company, Inc. was incorporated pursuant to the laws of the State of Delaware on October 25, 2011 to become a holding company for Midstates Petroleum Company LLC (“Midstates Sub”), which was previously a wholly owned subsidiary of Midstates Petroleum Holdings LLC (“Holdings LLC”). The terms “Company,” “we,” “us,” “our,” and similar terms refer to Midstates Petroleum Company, Inc. and its subsidiary, unless the context indicates otherwise.

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

2. Liquidity and Capital Resources

As a result of substantial declines in oil, natural gas liquids and natural gas prices during the latter half of 2014 and continuing into 2015, we expect lower operating cash flows than previously experienced and if commodity prices continue to remain low, our liquidity will be impacted as current hedging contracts expire. During the three and six months ended June 30, 2015, the Company received cash payments on settled derivative contracts of $42.2 million and $94.8 million, respectively. The weighted average fixed price of the Company’s derivatives for the second half of 2015 are lower than the weighted average fixed price for the first half of 2015, and the Company currently has no derivatives for any period subsequent to 2015. As such, the cash payments received during the first half of 2015 could significantly decrease in the second half of 2015, and such cash payments will not be received in 2016 and future periods due to the expiration of our hedging contracts.

The interest payment obligations of the Company are substantial and the uncertainty associated with the Company’s ability to meet commitments as they come due or to repay outstanding debt raises substantial doubt about the Company’s ability to continue as a going concern. The Company received a going concern qualification from its independent registered public accounting firm for the year ended December 31, 2014, but obtained a waiver to the reserve based revolving credit facility (“the Credit Facility”) waiving any default as a result of receiving such qualification. The accompanying financial statements do not include any adjustments that might result from the uncertainty associated with the Company’s ability to meet obligations as they come due.

As a result of the commodity price decline and the Company’s substantial debt burden, the Company took steps to increase its liquidity and amended certain debt covenants. On April 21, 2015, the Company closed on the sale of certain of its oil and gas properties in Beauregard and Calcasieu Parishes, Louisiana (the “Dequincy Divestiture”), for approximately $44.0 million, before customary post-closing adjustments. The net proceeds from the Dequincy Divestiture were retained for general corporate purposes. On May 21, 2015, the Company sold $625.0 million of 10.0% Second Lien Senior Secured Notes due 2020 (the “Second Lien Notes”) and utilized the proceeds to repay the outstanding balance of the Credit Facility of approximately $468.2 million, with the remainder to be utilized for general corporate purposes. Further, the Company exchanged approximately $504.1 million of 12.0% Third Lien Senior Secured Notes due 2020 (the “Third Lien Notes”) for approximately $279.8 million of 10.75% Senior Unsecured Notes due 2020 (the “2020 Senior Notes”) and $350.3 million of 9.25% Senior Unsecured Notes due 2021 (the “2021 Senior Notes” together with the 2020 Senior Notes, the “Unsecured Notes”), representing an exchange at 80.0% of the exchanged Unsecured Notes’ par value. Additionally, on June 2, 2015, the Company exchanged approximately $20.0 million of Third Lien Notes for approximately $26.6 million of 2020 Senior Notes and $2.0 million of 2021 Senior Notes, representing an exchange at 70.0% of the exchanged Unsecured Notes’ par value. The Company also entered into a Seventh Amendment to the Credit Facility (“Seventh Amendment”) which provided that upon completion of the Second Lien Notes and Third Lien Notes exchange, the borrowing base of the Credit Facility would be reduced to $252.4 million. The Seventh Amendment also provided additional covenant flexibility. For further information regarding the Second Lien Notes, Third Lien Notes and updates to the Company’s debt covenants, see “— Note 10. Long-Term Debt.” The Dequincy Divestiture, the issuance of the Second Lien Notes and the exchange of the Third Lien Notes increased the Company’s cash balance, increased the amount of borrowings available under the Credit Facility and as a result, increased the liquidity of the Company.

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Correction of Operating and Investing Cash Flows for the Six Months Ended June 30, 2014

In the first quarter of 2015, the Company determined that it had incorrectly presented non-cash accrued capital expenditures in its Statements of Cash Flows since December 31, 2012. Management concluded the misstatement is immaterial to previously issued financial statements; however, the Company has corrected the cash flow presentation in the accompanying Condensed Consolidated Statement of Cash Flows for the six months ended June 30, 2014. There was no impact of the misstatement on the Condensed Consolidated Balance Sheet as of December 31, 2014, or on the Condensed Consolidated Statement of Operations for the three or six months ended June 30, 2014. The impact of the correction is shown in the following table (in thousands):

	For the Six Months Ended June 30, 2014
Statement of Cash Flows	As Previously Reported			As Restated

Change in operating assets and liabilities: accounts receivable - JIB and other	$	1,929		$	(1,557	)
Net cash provided by operating activities	177,047			173,561

Investment in property and equipment	(279,033		)	(275,547		)
Net cash used in investing activities	(131,514		)	(128,028		)

4. Fair Value Measurements of Financial Instruments

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Derivative Instruments

Commodity derivative contracts reflected in the condensed consolidated balance sheets are recorded at estimated fair value. At June 30, 2015 and December 31, 2014, all of the Company’s commodity derivative contracts were with seven bank counterparties, and were classified as Level 2 in the fair value input hierarchy.

Derivative instruments listed below are presented gross and consist of swaps that are carried at fair value. The Company records the net change in the fair value of these positions in “Gains (losses) on commodity derivative contracts — net” in the Company’s unaudited condensed consolidated statements of operations. See “— Note 5. Risk Management and Derivative Instruments” for additional information on the Company’s derivative instruments and balance sheet presentation.

	Fair Value Measurements at June 30, 2015
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in thousands)
Assets:
Commodity derivative oil swaps	$	—	$	27,708	$	—	$	27,708
Commodity derivative gas swaps	—		9,152		—		9,152
Total assets	$	—	$	36,860	$	—	$	36,860

Liabilities:
Commodity derivative oil swaps	$	—	$	2,869	$	—	$	2,869
Commodity derivative gas swaps	—		—		—		—
Total liabilities	$	—	$	2,869	$	—	$	2,869

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

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

5. Risk Management and Derivative Instruments

The Company’s production is exposed to fluctuations in crude oil, 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 June 30, 2015 would have been approximately $35.9 million.

Commodity Derivative Contracts

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

	Hedged	Weighted-Average
	Volume	Fixed Price
Oil (Bbls):
WTI Swaps — 2015	2,208,000	$	71.56

Natural Gas (MMBtu):
Swaps — 2015(1)	9,200,000	$	4.13

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

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Balance Sheet Presentation

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

Type	Balance Sheet Location (1)	June 30, 2015			December 31, 2014
Oil Swaps	Derivative financial instruments — Current Assets	$	27,708		$	106,450
Oil Swaps	Derivative financial instruments — Current Liabilities	(2,869		)	—
Gas Swaps	Derivative financial instruments — Current Assets	9,152			20,259
Total derivative fair value at period end		$	33,991		$	126,709

(1) The fair values of commodity derivative instruments reported in the Company’s condensed consolidated balance sheets are subject to netting arrangements and qualify for net presentation. The following table summarizes the location and fair value amounts of all derivative instruments in the unaudited condensed consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the unaudited condensed consolidated balance sheets at June 30, 2015 and December 31, 2014, respectively (in thousands):

		June 30, 2015
Not Designated as ASC 815 Hedges:	Balance Sheet Classification	Gross Recognized Assets/ Liabilities		Gross Amounts Offset		Net Recognized Fair Value Assets/ Liabilities
Derivative assets:
Commodity contracts	Derivative financial instruments - current	$	36,860	$	1,002	$	35,858
Commodity contracts	Derivative financial instruments - noncurrent	—		—		—
		$	36,860	$	1,002	$	35,858
Derivative liabilities:
Commodity contracts	Derivative financial instruments - current	$	2,869	$	1,002	$	1,867
Commodity contracts	Derivative financial instruments - noncurrent	—		—		—
		$	2,869	$	1,002	$	1,867

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

Gains (losses) on Commodity Derivative Contracts

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

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2015			2014			2015			2014
	(in thousands)						(in thousands)
Net cash received (paid) for commodity derivative contracts	$	42,189		$	(17,138	)	$	94,797		$	(31,948	)
Unrealized net gains (losses)	(61,482		)	(14,329		)	(92,718		)	(22,192		)
Gains (losses) on commodity derivative contracts - net	$	(19,293	)	$	(31,467	)	$	2,079		$	(54,140	)

6. Property and Equipment

	June 30, 2015			December 31, 2014
	(in thousands)
Oil and gas properties, on the basis of full-cost accounting:
Proved properties	$	3,527,182		$	3,398,146
Unevaluated properties	31,778			44,535
Other property and equipment	14,734			13,454
Less accumulated depreciation, depletion, amortization and impairment	(2,119,458		)	(1,333,019		)
Net property and equipment	$	1,454,236		$	2,123,116

Oil and Gas Properties

The Company capitalizes internal costs directly related to exploration and development activities to oil and gas properties. During the three and six months ended June 30, 2015 and 2014, the Company capitalized the following (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014

Internal costs capitalized to oil and gas properties (1)	$	2,613	$	3,325	$	4,915	$	6,449

(1) Inclusive of $0.4 million and $0.6 million of qualifying share-based compensation expense for the three months ended June 30, 2015 and 2014, respectively. For the six months ended June 30, 2015 and 2014, inclusive of $0.9 million and $1.2 million, 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 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 June 30, 2015, capitalized costs exceeded the ceiling and the Company recorded an impairment of oil and gas properties of $498.4 million. During the six months ended June 30, 2015 and 2014, the Company recorded impairments of oil and gas properties of $673.1 million and $86.5 million, respectively. Impairments at June 30, 2015 and March 31, 2015 were primarily due to continued low commodity prices, which resulted in a reduction of the discounted present value of the Company’s proved oil and natural gas reserves.

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

	Three Months Ended June 30,								Six Months Ended June 30,
	2015		2014		2015		2014		2015		2014		2015		2014
	(in thousands)				(per Boe)				(in thousands)				(per Boe)
Depletion expense	$	54,359	$	70,323	$	17.63	$	24.22	$	111,964	$	136,527	$	18.18	$	24.76
Depreciation on other property	896		751		0.29		0.25		1,719		1,448		0.28		0.26
Depreciation, depletion, and amortization	$	55,255	$	71,074	$	17.92	$	24.47	$	113,683	$	137,975	$	18.46	$	25.02

Oil and gas unevaluated properties and properties under development include costs that are not being depleted or amortized. These costs represent investments in unproved properties. The Company excludes these costs until proved reserves are found, until it is determined that the costs are impaired or until major development projects are placed in service, at which time the costs are moved into oil and natural gas properties subject to amortization. All unproved property costs are reviewed at least quarterly to determine if impairment has occurred. Unevaluated property was $31.8 million and $44.5 million at June 30, 2015 and December 31, 2014, respectively.

