Amplify Energy Corp. - FORM 10-Q

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EX-32.1 - EX-32.1 - Amplify Energy Corp.	a14-14016_1ex32d1.htm
EX-31.1 - EX-31.1 - Amplify Energy Corp.	a14-14016_1ex31d1.htm
EX-31.2 - EX-31.2 - Amplify Energy Corp.	a14-14016_1ex31d2.htm
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Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2014

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

For the transition period from to

Commission File Number: 001-35512

MIDSTATES PETROLEUM COMPANY, INC.

(Exact name of registrant as specified in its charter)

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

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

(713) 595-9400

(Registrant’s telephone number, including area code)

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

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

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

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

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

The number of shares outstanding of our common stock at August 5, 2014 is shown below:

Class		Number of shares outstanding
Common stock, $0.01 par value		70,673,772

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MIDSTATES PETROLEUM COMPANY, INC.

QUARTERLY REPORT ON

FORM 10-Q

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2014

TABLE OF CONTENTS

	Page

Glossary of Oil and Natural Gas Terms	3

PART I - FINANCIAL INFORMATION

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

Notes to Unaudited Condensed Consolidated Financial Statements	8

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk	38

Item 4. Controls and Procedures	41

PART II - OTHER INFORMATION

Item 1. Legal Proceedings	41

Item 1A. Risk Factors	41

Item 6. Exhibits	41

SIGNATURES	42

EXHIBIT INDEX	43

Table of Contents

GLOSSARY OF OIL AND NATURAL GAS TERMS

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

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

Boe/day: Barrels of oil equivalent per day.

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

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

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

Mcf: One thousand cubic feet of natural gas.

MMBoe: One million barrels of oil equivalent.

MMBtu: One million British thermal units.

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

NYMEX: The New York Mercantile Exchange.

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

Reasonable certainty: A high degree of confidence.

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

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

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

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

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

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

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PART I - FINANCIAL INFORMATION

MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands, except share amounts)

	June 30, 2014			December 31, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	29,660		$	33,163
Accounts receivable:
Oil and gas sales	103,481			102,483
Joint interest billing	40,721			42,631
Other	2,396			1,090
Commodity derivative contracts	—			700
Deferred income taxes	12,090			11,837
Other current assets	1,419			693
Total current assets	189,767			192,597

PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of full-cost accounting	3,190,927			3,060,661
Other property and equipment	12,691			11,113
Less accumulated depreciation, depletion, amortization and impairment	(1,201,060		)	(976,880		)
Net property and equipment	2,002,558			2,094,894

OTHER ASSETS:
Commodity derivative contracts	17			19
Other noncurrent assets	50,942			54,597
Total other assets	50,959			54,616

TOTAL	$	2,243,284		$	2,342,107

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	34,267		$	21,493
Accrued liabilities	207,983			204,381
Commodity derivative contracts	47,152			27,880
Total current liabilities	289,402			253,754

LONG-TERM LIABILITIES:
Asset retirement obligations	20,382			26,308
Commodity derivative contracts	5,869			3,651
Long-term debt	1,654,150			1,701,150
Deferred income taxes	13,233			15,291
Other long-term liabilities	2,665			1,954
Total long-term liabilities	1,696,299			1,748,354

COMMITMENTS AND CONTINGENCIES (Note 13)

STOCKHOLDERS’ EQUITY:
Preferred stock, $0.01 par value, 49,675,000 shares authorized; no shares issued or outstanding	—			—
Series A mandatorily convertible preferred stock, $0.01 par value, $372,892 and $358,550 liquidation value at June 30, 2014 and December 31, 2013, respectively; 8% cumulative dividends; 325,000 shares issued and outstanding	3			3
Common stock, $0.01 par value, 300,000,000 shares authorized; 70,857,076 shares issued and 70,459,020 shares outstanding at June 30, 2014 and 68,925,745 shares issued and 68,807,043 shares outstanding at December 31, 2013	708			689
Treasury stock	(2,155		)	(664		)
Additional paid-in-capital	875,846			871,047
Retained deficit	(616,819		)	(531,076		)
Total stockholders’ equity	257,583			339,999