Other Property and Equipment

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

Sale of Dequincy Assets

On April 21, 2015, the Company closed on the sale of its ownership interest in developed and undeveloped acreage in the Dequincy area located in Beauregard and Calcasieu Parishes, Louisiana for $44.0 million to Pintail Oil and Gas LLC. The net proceeds of approximately $42.4 million, which was net of customary closing adjustments, was reflected as a reduction of oil and natural gas properties, with no gain or loss recognized. The proceeds from the sale have been and will continue to be used for general corporate purposes.

7. Other Noncurrent Assets

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

	June 30, 2015		December 31, 2014
	(in thousands)
Deferred financing costs	$	33,483	$	37,807
Field inventory	5,911		5,713
Other	166		211
Other noncurrent assets	$	39,560	$	43,731

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

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8. Accrued Liabilities

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

	June 30, 2015		December 31, 2014
	(in thousands)
Accrued oil and gas capital expenditures	$	54,674	$	76,398
Accrued revenue and royalty distributions	44,411		51,292
Accrued lease operating and workover expense	17,250		10,113
Accrued interest	23,567		21,521
Accrued taxes	4,427		4,226
Other	10,892		20,281
Accrued liabilities	$	155,221	$	183,831

9. Asset Retirement Obligations

Asset Retirement Obligations (“AROs”) represent the future abandonment costs of tangible assets, such as wells, service assets and other facilities. The fair value of the ARO at inception is capitalized as part of the carrying amount of the related long-lived assets.

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

	Six Months Ended			Six Months Ended
	June 30, 2015			June 30, 2014
	(in thousands)
Asset retirement obligations — beginning of period	$	21,599		$	26,308
Liabilities incurred	2			844
Revisions	—			—
Liabilities settled	—			(47		)
Liabilities eliminated through asset sales	(4,699		)	(7,652		)
Current period accretion expense	835			929
Asset retirement obligations — end of period	$	17,737		$	20,382

10. Long-Term Debt

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

	December 31, 2014 Carrying Value		Borrowings		Repayments			Exchanges			Deferred Gain on Forgiven Debt			Amortization of Forgiven Debt			PIK Interest		June 30, 2015 Carrying Value
Credit Facility	$	435,150	$	33,000	$	(468,150	)	$	—		$	—		$	—		$	—	$	—
2020 Senior Notes	600,000		—		—			(242,445		)	(63,930		)	—			—		293,625
2021 Senior Notes	700,000		—		—			(281,676		)	(70,672		)	—			—		347,652
Second Lien Notes	—		625,000		—			—			47,082			(896		)	—		671,186
Third Lien Notes	—		—		—			524,121			87,520			(879		)	1,187		611,949
Total debt	$	1,735,150	$	658,000	$	(468,150	)	$	—		$	—		$	(1,775	)	$	1,187	$	1,924,412
Current maturities	—		—		—			—			—			—			—		—
Long-term debt	$	1,735,150	$	658,000	$	(468,150	)	$	—		$	—		$	(1,775	)	$	1,187	$	1,924,412

	June 30, 2015 Carrying Value		Unamortized Deferred Gain on Debt Forgiven			June 30, 2015 Principle Balance Outstanding
Revolving Credit Facility	$	—	$	—		$	—
2020 Senior Notes	293,625		—			293,625
2021 Senior Notes	347,652		—			347,652
Second Lien Notes	671,186		(46,186		)	625,000
Third Lien Notes	611,949		(86,641		)	525,308
Total debt	$	1,924,412	$	(132,827	)	$	1,791,585
Current maturities	—		—			—
Long-term debt	$	1,924,412	$	(132,827	)	$	1,791,585

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Debt Restructuring

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

Additionally, the Company and Midstates Sub entered into the Seventh Amendment to the Credit Facility which provided that upon completion of the offering of the Second Lien Notes and exchange of Third Lien Notes, the borrowing base of the Credit Facility would be reduced to $252.4 million. The Seventh Amendment also provided additional covenant flexibility. Further discussion regarding the Second Lien Notes, Third Lien Notes and Seventh Amendment can be found below. The exchanges of Third Lien Notes for the Unsecured Notes as well as the issuance of the Second Lien Notes were accounted for as a troubled debt restructuring. As the future cash flows of the modified debt instruments are greater than the carrying amount of the previous debt instruments, no gain was recognized. The amount of extinguished debt will be amortized and recognized as a reduction of interest expense over the remaining life of the Second Lien Notes and Third Lien Notes using the effective interest method. As a result, the Company’s reported interest expense will be significantly less than the contractual interest payments throughout the term of Second Lien Notes and Third Lien Notes. All costs incurred, including restructuring costs as well as the direct issuance costs of the Second Lien Notes and Third Lien Notes, were expensed and are included within debt restructuring costs in our condensed consolidated statements of operations.

Reserve-based Credit Facility

The Company maintains a $750.0 million Credit Facility with a borrowing base of $252.4 million supported by the Company’s Mississippian Lime and Anadarko Basin oil and gas assets. At June 30, 2015, the Company had no amounts drawn on the Credit Facility and had outstanding letters of credit obligations totaling $1.5 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 June 30, 2015 and 2014, the weighted average interest rate was 2.9% and 2.8%, respectively.

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

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 any amount by which the principal balance of its outstanding loans and its letter of credit obligations exceed its redetermined borrowing base or grant liens on additional property having sufficient value to eliminate such excess. The Company is permitted to make such repayment in six equal successive monthly payments commencing 30 days following the administrative agent’s notice regarding such borrowing base reduction.

On March 24, 2015, the Company and Midstates Sub entered into a Sixth Amendment (the “Sixth Amendment”) to the Credit Facility. The Sixth Amendment amended the required ratio of net consolidated indebtedness to EBITDA under the Credit Agreement for each of the fiscal quarters in 2015 from 4.0:1.0 to 4.5:1.0. Additionally, the Sixth Amendment amended the mortgage requirements under the Credit Facility to provide for an increase from 80% to 90% for the percentage of properties included in the borrowing base that are required to be subject to mortgages for the benefit of the lenders.

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On May 21, 2015, the Company and Midstates Sub entered into a Seventh Amendment (the “Seventh Amendment”) to the Credit Facility. The Seventh Amendment provided that, with the completion of the offering of the Second Lien Notes and Third Lien Notes (both discussed below), the Company’s borrowing base would be reduced to approximately $252.4 million. The Seventh Amendment also eliminated the required ratio of net consolidated indebtedness to EBITDA covenant and added a ratio of Total Senior Indebtedness (as defined therein) to EBITDA of not more than 1.0:1.0, which is further discussed below under “— Debt Covenants.” The next scheduled redetermination of the borrowing base is October 2015.

2020 Senior Notes

On October 1, 2012, the Company issued $600 million in aggregate principal amount of 2020 Senior Notes conducted pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended (the “Securities Act”). In October 2013, these notes were exchanged for an equal principal amount of identical registered notes. The 2020 Senior Notes rank pari passu in right of payment with the 2021 Senior Notes, the Second Lien Notes and Third Lien Notes. The 2020 Senior Notes were co-issued on a joint and several basis by the Company and its wholly owned subsidiary, Midstates Sub. The Company does not have any operations or independent assets other than its 100% ownership interest in Midstates Sub and there are no other subsidiaries of the Company. The indenture governing the 2020 Senior Notes (the “2020 Senior Notes Indenture”) does not create any restricted assets within Midstates Sub, nor does it impose any significant restrictions on the ability of Midstates Sub to pay dividends or make loans to the Company or limit the ability of the Company to advance loans to Midstates Sub.

At any time prior to October 1, 2015, the Company may, under certain circumstances, redeem up to 35% of the aggregate principal amount of the 2020 Senior Notes with the net proceeds of a public or private equity offering at a redemption price of 110.75% of the principal amount of the 2020 Senior Notes, plus any accrued and unpaid interest up to the redemption date. In addition, at any time before October 1, 2016, the Company may redeem all or a part of the 2020 Senior Notes at a redemption price equal to 100% of the principal amount of 2020 Senior Notes redeemed plus the Applicable Premium (as defined in the 2020 Senior Notes Indenture) at the redemption date, plus any accrued and unpaid interest, if any, up to the redemption date. On or after October 1, 2016, the Company may redeem all or a part of the 2020 Senior Notes at varying redemption prices (expressed as percentages of principal amount) set forth in the 2020 Senior Notes Indenture plus accrued and unpaid interest, if any, on the 2020 Senior Notes redeemed, up to the redemption date.

Upon the occurrence of certain change of control events, as defined in the 2020 Senior Notes Indenture, each holder of the 2020 Senior Notes will have the right to require that the Company repurchase all or a portion of such holder’s 2020 Senior Notes in cash at a purchase price equal to 101% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

On May 21, 2015 and June 2, 2015, a total of approximately $306.4 million of 2020 Senior Notes were exchanged for Third Lien Notes, as discussed above. The estimated fair value of the 2020 Senior Notes as of June 30, 2015 was $121.1 million (Level 2 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities.

2021 Senior Notes

On May 31, 2013, the Company issued $700 million in aggregate principal amount of 2021 Senior Notes. In October 2013, these notes were exchanged for an equal principal amount of identical registered notes. The 2021 Senior Notes rank pari passu in right of payment with the 2020 Senior Notes, Second Lien Notes and Third Lien Notes. The 2021 Senior Notes were co-issued on a joint and several basis by the Company and its wholly owned subsidiary, Midstates Sub. The indenture governing the 2021 Senior Notes (the “2021 Senior Notes Indenture”) does not create any restricted assets within Midstates Sub, nor does it impose any significant restrictions on the ability of Midstates Sub to pay dividends or make loans to the Company or limit the ability of the Company to advance loans to Midstates Sub.

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Prior to June 1, 2016, the Company may, under certain circumstances, redeem up to 35% of the aggregate principal amount of the 2021 Senior Notes with the net proceeds of any equity offerings at a redemption price of 109.25% of the principal amount of the 2021 Senior Notes redeemed, plus any accrued and unpaid interest, if any, up to the redemption date. In addition, at any time before June 1, 2016, the Company may redeem all or a part of the 2021 Senior Notes at a redemption price equal to 100% of the principal amount of the 2021 Senior Notes redeemed plus the Applicable Premium (as defined in the 2021 Senior Notes Indenture) at the redemption date, plus any accrued and unpaid interest, if any, up to, the redemption date. On or after June 1, 2016, the Company may redeem all or a part of the 2021 Senior Notes at varying redemption prices (expressed as percentages of principal amount) set forth in the 2021 Senior Notes Indenture plus accrued and unpaid interest, if any, on the 2021 Senior Notes redeemed, up to, the redemption date.

Upon the occurrence of certain change of control events, as defined in the 2021 Senior Notes Indenture, each holder of the 2021 Senior Notes will have the right to require that the Company repurchase all or a portion of such holder’s 2021 Senior Notes in cash at a purchase price equal to 101% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

On May 21, 2015 and June 2, 2015, a total of approximately $352.3 million of 2021 Senior Notes were exchanged for Third Lien Notes, as discussed above. The estimated fair value as of June 30, 2015 of the 2021 Senior Notes was $137.8 million (Level 2 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities.

Second Lien Notes

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

On May 21, 2015, in connection with the offering of Second Lien Notes, the Company and Midstates Sub entered into a registration rights agreement with the initial purchasers of the Second Lien Notes pursuant to which the Company and Midstates Sub are obligated, within 270 days after the issuance of the Second Lien Notes, to file with the Securities and Exchange Commission under the Securities Act a registration statement with respect to an offer to exchange the Second Lien Notes for substantially identical registered new notes. The Company will be obligated to pay liquidated damages consisting of additional interest on the Second Lien Notes if, within the periods specified in the agreement, it does not file the exchange offer registration statement or if certain other events occur.

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

Upon the occurrence of certain change of control events, as defined in the indenture governing the Second Lien Notes, each holder of the Second Lien Notes will have the right to require that the Company repurchase all or a portion of such holder’s 2020 Second Lien Notes in cash at a purchase price equal to 101% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

The estimated fair value of the Second Lien Notes was $601.6 million as of June 30, 2015 (Level 2 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities.

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Third Lien Notes

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

On May 21, 2015, in connection with the issuance of the Third Lien Notes, the Company entered into a registration rights agreement with the initial purchasers of the Third Lien Notes pursuant to which the Company is obligated, within 270 days after the issuance of the Third Lien Notes, to file with the Securities and Exchange Commission under the Securities Act a registration statement with respect to an offer to exchange the Third Lien Notes for substantially identical registered new notes. The Company will be obligated to pay liquidated damages consisting of additional interest on the Third Lien Notes if, within the periods specified in the agreement, it does not file the exchange offer registration statement or if certain other events occur.

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

Upon the occurrence of certain change of control events, as defined in the indenture governing the Third Lien Notes, each holder of the Third Lien Notes will have the right to require that the Company repurchase all or a portion of such holder’s Third Lien Notes in cash at a purchase price equal to 101% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

The estimated fair value of the Third Lien Notes was $420.3 million as of June 30, 2015 (Level 2 in the fair value measurement hierarchy), based on quoted market prices for these same debt securities.

Debt Covenants

The indentures governing the 2020 Senior Notes, 2021 Senior Notes, Second Lien Notes and Third Lien Notes contain covenants that, among other things, restrict the Company’s ability to: (i) incur additional indebtedness, guarantee indebtedness or issue certain preferred shares; (ii) make loans, investments and other restricted payments; (iii) pay dividends on or make other distributions in respect of, or repurchase or redeem, capital stock; (iv) create or incur certain liens; (v) sell, transfer or otherwise dispose of certain assets; (vi) enter into certain types of transactions with the Company’s affiliates; (vii) consolidate, merge or sell substantially all of the Company’s assets; (viii) prepay, redeem or repurchase certain debt; (ix) alter the business the Company conducts and (x) enter into agreements restricting the ability of the Company’s current and any future subsidiaries to pay dividends.

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

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Cross Default Provisions

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

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

· The indentures governing the 2020 Senior Notes, 2021 Senior Notes, Second Lien Notes and Third Lien Notes allow the lenders to declare an event of default if there is an event of default on other indebtedness and that default: (i) is caused by a failure to make any payment of principal prior to the expiration of the grace period following the final maturity date of such indebtedness; or (ii) results in the acceleration of such indebtedness prior to its stated maturity, and, in each case, the principal amount of any such indebtedness, together with the principal amount of any other indebtedness with respect to which an event described herein has occurred, aggregates $50.0 million or more.

11. Preferred Stock

Series A Preferred Stock

In connection with the Company’s acquisition of its Mississippian Lime properties, on September 28, 2012, the Company designated 325,000 shares of Series A Mandatorily Convertible Preferred Stock (the “Series A Preferred Stock”) with an initial liquidation preference of $1,000 per share and an 8% per annum dividend, payable semiannually at the Company’s option in cash or through an increase in the liquidation preference. The Series A Preferred Shares are currently convertible in whole but not in part and at the option of the holders of a majority of the outstanding shares of Series A Preferred Stock, into a number of shares of the Company’s common stock calculated by dividing the then-current liquidation preference by the conversion price of $135.00 per share and, if not previously converted, are mandatorily convertible at September 30, 2015 into shares of the Company’s common stock at a conversion price no greater than $135.00 per share and no less than $110.00 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 conversion prices for the Series A Preferred Shares were automatically adjusted to reflect the reverse stock split and the resulting decrease in the number of shares of common stock outstanding. The Series A Preferred Stock was issued on October 1, 2012.

On March 30, 2015, the Company elected to pay the $13.0 million semi-annual dividend due on that date through an increase in the Series A Preferred Stock liquidation preference to $1,241 per share. It is the Company’s intention for the foreseeable future to pay Series A Preferred Share dividends through an adjustment to the liquidation preference. Therefore, for the three months ended June 30, 2015, the $7.9 million Series A Preferred Stock dividend, which the Company intends to pay through the adjustment to the liquidation preference, is based upon the estimated fair value of 71,893 common shares that would have been issued had the Series A Preferred Stock dividend for the three months been converted into common shares at a conversion price of $110.00 per share.

As a result, the Company will be obligated to issue between 580,151 and 712,004 additional shares of common stock upon conversion of the Series A Preferred stock, with the ultimate number of shares dependent upon the conversion price then in effect as described above.

The following table demonstrates the number of shares to be issued upon conversion through June 30, 2015 at the respective conversion rates based upon the current liquidation preference:

	Conversion at $135.00/share	Conversion at $110.00/share

Number of Common Shares Issuable Upon Conversion	2,987,558	3,666,549

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12. Equity and Share-Based Compensation

Share Activity

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

	Number of Shares
	Common Stock		Treasury Stock
Share count as of December 31, 2014	7,049,173		(53,467	)
Grants of restricted stock	268,677		—
Forfeitures of restricted stock	(60,843	)	—
Acquisition of treasury stock	—		(38,572	)
Share count as of June 30, 2015	7,257,007		(92,039	)

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 June 30, 2015, 1,099 incentive units were issued and outstanding. These incentive units were issued prior to the Company’s initial public offering. In connection with the corporate reorganization that occurred immediately prior to the Company’s initial public offering, these incentive units held in the Company 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 incentive units has been recognized by the Company, as any payout under the incentive units is not considered probable, and thus, the amount of FRMI Profits, if any, cannot be determined.

Share-based Compensation

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 656,343 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 863,843 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 June 30, 2015 a total of 863,843 common share Awards are authorized for issuance and shares of stock subject to an Award that expire, or are canceled, forfeited, exchanged, settled in cash or otherwise terminated, will again be available for future Awards under the 2012 LTIP.

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Non-vested Stock Awards

At June 30, 2015, the Company had 377,556 non-vested shares of restricted common stock to directors, management and employees outstanding pursuant to the 2012 LTIP. Shares granted under the LTIP generally vest ratably over a period of three years (one-third on each anniversary of the grant); however, beginning in 2013, shares granted under the 2012 LTIP to directors are subject to one-year cliff vesting.

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

The following table summarizes the Company’s non-vested share award activity for the six months ended June 30, 2015:

	Shares		Weighted Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2014	306,201		$	52.76
Granted	268,677		$	12.29
Vested	(136,479	)	$	57.23
Forfeited	(60,843	)	$	47.06
Non-vested shares outstanding at June 30, 2015	377,556		$	22.76

Unrecognized expense, adjusted for estimated forfeitures, as of June 30, 2015 for all outstanding restricted stock awards was $6.4 million and will be recognized over a weighted average period of 1.8 years.

At June 30, 2015, 170,271 shares remain available for issuance under the terms of the 2012 LTIP.

13. Income Taxes

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

For the six months ended June 30, 2015, the Company’s effective tax rate was a benefit of approximately 1.1%. The Company’s effective tax rate differs from the federal statutory rate of 35% due to the effect of state income taxes and changes in the valuation allowance. This year, the Company recorded $305.9 million in additional valuation allowance in light of the impairment of oil and gas properties bringing the total valuation allowance to $309.7 million at June 30, 2015. A valuation allowance has been recorded as management does not believe that it is more-likely-than-not that the 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.

14. Net Loss Per Share

The Company’s Series A Preferred Stock has the nonforfeitable right to participate on an as converted basis at the conversion rate then in effect in any common stock dividends declared and as such, is considered a participating security. The Company’s nonvested stock awards, which are granted as part of the 2012 LTIP, contain nonforfeitable rights to dividends and as such, are considered to be participating securities and, together with the Series A Preferred Stock, are included in the computation of basic and diluted loss per share, pursuant to the two-class method. In the calculation of basic 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.

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

The following table (in thousands, except per share amounts) provides a reconciliation of net loss to preferred shareholders, common shareholders, and non-vested restricted shareholders for purposes of computing net loss per share for the three and six months ended June 30, 2015 and 2014, respectively:

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Net loss	$	(598,437	)	$	(2,098	)	$	(791,989	)	$	(85,743	)
Preferred Dividend (1)	(669		)	(4,806		)	(800		)	(7,426		)
Net loss attributable to shareholders	$	(599,106	)	$	(6,904	)	$	(792,789	)	$	(93,169	)

Participating securities - Series A Preferred Stock (2)	—			—			—			—
Participating securities - Non-vested Restricted Stock (2)	—			—			—			—
Net loss attributable to common shareholders	$	(599,106	)	$	(6,904	)	$	(792,789	)	$	(93,169	)

Weighted average shares outstanding	6,774			6,645			6,750			6,622
Net loss per share	$	(88.44	)	$	(1.04	)	$	(117.45	)	$	(14.07	)

(1) Calculation of the preferred stock dividend is discussed in “— Note 11. Preferred Stock”

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

The aggregate number of common shares outstanding at June 30, 2015 was 7,257,007 of which 377,556 were non-vested restricted shares. The aggregate number of shares of Series A Preferred Stock outstanding at June 30, 2015 was 325,000, each with a liquidation preference of $1,241 representing on an as-converted basis approximately 3,666,549 common shares based upon a conversion price of $110.00 per share, which have been excluded from the weighted average shares outstanding for EPS purposes for the three and six months ended June 30, 2015 due to their anti-dilutive effect.

15. Commitments and Contingencies

Litigation

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

The Company vigorously defends itself in these matters. If the Company determines that an unfavorable outcome or loss of a particular matter is probable and the amount of the loss can be reasonably estimated, it accrues a liability for the contingent obligation. As new information becomes available or as a result of legal or administrative rulings in similar matters or a change in applicable law, the Company’s conclusions regarding the probability of outcomes and the amount of estimated loss, if any, may change. The impact of subsequent changes to the Company’s accruals could have a material effect on its results of operations.

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and notes thereto for the year ended December 31, 2014, and the related management’s discussion and analysis contained in our annual report on Form 10-K dated and filed with the Securities and Exchange Commission (“SEC”) on March 16, 2015, as well as the unaudited condensed consolidated financial statements and notes thereto included in this quarterly report on Form 10-Q and our quarterly report on Form 10-Q for quarter ended March 31, 2015 filed with the SEC on May 11, 2015.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in or incorporated by reference into this report are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, and the plans, beliefs, expectations, intentions and objectives of management are forward-looking statements. When used in this quarterly report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” and similar expressions are intended to identify forward looking statements, although not all forward looking statements contain such identifying words. In particular, the factors discussed in this report on Form 10-Q and detailed in our annual report filed on Form 10-K dated and filed with the SEC on March 16, 2015, could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements.

Forward-looking statements may include statements about our:

· business strategy;

· estimated future net reserves and present value thereof;

· technology;

· cash flows and liquidity;

· financial strategy, budget, projections and operating results;

· oil and natural gas realized prices;

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

· availability of drilling and production equipment;

· availability of oilfield labor;

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

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

· availability and terms of capital;

· drilling of wells, including our identified drilling locations;

· successful results from our identified drilling locations;

· marketing of oil and natural gas;

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

· infrastructure for salt water disposal and electricity;

· 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 and Kansas with the October 1, 2012 closing of our acquisition (“Eagle Property Acquisition”) of interests in producing oil and natural gas assets and unevaluated leasehold acreage in Oklahoma and Kansas 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 $618.0 million in cash (the “Anadarko Basin Acquisition”), before customary post-closing adjustments. Subsequent to the closing of the Eagle Property Acquisition and the Anadarko Basin Acquisition, the Company has oil and gas operations and properties in Louisiana, Oklahoma and Texas.

We were incorporated pursuant to the laws of the State of Delaware on October 25, 2011 to become a holding company for Midstates Petroleum Company LLC (“Midstates Sub”), a wholly-owned subsidiary of Midstates Petroleum Holdings LLC. With the completion of our initial public offering, we became a publicly traded company. Our common stock is listed on the NYSE under the ticker symbol “MPO.” The terms “Company,” “we,” “us,” “our,” and similar terms, refer to us and our subsidiary, unless the context indicates otherwise.

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

Recent Developments

Debt Restructuring

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

Additionally, we entered into the Seventh Amendment which provided that upon completion of the offering of the Second Lien Notes and Third Lien Notes, the borrowing base of the Credit Facility would be reduced to $252.4 million. The Seventh Amendment also provided additional covenant flexibility. Further discussion regarding the Second Lien Notes, Third Lien Notes and Seventh Amendment can be found below under “—Liquidity and Capital Resources.”

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Dequincy Divestiture

On April 21, 2015, we closed on the sale of ownership interest in developed and undeveloped acreage in the Dequincy area located in Beauregard and Calcasieu Parishes, Louisiana for $44.0 million to Pintail Oil and Gas LLC. The net proceeds of approximately $42.4 million, which is net of customary closing adjustments, was reflected as a reduction of oil and natural gas properties, with no gain or loss recognized. The proceeds from the sale will be used for general corporate purposes. With the Dequincy Divestiture, we no longer have any proved reserves or production in our Gulf Coast operating area.

Risks, Uncertainties and Going Concern

As a result of substantial declines in oil, natural gas liquids and natural gas prices during the latter half of 2014 and continuing into 2015, the liquidity outlook of the Company has been impacted. Decreases in commodity prices directly impact our revenues and associated operating cash flows and consequently our ability to fund our capital program and service our debt. As a result, we expect lower operating cash flows than previously experienced and if commodity prices continue to remain low, our liquidity will be further impacted as current hedging contracts expire. During the three and six months ended June 30, 2015, we received cash payments on settled derivative contracts of $42.2 million and $94.8 million, respectively. Such cash payments will not be received in 2016 and future periods due to the expiration of our hedging contracts.

Our interest payment obligations are substantial and the uncertainty associated with our ability to meet commitments as they come due or to repay outstanding debt raises substantial doubt about our ability to continue as a going concern. We received a going concern qualification from our independent registered public accounting firm for the year ended December 31, 2014, but obtained a waiver to the Credit Facility waiving any default as a result of receiving such qualification. The accompanying financial statements do not include any adjustments that might result from the uncertainty associated with our ability to meet obligations as they come due.

As a result of the commodity price decline and our substantial debt burden, the Company took steps to increase its liquidity and amend certain debt covenants. As discussed above, we completed the Dequincy Divestiture on April 21, 2015, for approximately $42.4 million, net of post-closing adjustments. Additionally, on May 21, 2015, we issued $625.0 million of Second Lien Notes and on May 21, 2015 and June 2, 2015 we exchanged an aggregate of approximately $524.1 million of Third Lien Notes for an aggregate of approximately $306.4 million of 2020 Senior Notes and $352.3 million of 2021 Senior Notes. Approximately $63.9 million of 2020 Senior Notes and $70.7 million of 2021 Senior Notes were extinguished as a result of the exchanges occurring at a percentage of the Unsecured Notes’ par value. For additional detail, please see “—Liquidity and Capital Resources” below.

We also entered into the Seventh Amendment which provided that upon completion of the Second Lien Notes offering and Third Lien Notes exchange, the borrowing base of the Credit Facility would be reduced to $252.4 million. The Seventh Amendment also provided additional covenant flexibility. Further discussion regarding the Second Lien Notes, Third Lien Notes and Seventh Amendment can be found in “— Note 10. Long-Term Debt” to our condensed consolidated financial statements. Additionally, further discussion on liquidity can be found below under “—Liquidity and Capital Resources.”

Operations Update

Mississippian Lime

For the three months ended June 30, 2015 and March 31, 2015, our average daily production from the Mississippian Lime area was as follows:

	Three Months Ended June 30, 2015	Three Months Ended March 31, 2015	Increase (Decrease) in Production

Average daily production:
Oil (Bbls)	10,828	10,675	1.4	%
Natural gas liquids (Bbls)	5,314	5,367	(1.0	)%
Natural gas (Mcf)	65,324	62,933	3.8	%
Net boe/day	27,029	26,531	1.9	%

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

		Total Number of Gross Horizontal Wells Spud (1)		Total Number of Gross Horizontal Wells Brought into Production
Mississippian Lime		17		19

(1) We had four rigs drilling in the Mississippian Lime horizontal well program at June 30, 2015. Of the 17 wells spud, six were producing, seven were awaiting completion and four were being drilled at quarter-end.

In the second quarter of 2015, we invested approximately $67.7 million on completions and drilling new wells.

Anadarko Basin

For the three months ended June 30, 2015 and March 31, 2015, our average daily production from our Anadarko Basin area was as follows:

	Three Months Ended June 30, 2015	Three Months Ended March 31, 2015	Increase (Decrease) in Production

Average daily production:
Oil (Bbls)	2,937	3,028	(3.0	)%
Natural gas liquids (Bbls)	1,404	1,240	13.2	%
Natural gas (Mcf)	13,468	12,734	5.8	%
Net boe/day	6,586	6,390	3.1	%

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

Gulf Coast

For the three months ended June 30, 2015 and March 31, 2015, our average daily production from the Gulf Coast area was as follows:

	Three Months Ended June 30, 2015	Three Months Ended March 31, 2015	Decrease in Production

Average daily production:
Oil (Bbls)	194	858	(77.4	)%
Natural gas liquids (Bbls)	55	274	(79.9	)%
Natural gas (Mcf)	177	664	(73.3	)%
Net boe/day	278	1,243	(77.6	)%

Overall production decreased by 77.6% versus the first quarter of 2015 as a result of the Dequincy Divestiture, which occurred on April 21, 2015. The Dequincy Divestiture represented all of our remaining production and proved reserves in the Gulf Coast region.

No wells were spud or brought into production in our Gulf Coast area of operation during the second quarter of 2015.

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Capital Expenditures

During the three and six months ended June 30, 2015, we incurred operational capital expenditures of $70.4 million and $163.3 million, respectively, which consisted primarily of:

	For the Three Months Ended June 30, 2015		For the Six Months Ended June 30, 2015
	(in thousands)
Drilling and completion activities	$	69,348	$	160,399
Acquisition of acreage and seismic data	1,005		2,929
Operational capital expenditures incurred	$	70,353	$	163,328
Capitalized G&A, Office, ARO, & Other	2,576		4,336
Capitalized interest	1,082		2,066
Total capital expenditures incurred	$	74,011	$	169,730

Operational capital expenditures were incurred in the following areas:

	For the Three Months		For the Six Months
	Ended June 30, 2015		Ended June 30, 2015
	(in thousands)
Mississippian Lime	$	67,700	$	156,589
Anadarko Basin	1,493		4,656
Gulf Coast	1,160		2,083
Total capital expenditures incurred	$	70,353	$	163,328

We expect to invest between $250.0 million to $275.0 million of capital for exploration, development and lease and seismic acquisition during the year ended December 31, 2015.

Factors that Significantly Affect our Results

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

We generally hedge a portion of our expected future oil and gas production to reduce our exposure to fluctuations in commodity price. By removing a portion of commodity price volatility, we expect to reduce some of the variability in our cash flow from operations. See “Item 3. — Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Exposure” for discussion of our hedging and hedge positions. We plan to continue our strategy of hedging the risks associated with commodity price volatility; however, given the current low commodity price environment, we may limit the extent of our hedging program in the near-term as appropriate.

Like all businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from any given well is expected to decline. As a result, oil and natural gas exploration and production companies deplete their asset base with each unit of oil or natural gas they produce. We attempt to overcome this natural production decline by developing additional reserves through our drilling operations, acquiring additional reserves and production and implementing secondary recovery techniques. Our future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production. We will maintain our focus on the capital investments necessary to produce our reserves as well as to add to our reserves through drilling and 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.

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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 first quarter and second quarter of 2015, 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.

Results of Operations

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

Revenues

	For the Three Months Ended June 30,										For the Six Months Ended June 30,
	2015					2014					2015					2014
	(in thousands)										(in thousands)
REVENUES:
Oil sales	$	67,498		72	%	$	131,273		73	%	$	126,755		69	%	$	247,495		71	%
Natural gas liquid sales	10,239			11	%	23,020			13	%	21,249			12	%	48,539			14	%
Natural gas sales	15,995			17	%	24,994			14	%	35,167			19	%	50,379			15	%
Total oil, natural gas liquids, and natural gas sales	93,732			100	%	179,287			100	%	183,171			100	%	346,413			100	%

Realized gain/(losses) on commodity derivative contracts, net	42,189			(219	)%	(17,138		)	54	%	94,797			4,560	%	(31,948		)	59	%
Unrealized gains/(losses) on commodity derivative contracts, net	(61,482		)	319	%	(14,329		)	46	%	(92,718		)	(4,460	)%	(22,192		)	41	%
Gains (losses) on commodity derivative contracts - net	(19,293		)	100	%	(31,467		)	100	%	2,079			100	%	(54,140		)	100	%

Other	315					170					678					379

Total revenues	$	74,754				$	147,990				$	185,928				$	292,652

Production

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2015	2014	% Change		2015	2014	% Change
PRODUCTION DATA:
Oil (MBbls)	1,270	1,300	(2	)%	2,581	2,508	3	%
Natural gas liquids (MBbls)	616	601	3	%	1,236	1,134	9	%
Natural gas (MMcf)	7,186	6,013	20	%	14,056	11,237	25	%
Oil equivalents (MBoe)	3,084	2,904	6	%	6,160	5,514	12	%

Oil (Bbls/day)	13,959	14,290	(2	)%	14,258	13,856	3	%
Natural gas liquids (Bbls/day)	6,773	6,609	2	%	6,827	6,263	9	%
Natural gas (Mcf/day)	78,969	66,078	20	%	77,657	62,085	25	%
Average daily production (Boe/day)	33,893	31,912	6	%	34,028	30,466	12	%

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Prices

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2015		2014		% Change		2015		2014		% Change
AVERAGE SALES PRICES:
Oil, without realized derivatives (per Bbl)	$	53.14	$	100.95	(47	)%	$	49.12	$	98.69	(50	)%
Oil, with realized derivatives (per Bbl)	$	81.19	$	89.12	(9	)%	$	80.30	$	88.13	(9	)%
Natural gas liquids, without realized derivatives (per Bbl)	$	16.61	$	38.27	(57	)%	$	17.20	$	42.82	(60	)%
Natural gas liquids, with realized derivatives (per Bbl)	$	16.61	$	38.52	(57	)%	$	17.20	$	42.88	(60	)%
Natural gas, without realized derivatives (per Mcf)	$	2.23	$	4.16	(46	)%	$	2.50	$	4.48	(44	)%
Natural gas, with realized derivatives (per Mcf)	$	3.14	$	3.84	(18	)%	$	3.52	$	3.99	(12	)%

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

Oil, natural gas liquids and natural gas sales revenues

Our oil, NGL and natural gas sales revenues decreased by $85.6 million, or 47.7%, to $93.7 million during the three months ended June 30, 2015, as compared to $179.3 million during the three months ended June 30, 2014. The major contributing factor to this decrease was the substantially lower commodity prices for the three months ended June 30, 2015 as compared to the three months ended June 30, 2014.

Our oil sales revenues decreased by $63.8 million, or 48.6%, to $67.5 million during the three months ended June 30, 2015, as compared to $131.3 million for the three months ended June 30, 2014. Oil volumes sold decreased 331 Bbls/d, or 2.3%, to 13,959 Bbls/d for the three months ended June 30, 2015, from 14,290 Bbls/d for the three months ended June 30, 2014. The decrease in oil volumes sold was primarily attributable to lower production in our Gulf Coast area due to the Dequincy Divestiture, which impacted sales by 1,494 Bbls/d, as well as lower production from our Anadarko Basin area of 1,443 Bbls/d attributable to a decrease in drilling activity. These decreases were largely offset by increased production in the Mississippian Lime area of 2,606 Bbls/d.

Our NGL sales revenues decreased by $12.8 million, or 55.5%, to $10.2 million during the three months ended June 30, 2015, as compared to $23.0 million for the three months ended June 30, 2014. NGL volumes sold increased 164 Bbls/day, or 2.5%, to 6,773 Bbls/d for the three months ended June 30, 2015, from 6,609 Bbls/d for the three months ended June 30, 2014. This increase in NGL volumes sold was attributable to the increased production in the Mississippian Lime area of 869 Bbls/d partially offset by a 329 Bbls/d decrease in production from our Gulf Coast area due to the Dequincy Divestiture and reduced development drilling activity in our Anadarko Basin area, which resulted in lower NGL production of 376 Bbls/d.

Our natural gas sales revenues decreased by $9.0 million, or 36.0%, to $16.0 million during the three months ended June 30, 2015, as compared to $25.0 million for the three months ended June 30, 2014. Natural gas volumes sold increased 12,891 Mcf/d or 19.5%, to 78,969 Mcf/day for the three months ended June 30, 2015, from 66,078 Mcf/d for the three months ended June 30, 2014. The increase in natural gas volumes sold was attributable to increased production of 17,138 Mcf/d in the Mississippian Lime area due to the development drilling program and, starting in October 2014, ethane rejection on the gas processing side, partially offset by a decrease in production of 1,367 Mcf/d from our Gulf Coast area due to the Dequincy Divestiture and reduced development drilling activity in our Anadarko Basin area, which resulted in lower natural gas production of 2,880 Mcf/d.

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Gains/losses on commodity derivative contracts - net

Our mark-to-market (“MTM”) derivative positions moved from an unrealized loss of $14.3 million for the three months ended June 30, 2014 to an unrealized loss of $61.5 million for the three months ended June 30, 2015. The NYMEX WTI closing price on June 30, 2015 was $59.47 per barrel compared to a closing price of $105.37 per barrel on June 30, 2014.

Our realized gain on derivatives for the three months ended June 30, 2015 was $42.2 million, compared to a realized loss of $17.1 million for the three months ended June 30, 2014. The following table presents realized gain by type of commodity contract for the three months ended June 30, 2015:

	For the Three Months Ended June 30, 2015
	Realized Gain		Average Sales Price
	(in thousands)
Oil commodity contracts	$	35,627	$	81.19
Natural gas commodity contracts	6,562		3.14
Realized gains on commodity derivative contracts, net	$	42,189

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

Six Months Ended June 30, 2015 as Compared to the Six Months Ended June 30, 2014

Oil, natural gas liquids and natural gas sales revenues

Our oil, NGL and natural gas sales revenues decreased by $163.2 million, or 47.1%, to $183.2 million during the six months ended June 30, 2015, as compared to $346.4 million during the six months ended June 30, 2014. The major contributing factor to this decrease was the substantially lower commodity prices for the six months ended June 30, 2015 as compared to the six months ended June 30, 2014.

Our oil sales revenues decreased by $120.7 million, or 48.8%, to $126.8 million during the six months ended June 30, 2015, as compared to $247.5 million for the six months ended June 30, 2014. Oil volumes sold increased 402 Bbs/d, or 2.9%, to 14,258 Bbls/d for the six months ended June 30, 2015, from 13,856 Bbls/day for the six months ended June 30, 2014. This increase in oil volumes sold was attributable to increased production period over period in the Mississippian Lime area of 3,595 Bbls/d, partially offset by lower production in our Gulf Coast area due to the Dequincy Divestiture, which impacted sales by 1,813 Bbls/d, as well as lower production from our Anadarko Basin area of 1,380 Bbls/d, attributable to a decrease in drilling activity during the period and base production declines.

Our NGL sales revenues decreased by $27.3 million, or 56.2%, to $21.3 million during the six months ended June 30, 2015, as compared to $48.5 million for the six months ended June 30, 2014. NGL volumes sold increased 564 Bbls/d, or 9.0%, to 6,827 Bbls/d for the six months ended June 30, 2015, from 6,263 Bbls/d for the six months ended June 30, 2014. This increase in NGL volumes was attributable to the increased production in the Mississippian Lime area of 1,367 Bbls/d. Increased production in our Mississippian Lime area was offset by a 388 Bbls/d decrease in production from our Gulf Coast area due to the Dequincy Divestiture and reduced development drilling activity in the Anadarko Basin, which contributed to a decrease of 415 Bbls/d.

Our natural gas sales revenues decreased by $15.2 million, or 30.2%, to $35.2 million during the six months ended June 30, 2015, as compared to $50.4 million for the six months ended June 30, 2014. Natural gas volumes sold increased 15,572 Mcf/d or 25.1%, to 77,657 Mcf/d for the six months ended June 30, 2015, from 62,085 Mcf/d for the six months ended June 30, 2014. This increase in natural gas volumes sold was attributable to increased production of 19,614 Mcf/day in the Mississippian Lime area, partially offset by a decrease in production of 1,944 Mcf/d from our Gulf Coast area due to the Dequincy Divestiture and reduced development drilling activity in the Anadarko Basin, which contributed a decrease of 2,098 Mcf/d.

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Gains/losses on commodity derivative contracts - net

Our mark-to-market (“MTM”) derivative positions moved from an unrealized loss of $22.2 million for the six months ended June 30, 2014 to an unrealized loss of $92.7 million for the six months ended June 30, 2015. The NYMEX WTI closing price on June 30, 2015 was $59.47 per barrel compared to a closing price of $105.37 per barrel on June 30, 2014.

The realized gain on derivatives for the six months ended June 30, 2015 was $94.8 million compared to a realized loss of $32.0 million for the six months ended June 30, 2014. The following table presents realized gain by type of commodity contract for the six months ended June 30, 2015:

	For the Six Months Ended June 30, 2015
	Realized Gain		Average Sales Price
	(in thousands)
Oil commodity contracts	$	80,484	$	80.30
Natural gas commodity contracts	14,313		3.52
Realized gains on commodity derivative contracts, net	$	94,797

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 June 30,								Six Months Ended June 30,
	2015		2014		2015		2014		2015		2014		2015		2014
	(in thousands)				(per Boe)				(in thousands)				(per Boe)
EXPENSES:
Lease operating and workover	$	21,758	$	19,721	$	7.06	$	6.79	$	45,020	$	39,848	$	7.31	$	7.23
Gathering and transportation	3,931		2,940		1.27		1.01		7,369		5,795		1.20		1.05
Severance and other taxes	2,505		5,632		0.81		1.94		6,069		13,279		0.99		2.41
Asset retirement accretion	390		432		0.13		0.15		835		929		0.14		0.17
Depreciation, depletion, and amortization	55,255		71,074		17.92		24.47		113,683		137,975		18.46		25.02
Impairment of oil and gas properties	498,389		—		161.60		—		673,056		86,471		109.28		15.68
General and administrative	11,461		13,434		3.71		4.63		23,115		25,118		3.75		4.56
Acquisition and transaction costs	251		2,483		0.09		0.86		251		2,611		0.04		0.47
Debt restructuring costs	34,398		—		11.15		—		36,141		—		5.87		—
Other	—		609		—		0.21		73		939		0.01		0.17
Total expenses	$	628,338	$	116,325	$	203.74	$	40.06	$	905,612	$	312,965	$	147.05	$	56.76

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

Lease operating and workover expenses

Lease operating and workover expenses increased $2.0 million, or 10.3%, to $21.8 million for the three months ended June 30, 2015 compared to $19.7 million for the three months ended June 30, 2014. The increase in lease operating and workover expenses was primarily due to workover activity related to production optimization projects, higher environmental compliance costs and higher costs associated with the increase in producing well count period over period, partially offset by lower lease operating expenses due to the Dequincy Divestiture. Lease operating and workover expenses increased to $7.06 per Boe for the three months ended June 30, 2015, an increase of $0.27, or 4.0%, over the $6.79 per Boe for the three months ended June 30, 2014, primarily for the reasons noted above.

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Gathering and transportation

Gathering and transportation expenses were $3.9 million for the three months ended June 30, 2015, as compared to $2.9 million for the three months ended June 30, 2014. These expenses are primarily attributable to a gas transportation, gathering and processing contract covering the Mississippian Lime area that includes a $0.36 per Mmbtu gathering fee based upon wellhead volumes. As such, the increase in our gathering and transportation costs is due to increased natural gas production in our Mississippian Lime area.

Severance and other taxes

	Three Months Ended June 30,
	2015			2014

Total oil, natural gas, and natural gas liquids sales	$	93,732		$	179,287

Severance taxes	1,229			4,353
Ad valorem and other taxes	1,276			1,279
Severance and other taxes	$	2,505		$	5,632

Severance taxes as a percentage of sales	1.3		%	2.4		%
Severance and other taxes as a percentage of sales	2.7		%	3.1		%

Severance and other taxes decreased $3.1 million, or 55.5%, to $2.5 million for the three months ended June 30, 2015 compared to $5.6 million for the three months ended June 30, 2014. Severance taxes decreased $3.1 million, or 71.8%, to $1.2 million for the three months ended June 30, 2015, as compared to $4.4 million for the three months ended June 30, 2014. Severance taxes as a percentage of sales changed from 2.4% for the three months ended June 30, 2014 to 1.3% for the corresponding 2015 period due to lower realized pricing as well as a refund received in the 2015 period for production taxes paid in prior periods of $0.6 million. Ad valorem taxes were essentially unchanged for the three months ended June 30, 2015, as compared to the three months ended June 30, 2014.

Depreciation, depletion and amortization (DD&A)

DD&A expense decreased $15.8 million, or 22.3%, to $55.3 million for the three months ended June 30, 2015 compared to $71.1 million for the three months ended June 30, 2014. The decrease in DD&A expense was driven by downward revisions in our proved undeveloped reserves in the Anadarko Basin from June 30, 2014, which decreased estimated finding and developments costs and as a result, reduced our DD&A expense, as well as the ceiling test impairments recorded during the period. Additionally, our depletion rate has decreased from approximately 2.3% for the three months ended June 30, 2014 to 2.0% for the three months ended June 30, 2015, primarily as a result of increased proved developed reserve volumes. The DD&A rate for 2015 was $17.92 per Boe, compared to $24.47 per Boe for 2014 as a result of the factors discussed above.

Impairment of oil and gas properties

We recorded pre-tax impairment expense related to our oil and natural gas properties for the three months ended June 30, 2015 of $498.4 million as a result of our full-cost ceiling test. Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of capitalized costs associated with our oil and natural gas properties in our condensed consolidated balance sheets. The impairment expense for the three months ended June 30, 2015 was due to a decrease in the PV-10 value of our proven oil and natural gas reserves as a result of low commodity prices.

General and administrative (G&A)

Our G&A expenses decreased by $2.0 million, or 14.7%, to $11.5 million for the three months ended June 30, 2015, compared to $13.5 million for the three months ended June 30, 2014. The decrease is primarily due to lower employee related costs period over period, mainly due to lower headcount and the closure of our Houston office.

Acquisition and transaction costs

Our acquisition and transaction costs were $0.3 million for the three months ended June 30, 2015, related to the Dequincy Divestiture, compared to $2.5 million for the three months ended June 30, 2014, representing our expenses related to the Pine Prairie disposition in 2014.

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Debt restructuring costs

During the 2015 period, we engaged various advisors to assist us in analyzing options to improve our financial flexibility and provide additional long-term liquidity. For the three months ended June 30, 2015, we incurred approximately $34.4 million in fees associated with these advisors as well as issuance costs associated with the Second Lien Notes offering and Third Lien Notes exchange.

Other

Other operating expenses for the three months ended June 30, 2014 were $0.6 million and represent the loss on disposal of field equipment inventory deemed no longer essential to operations. No such expenses were incurred in the three months ended June 30, 2015.

Six Months Ended June 30, 2015 as Compared to the Six Months Ended June 30, 2014

Lease operating and workover expenses

Lease operating and workover expenses increased $5.1 million, or 13.0%, to $45.0 million for the six months ended June 30, 2015 compared to $39.8 million for the six months ended June 30, 2014. The increase in lease operating and workover expenses was primarily due to costs associated with the increase in producing well count period over period and higher environmental compliance costs, partially offset by lower lease operating expenses due to the Dequincy Divestiture. Lease operating and workover expenses increased minimally to $7.31 per Boe for the six months ended June 30, 2015, an increase of $0.08, or 1.1%, from the $7.23 per Boe for the six months ended June 30, 2014, primarily for the reasons noted above.

Gathering and transportation

Gathering and transportation expenses were $7.4 million for the six months ended June 30, 2015, as compared to $5.8 million for the six months ended June 30, 2014. These expenses are primarily attributable to a gas transportation, gathering and processing contract covering the Mississippian Lime area that includes a $0.36 per Mmbtu gathering fee based upon wellhead volumes. As such, the increase in our gathering and transportation costs is due to increased natural gas production in our Mississippian Lime area.

Severance and other taxes

	Six Months Ended June 30,
	2015			2014

Total oil, natural gas, and natural gas liquids sales	$	183,171		$	346,413

Severance taxes	3,011			10,162
Ad valorem and other taxes	3,058			3,117
Severance and other taxes	$	6,069		$	13,279

Severance taxes as a percentage of sales	1.6		%	2.9		%
Severance and other taxes as a percentage of sales	3.3		%	3.8		%

Severance and other taxes decreased $7.2 million, or 54.3%, to $6.1 million for the six months ended June 30, 2015, compared to $13.3 million for the six months ended June 30, 2014. Severance taxes decreased $7.2 million, or 70.4%, to $3.0 million for the six months ended June 30, 2015, as compared to $10.2 million for the six months ended June 30, 2014. Severance taxes as a percentage of sales changed from 2.9% for the six months ended June 30, 2014 to 1.6% for the corresponding 2015 period due to lower realized pricing as well as a refund received in 2015 for production taxes paid in prior periods of $0.6 million. Ad valorem taxes were essentially unchanged for the six months ended June 30, 2015, as compared to the six months ended June 30, 2014.

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Depreciation, depletion and amortization

DD&A expense decreased $24.3 million, or 17.6%, to $113.7 million for the six months ended June 30, 2015 compared to $138.0 million for the six months ended June 30, 2014. The decrease in DD&A expense was driven by downward revisions in our proved undeveloped reserves in the Anadarko Basin from June 30, 2014, which decreased estimated finding and developments costs and as a result, reduced our DD&A expense, as well as the ceiling test impairments recorded during the period. Additionally, our depletion rate has decreased from an average of approximately 2.2% for the six months ended June 30, 2014 to an average of 2.0% for the six months ended June 30, 2015, primarily as a result of increased proved developed reserve volumes. The DD&A rate for 2015 was $18.46 per Boe, compared to $25.02 per Boe for 2014 as a result of the factors discussed above.

Impairment of oil and gas properties

We recorded pre-tax impairment expense related to our oil and natural gas properties for the six months ended June 30, 2015 and 2014 of $673.1 million and $86.5 million, respectively, as a result of our full-cost ceiling test. Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of capitalized costs associated with our oil and natural gas properties in our condensed consolidated balance sheets. The impairment expense for the six months ended June 30, 2015 was due to a decrease in the PV-10 value of our proven oil and natural gas reserves as a result of low commodity prices. The impairment expense for six months ended June 30, 2014 was largely due to the transfer of unevaluated property costs to the full cost pool during the first quarter of 2014. During the first quarter of 2014, we transferred $21.4 million and $38.1 million related to the Mississippian Lime and Anadarko Basin areas, respectively, as we released acreage that did not present the best near term development potential.

General and administrative

Our G&A expenses decreased by $2.0 million, or 8.0%, to $23.1 million for the six months ended June 30, 2015, compared to $25.1 million for the six months ended June 30, 2014. The decrease is primarily attributable to due to lower stock compensation and other employee related expenses due to lower headcount and the closure of the Houston office.

Acquisition and transaction costs

Our acquisition and transaction costs were $0.3 million for the six months ended June 30, 2014, related to the Dequincy Divestiture, compared to $2.6 million for the six months ended June 30, 2014, representing our expenses related to the Pine Prairie disposition in 2014.

Debt restructuring costs

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

Other

Other operating expenses for the six months ended June 30, 2015 and 2014 were $0.1 million and $0.9 million, respectively. For 2014, these costs represent the loss on disposal of field equipment inventory deemed no longer essential to operations.

Other Income (Expense)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2015			2014			2015			2014
	(in thousands)						(in thousands)
OTHER INCOME (EXPENSE)
Interest income	$	27		$	9		$	36		$	19

Interest expense	(45,962		)	(37,157		)	(83,448		)	(75,722		)
Capitalized Interest	1,082			3,344			2,066			7,962
Interest expense — net of amounts capitalized	(44,880		)	(33,813		)	(81,382		)	(67,760		)

Total other expense	$	(44,853	)	$	(33,804	)	$	(81,346	)	$	(67,741	)

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Interest expense

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

Interest expense for the three months ended June 30, 2015 and 2014 was $46.0 million and $37.2 million, respectively. The increase in interest expense was primarily due to the issuance of the Second Lien Notes and Third Lien Notes on May 21, 2015. The Second Lien Notes bear interest at 10.0% and were used to repay outstanding borrowings under the Credit Facility, which had an interest rate of 2.9% at June 30, 2015. Additionally, the Third Lien Notes bear interest at 12.0% and were exchanged for a portion of the 2020 Senior Notes and 2021 Senior Notes, which had stated interest rates of 10.75% and 9.25%, respectively. Further, approximately $4.6 million in unamortized debt costs were impaired during the three months ended June 30, 2015 as a result of the Seventh Amendment to the Credit Facility. For the three months ended June 30, 2015 and 2014, approximately $1.1 million and $3.3 million, respectively, in interest expense was capitalized to oil and gas properties. Capitalized interest was lower due to a decrease in the balance of our unevaluated property from June 30, 2014.

Six Months Ended June 30, 2015 as Compared to the Six Months Ended June 30, 2014

Interest expense for the six months ended June 30, 2015 and 2014 was $83.4 million and $75.7 million, respectively. The increase in interest expense was primarily due to the issuance of the Second Lien Notes and Third Lien Notes on May 21, 2015. The Second Lien Notes bear interest at 10.0% and were used to repay outstanding borrowings under the Credit Facility, which had an interest rate of 2.9% at June 30, 2015. Additionally, the Third Lien Notes bear interest at 12.0% and were exchanged for a portion of the 2020 Senior Notes and 2021 Senior Notes, which had stated interest rates of 10.75% and 9.25%, respectively. Further, approximately $4.6 million in unamortized debt costs were impaired during the six months ended June 30, 2015 as a result of the Seventh Amendment to the Credit Facility. For the six months ended June 30, 2015 and 2014, approximately $2.1 million and $8.0 million, respectively, in interest expense was capitalized to oil and gas properties. Capitalized interest was lower due to a decrease in the balance of our unevaluated property from June 30, 2014

Provision for Income Taxes

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

We had no income tax benefit or expense for the three months ended June 30, 2015, compared to a benefit of $0.1 million for the three months ended June 30 2014. Our effective tax rate for the second quarter of 2015 differs from the federal statutory rate of 35% due to the effect of recurring permanent adjustments, state income taxes and changes in the valuation allowance

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

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

Six Months Ended June 30, 2015 as Compared to the Six Months Ended June 30, 2014

Our income tax benefit was $9.0 million and $2.3 million for the six months ended June 30, 2015 and 2014, respectively. For the six months ended June 30, 2015, our effective tax rate was a benefit of approximately 1.1%. Our effective tax rate for the six months ended June 30, 2015 differs from the federal statutory rate of 35% due to the effect of recurring permanent adjustments, state income taxes and changes in the valuation allowance.

This year, we recorded $305.9 million in additional valuation allowance in light of the impairment of oil and gas properties and the settlement of certain hedging contracts that existed at December 31, 2014, bringing the total valuation allowance to $309.7 million at June 30, 2015.

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Liquidity and Capital Resources

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

At June 30, 2015, our liquidity consisted of approximately $250.9 million of available borrowing capacity under Credit Facility and $151.0 million of cash and cash equivalents.

Expenditures for exploration and development of oil and natural gas properties and payments for interest related to our outstanding debt are the primary use of our capital resources and liquidity. We expect to invest a total of between $250.0 million and $275.0 million of capital for exploration, development and lease and seismic acquisition during the year ending December 31, 2015. Additionally, we expect to capitalize between $4.0 million and $6.0 million of interest expense during that same period.

In April 2015, we closed a purchase and sale agreement covering the sale of our remaining producing assets in Louisiana for total consideration of approximately $42.4 million cash, net of customary closing adjustments. The net proceeds will be used for general corporate purposes.

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

Additionally, we and Midstates Sub also entered into the Seventh Amendment which provided that upon completion of the offering of the Second Lien Notes and Third Lien Notes exchange, the borrowing base of the Credit Facility would be reduced to $252.4 million. The Seventh Amendment also provided additional covenant flexibility.

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

	2020 Senior Notes		2021 Senior Notes		Second Lien Notes		Third Lien Notes		Total
Remainder of 2015	$	10,521	$	16,079	$	33,851	$	28,515	$	88,966
2016	31,565		32,158		63,817		54,602		182,142
2017	31,565		32,158		63,817		55,728		183,268
2018	31,565		32,158		63,817		56,877		184,417
2019	31,565		32,158		63,817		58,049		185,589
2020	31,565		32,158		31,908		86,121		181,752
2021	—		16,079		—		—		16,079

Our future success in growing proved reserves and production and meeting our interest obligations will be highly dependent on our ability to access additional outside sources of capital, via either the debt or equity markets, through growth in our Credit Facility or by securing other external sources of funding. Though we have no current plans to do so, we may from time to time seek to retire, purchase or exchange our outstanding debt in open market purchases, privately negotiated transactions or otherwise. Such 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.

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Significant Sources of Capital

Reserve-based Credit Facility

We maintain a $750.0 million Credit Facility with a borrowing base of $252.4 million supported by our Mississippian Lime and Anadarko Basin oil and gas assets. At June 30, 2015, we had no amounts drawn on the Credit Facility and had outstanding letters of credit obligations totaling $1.5 million.

The Credit Facility matures on May 31, 2018 and borrowings thereunder are secured by substantially all of our oil and natural gas properties and bear interest at LIBOR plus an applicable margin, depending upon the Company’s borrowing base utilization, between 2.00% and 3.00% per annum. At June 30, 2015 and 2014, the weighted average interest rate was 2.9% and 2.8%, 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 any amount by which the principal balance of its outstanding loans and its letter of credit obligations exceed its redetermined borrowing base or grant liens on additional property having sufficient value to eliminate such excess. We are permitted to make such repayment in six equal successive monthly payments commencing 30 days following the administrative agent’s notice regarding such borrowing base reduction.

On March 24, 2015, we and Midstates Sub entered into a Sixth Amendment (the “Sixth Amendment”) to the Credit Facility. The Sixth Amendment amended the required ratio of net consolidated indebtedness to EBITDA under the Credit Agreement for each of the fiscal quarters in 2015 from 4.0:1.0 to 4.5:1.0. Additionally, the Sixth Amendment amended the mortgage requirements under the Credit Facility to provide for an increase from 80% to 90% for the percentage of properties included in the borrowing base that are required to be subject to mortgages for the benefit of the lenders.

On May 21, 2015, we and Midstates Sub entered into a Seventh Amendment (the “Seventh Amendment”) to the Credit Facility. The Seventh Amendment provided that, with the completion of the offering of the Second Lien Notes and Third Lien Notes exchange (both discussed below), our borrowing base would be reduced to approximately $252.4 million. The Seventh Amendment also eliminated the required ratio of net consolidated indebtedness to EBITDA covenant and added a ratio of Total Senior Indebtedness (as defined therein) to EBITDA of not more than 1.0:1.0. The next scheduled redetermination of the borrowing base is October 2015.

2020 Senior Notes

On October 1, 2012, we issued $600 million in aggregate principal amount of 2020 Senior Notes conducted pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended (the “Securities Act”). In October 2013, these notes were exchanged for an equal principal amount of identical registered notes. The 2020 Senior Notes rank pari passu in right of payment with the 2021 Senior Notes, the Second Lien Notes and Third Lien Notes. The 2020 Senior Notes were co-issued on a joint and several basis by us and our wholly owned subsidiary, Midstates Sub. We do not have any operations or independent assets other than its 100% ownership interest in Midstates Sub and there are no other subsidiaries. The indenture governing the 2020 Senior Notes (the “2020 Senior Notes Indenture”) does not create any restricted assets within Midstates Sub, nor does it impose any significant restrictions on the ability of Midstates Sub to pay dividends or make loans to us or limit our ability to advance loans to Midstates Sub. On May 21, 2015 and June 2, 2015, a total of approximately $306.4 million of 2020 Senior Notes were exchanged for Third Lien Notes, as discussed above.

At any time prior to October 1, 2015, we may, under certain circumstances, redeem up to 35% of the aggregate principal amount of the 2020 Senior Notes with the net proceeds of a public or private equity offering at a redemption price of 110.75% of the principal amount of the 2020 Senior Notes, plus any accrued and unpaid interest up to the redemption date. In addition, at any time before October 1, 2016, we may redeem all or a part of the 2020 Senior Notes at a redemption price equal to 100% of the principal amount of 2020 Senior Notes redeemed plus the Applicable Premium (as defined in the 2020 Senior Notes Indenture) at the redemption date, plus any accrued and unpaid interest, if any, up to the redemption date. On or after October 1, 2016, we may redeem all or a part of the 2020 Senior Notes at varying redemption prices (expressed as percentages of principal amount) set forth in the 2020 Senior Notes Indenture plus accrued and unpaid interest, if any, on the 2020 Senior Notes redeemed, up to the redemption date.

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Upon the occurrence of certain change of control events, as defined in the 2020 Senior Notes Indenture, each holder of the 2020 Senior Notes will have the right to require that we repurchase all or a portion of such holder’s 2020 Senior Notes in cash at a purchase price equal to 101% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

2021 Senior Notes

On May 31, 2013, we issued $700.0 million in aggregate principal amount of 2021 Senior Notes. In October 2013, these notes were exchanged for an equal principal amount of identical registered notes.The 2021 Senior Notes rank pari passu in right of payment with the 2020 Senior Notes, Second Lien Notes and Third Lien Notes. The 2021 Senior Notes were co-issued on a joint and several basis by us and our wholly owned subsidiary, Midstates Sub. The indenture governing the 2021 Senior Notes (the “2021 Senior Notes Indenture”) does not create any restricted assets within Midstates Sub, nor does it impose any significant restrictions on the ability of Midstates Sub to pay dividends or make loans us or limit our ability to advance loans to Midstates Sub. On May 21, 2015 and June 2, 2015, a total of approximately $352.3 million of 2021 Senior Notes were exchanged for Third Lien Notes, as discussed above.

Prior to June 1, 2016, we may, under certain circumstances, redeem up to 35% of the aggregate principal amount of the 2021 Senior Notes (less the amount of 2021 Senior Notes redeemed pursuant to the preceding paragraph) with the net proceeds of any equity offerings at a redemption price of 109.25% of the principal amount of the 2021 Senior Notes redeemed, plus any accrued and unpaid interest, if any, up to the redemption date. In addition, at any time before June 1, 2016, we may redeem all or a part of the 2021 Senior Notes at a redemption price equal to 100% of the principal amount of the 2021 Senior Notes redeemed plus the Applicable Premium (as defined in the 2021 Senior Notes Indenture) at the redemption date, plus any accrued and unpaid interest, if any, up to, the redemption date. On or after October 1, 2016, we may redeem all or a part of the 2021 Senior Notes at varying redemption prices (expressed as percentages of principal amount) set forth in the 2021 Senior Notes Indenture plus accrued and unpaid interest, if any, on the 2021 Senior Notes redeemed, up to, the redemption date.

Upon the occurrence of certain change of control events, as defined in the 2021 Senior Notes Indenture, each holder of the 2021 Senior Notes will have the right to require that we repurchase all or a portion of such holder’s 2021 Senior Notes in cash at a purchase price equal to 101% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

Second Lien Notes

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

On May 21, 2015, in connection with the offering of Second Lien Notes, we and Midstates Sub entered into a registration rights agreement with the initial purchasers of the Second Lien Notes pursuant to which the Issuers are obligated, within 270 days after the issuance of the Second Lien Notes, to file with the Securities and Exchange Commission under the Securities Act a registration statement with respect to an offer to exchange the Second Lien Notes for substantially identical registered new notes. We will be obligated to pay liquidated damages consisting of additional interest on the Second Lien Notes if, within the periods specified in the agreement, it does not file the exchange offer registration statement or if certain other events occur.

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

Upon the occurrence of certain change of control events, as defined in the indenture governing the Second Lien Notes, each holder of the Second Lien Notes will have the right to require that we repurchase all or a portion of such holder’s 2020 Second Lien Notes in cash at a purchase price equal to 101% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

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Third Lien Notes

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

On May 21, 2015, in connection with the issuance of the Third Lien Notes, we entered into a registration rights agreement with the initial purchasers of the Third Lien Notes pursuant to which we are obligated, within 270 days after the issuance of the Third Lien Notes, to file with the Securities and Exchange Commission under the Securities Act a registration statement with respect to an offer to exchange the Third Lien Notes for substantially identical registered new notes. We will be obligated to pay liquidated damages consisting of additional interest on the Third Lien Notes if, within the periods specified in the agreement, it does not file the exchange offer registration statement or if certain other events occur.

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

Upon the occurrence of certain change of control events, as defined in the indenture governing the Third Lien Notes, each holder of the Third Lien Notes will have the right to require that we repurchase all or a portion of such holder’s Third Lien Notes in cash at a purchase price equal to 101% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.

Debt Covenants

The indentures governing the 2020 Senior Notes, 2021 Senior Notes, Second Lien Notes and Third Lien Notes contain covenants that, among other things, restrict our ability to: (i) incur additional indebtedness, guarantee indebtedness or issue certain preferred shares; (ii) make loans, investments and other restricted payments; (iii) pay dividends on or make other distributions in respect of, or repurchase or redeem, capital stock; (iv) create or incur certain liens; (v) sell, transfer or otherwise dispose of certain assets; (vi) enter into certain types of transactions with our affiliates; (vii) consolidate, merge or sell substantially all of our assets; (viii) prepay, redeem or repurchase certain debt; (ix) alter the business we conduct and (x) enter into agreements restricting the ability of our current and any future subsidiaries to pay dividends.

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

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”.

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

	For the Six Months Ended June 30,
	2015			2014
Net cash provided by operating activities	$	138,650		$	173,561
Net cash used in investing activities	(149,994		)	(128,028		)
Net cash provided by (used in) financing activities	150,824			(49,036		)

Net change in cash	$	139,480		$	(3,503	)

Cash flows provided by operating activities

Net cash provided by operating activities decreased by $34.9 million to $138.7 million for the six months ended June 30, 2015 as compared to $173.6 million for the six months ended June 30, 2014. The decrease in net cash provided by operating activities was primarily the result of a decrease in our oil and gas revenues of $163.2 million due to lower commodity pricing, offset partially by increased settlements of derivatives of $126.8 million.

Cash flows used in investing activities

Net cash used in investing activities was $150.0 million and $128.0 million during the six months ended June 30, 2015 and 2014, respectively. The increase in net cash used in investing activities was primarily the result of a decrease in proceeds from the sale of oil and gas properties of $105.0 million offset by a decrease in capital expenditures of $85.3 million. During the 2014 period, the Company completed the Pine Prairie disposition for approximately in $147.5 million in proceeds as compared to the Dequincy Divestiture that occurred during the 2015 period for approximately $40.3 million in proceeds. The decrease in our capital expenditures is a result of lower rig count during the 2015 period due to low commodity pricing.

Cash flows provided by (used in) financing activities

Net cash provided by financing activities was $150.8 million for the six months ended June 30, 2015, as compared to cash used in financing activities of $49.0 million for the six months ended June 30, 2014. The increase in net cash provided by financing activities was primarily the result of the issuance of the Second Lien Notes of $625.0 million and additional borrowings from the Credit Facility of $33.0 million offset partially by the repayment of the Credit Facility of $468.2 million and debt restructuring costs of $36.1 million during the 2015 period as compared to borrowings from the Credit Facility of $84.0 million and repayments of the Credit Facility of $131.0 million during the 2014 period.

Critical Accounting Policies and Estimates

A discussion of our critical accounting policies and estimates is included in our Annual Report on Form 10-K for the year ended December 31, 2014. There have been no material changes to those policies.

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

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Other Items

Contractual Obligations

The following table summarizes our contractual obligations as of June 30, 2015 (in thousands):

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

Long-Term Debt:
Principal	$	1,790,398	$	—	$	—	$	1,790,398	$	—
Interest (2)	1,022,213		180,037		551,550		290,626		—
Drilling contracts	10,697		10,697		—		—		—
Non-cancellable office lease commitments	8,392		1,868		4,833		1,691		—
Seismic contracts	3,192		3,192		—		—		—
Asset retirement obligations (3)	17,737		—		—		—		17,737
Net minimum commitments	$	2,852,629	$	195,794	$	556,383	$	2,082,715	$	17,737

(1) Less than one year includes commitments from July 2015 through June 2016; 1-3 years includes commitments from July 2016 through June 2019; 3-5 years includes commitments from July 2019 through June 2021; and 5+ years includes commitments from July 2021 and beyond.

(2) Included within the interest amount shown is approximately $56.7 million in paid-in-kind interest on the Third Lien Notes that will be paid at the maturity date of June 1, 2020.

(3) 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 utilize any off-balance sheet arrangements with unconsolidated entities to enhance our liquidity and capital resource positions or for any other purpose. However, as is customary in the oil and gas industry, we have various contractual work commitments and letters of credit as described in our notes to the condensed consolidated financial statements.

Recent Accounting Pronouncements

On May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”). ASU 2014-09 provides guidance concerning the recognition and measurement of revenue from contracts with customers. The objective of ASU 2014-09 is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. ASU 2014-09 requires an entity to (i) identify the contract(s) with a customer, (ii) identify the performance obligations in the contract(s), (iii) determine the transaction price, (iv) allocate the transaction price to the performance obligations in the contract(s), and (v) recognize revenue when, or as, the entity satisfies a performance obligation. ASU 2014-09 will be effective for the Company beginning on January 1, 2018, including interim periods within that reporting period, considering the one year deferral approved by the FASB on July 9, 2015. The standard permits the use of either the retrospective or cumulative effect transition method. Early adoption is permitted. The Company has not selected a transition method and is evaluating the impact this standard will have on its consolidated financial statements and related disclosures.

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

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The disclosures are not meant to be precise indicators of expected future losses or gains, but rather indicators of reasonably possible losses or gains. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. These derivative instruments are discussed in “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. However, given the current low commodity price environment, we may limit the extent of our hedging program in the near-term as appropriate.

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

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

The following is a summary of our commodity derivative contracts as of June 30, 2015:

	Hedged	Weighted-Average
	Volume	Fixed Price
Oil (Bbls):
WTI Swaps — 2015	2,208,000	$	71.56

Natural Gas (MMBtu):
Swaps — 2015(1)	9,200,000	$	4.13

(1) Includes 1,500,000 MMBtus in natural gas swaps that priced during the period, but had not cash settled as of June 30, 2015.

	As of and for the Six Months Ended June 30, 2015
	(in thousands)
Derivative fair value at period end - asset (included in balance sheet)	$	33,991
Realized net gain (included in the statement of operations)	$	94,797
Unrealized net loss (included in the statement of operations)	$	92,718

At June 30, 2015 and December 31, 2014, all of our commodity derivative contracts were with seven bank counterparties. Our policy is to net derivative liabilities and assets where there is a legally enforceable master netting agreement with the counterparty.

Interest Rate Risk. At June 30, 2015, we had no indebtedness outstanding under our Credit Facility, $293.6 million outstanding in 2020 Senior Notes, which bear interest at 10.75%, $347.7 million outstanding in 2021 Senior Notes, which bear interest at 9.25%, $625.0 million outstanding in Second Lien Notes, which bear interest at 10.0% and $525.3 million in Third Lien Notes, which bear interest at 12.0%. At June 30, 2015 and 2014, the weighted average interest rate was 2.9% and 2.8%, respectively, for the Credit Facility.

A 1.0% increase in each of the average LIBOR and federal funds rate for the three and six months ended June 30, 2014 would have resulted in an estimated $1.0 million and $1.9 million, respectively, increase in interest expense, of which a portion may be capitalized. There were no borrowings on the Credit Facility as of June 30, 2015.

At June 30, 2015, we do not have any interest rate derivatives in place. In the future, we may utilize interest rate derivatives to mitigate our exposure to change in interest rates. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

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

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

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

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

In the first quarter of 2015, the Company determined that it had incorrectly presented non-cash accrued capital expenditures in its Statements of Cash Flows since December 31, 2012. Management concluded the misstatement was immaterial to previously issued financial statements; however, the Company intends to correct the cash flow presentation prospectively in future filings and reported restated amounts within Item 5. Other Information, of its Quarterly Report on Form 10-Q for the interim period ended March 31, 2015.

In the second quarter of 2015, the Company determined that the restated amounts for the years ended December 31, 2013 and 2012 in Item 5. Other Information, of its Quarterly Report on Form 10-Q for the interim period ended March 31, 2015, required revision. Although we continue to believe that these errors are immaterial, we have revised the restated amounts, as shown in the table below, for the years ended December 31, 2013 and 2012. There continues to be no impact to the Consolidated Balance Sheets as of December 31, 2014 and 2013, or the Consolidated Statements of Operations for the years ended December 31, 2014, 2013 and 2012.

	For the Twelve Months Ended December 31,
	2014						2013						2012
Statement of Cash Flows	As Previously Reported			As Restated			As Previously Reported			As Restated			As Previously Reported			As Restated

Change in operating assets and liabilities: accounts receivable - JIB and other	$	(13,603	)	$	(18,897	)	$	(28,488	)	$	(18,002	)	$	(11,019	)	$	(3,249	)
Net cash provided by operating activities	356,838			351,544			227,102			237,588			137,249			145,019

Investment in property and equipment	(561,691		)	(556,397		)	(573,734		)	(584,220		)	(422,332		)	(430,102		)
Net cash used in investing activities	(409,558		)	(404,264		)	(1,193,846		)	(1,204,332		)	(773,608		)	(781,378		)

Item 6. Exhibits

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

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EXHIBIT INDEX

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

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

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

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

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

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

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

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

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

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

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

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

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

10.1			Intercreditor Agreement, dated May 21, 2015, by and among Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC, SunTrust Bank, as priority lien agent, and Wilmington Trust, National Association, as second lien collateral agent and third lien collateral agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 22, 2015, and incorporated herein by reference).

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10.2		Second Lien Pledge and Security Agreement, dated May 21, 2015, by and among Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC and Wilmington Trust, National Association, as collateral agent (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on May 22, 2015, and incorporated herein by reference).

10.3		Third Lien Pledge and Security Agreement, dated May 21, 2015, by and among Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC and Wilmington Trust, National Association, as collateral agent (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on May 22, 2015, and incorporated herein by reference).

10.4		Seventh Amendment to Second Amended and Restated Credit Agreement, dated as of May 21, 2015, among Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC, as borrower, SunTrust Bank, N.A., as administrative agent, and the lenders and other parties thereto (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on May 22, 2015, and incorporated herein by reference).

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

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

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

101.INS		XBRL Instance Document.

101.SCH		XBRL Schema Document.

101.CAL		XBRL Calculation Linkbase Document.

101.DEF		XBRL Definition Linkbase Document.

101.LAB		XBRL Labels Linkbase Document

101.PRE		XBRL Presentation Linkbase Document.

*			Filed herewith
**			Furnished herewith

	Page

Glossary of Oil and Natural Gas Terms	3

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements
Condensed Consolidated Balance Sheets at June 30, 2015 and December 31, 2014 (unaudited)	4
Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2015 and 2014 (unaudited)	5
Condensed Consolidated Statements of Changes in Stockholders’ Equity (Deficit) for the Six Months Ended June 30, 2015 and 2014 (unaudited)	6
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2015 and 2014 (unaudited)	7

Notes to Unaudited Condensed Consolidated Financial Statements	8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	24

Item 3. Quantitative and Qualitative Disclosures About Market Risk	43

Item 4. Controls and Procedures	44

PART II - OTHER INFORMATION

Item 1. Legal Proceedings	45

Item 1A. Risk Factors	45

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	46

Item 3. Defaults Upon Senior Securities	46

Item 4. Mine Safety Disclosures	46

Item 5. Other Information	46

Item 6. Exhibits	46

SIGNATURES	47

EXHIBIT INDEX	48

	MIDSTATES PETROLEUM COMPANY, INC.

Dated: August 6, 2015	/s/ Frederic F. Brace
	Frederic F. Brace
	Interim President and Chief Executive Officer
	(Principal Executive Officer)

Dated: August 6, 2015	/s/ Nelson M. Haight
	Nelson M. Haight
	Executive Vice President and Chief Financial Officer
	(Principal Financial and Accounting Officer)