TOTAL	$	2,243,284		$	2,342,107

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

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MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share amounts)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2014			2013			2014			2013
REVENUES:
Oil sales	$	131,273		$	77,636		$	247,495		$	149,854
Natural gas liquid sales	23,020			10,998			48,539			20,717
Natural gas sales	24,994			14,464			50,379			23,259
Gains (losses) on commodity derivative contracts - net	(31,467		)	22,421			(54,140		)	2,297
Other	170			489			379			903

Total revenues	147,990			126,008			292,652			197,030

EXPENSES:
Lease operating and workover	19,721			17,575			39,848			31,446
Gathering and transportation	2,940			—			5,795			—
Severance and other taxes	5,632			6,579			13,279			12,534
Asset retirement accretion	432			313			929			567
Depreciation, depletion, and amortization	71,074			52,830			137,975			94,806
Impairment in carrying value of oil and gas properties	—			—			86,471			—
General and administrative	13,434			15,272			25,118			26,298
Acquisition and transaction costs	2,483			11,492			2,611			11,492
Other	609			—			939			—

Total expenses	116,325			104,061			312,965			177,143

OPERATING INCOME (LOSS)	31,665			21,947			(20,313		)	19,887

OTHER INCOME (EXPENSE):
Interest income	9			5			19			10
Interest expense — net of amounts capitalized	(33,813		)	(16,621		)	(67,760		)	(27,488		)

Total other income (expense)	(33,804		)	(16,616		)	(67,741		)	(27,478		)

INCOME (LOSS) BEFORE TAXES	(2,139		)	5,331			(88,054		)	(7,591		)

Income tax benefit (expense)	41			(1,993		)	2,311			2,980

NET INCOME (LOSS)	$	(2,098	)	$	3,338		$	(85,743	)	$	(4,611	)

Preferred stock dividend	(4,806		)	(2,709		)	(7,426		)	(6,826		)
Participating securities - Series A Preferred Stock	—			(154		)	—			—
Participating securities - Non-vested Restricted Stock	—			(16		)	—			—


NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(6,904	)	$	459		$	(93,169	)	$	(11,437	)

Basic and diluted net income (loss) per share attributable to common shareholders	$	(0.10	)	$	0.01		$	(1.41	)	$	(0.17	)
Basic and diluted weighted average number of common shares outstanding	66,453			68,441			66,221			65,699

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

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MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

(In thousands)

	Series A Preferred Stock		Common Stock		Treasury Stock			Additional Paid-in-Capital		Retained Deficit/ Accumulated Loss			Total Stockholders’ Equity
Balance as of December 31, 2013	$	3	$	689	$	(664	)	$	871,047	$	(531,076	)	$	339,999
Share-based compensation	—		19		—			4,799		—			4,818
Acquisition of treasury stock	—		—		(1,491		)	—		—			(1,491		)
Net loss	—		—		—			—		(85,743		)	(85,743		)
Balance as of June 30, 2014	$	3	$	708	$	(2,155	)	$	875,846	$	(616,819	)	$	257,583

	Series A Preferred Stock		Common Stock		Treasury Stock			Additional Paid-in-Capital		Retained Deficit/ Accumulated Loss			Total Stockholders’ Equity
Balance as of December 31, 2012	$	3	$	666	$	—		$	830,003	$	(187,091	)	$	643,581
Share-based compensation	—		20		—			3,689		—			3,709
Acquisition of treasury stock	—		—		(605		)	—		—			(605		)
Net loss	—		—		—			—		(4,611		)	(4,611		)
Balance as of June 30, 2013	$	3	$	686	$	(605	)	$	833,692	$	(191,702	)	$	642,074

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,
	2014			2013

CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(85,743	)	$	(4,611	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Losses (gains) on commodity derivative contracts — net	54,140			(2,297		)
Net cash paid for commodity derivative contracts not designated as hedging instruments	(31,948		)	(6,075		)
Asset retirement accretion	929			567
Depreciation, depletion, and amortization	137,975			94,806
Impairment in carrying value of oil and gas properties	86,471			—
Share-based compensation, net of amounts capitalized to oil and gas properties	3,668			3,014
Deferred income taxes	(2,311		)	(2,980		)
Amortization of deferred financing costs	4,197			2,264
Change in operating assets and liabilities:
Accounts receivable — oil and gas sales	(998		)	(26,032		)
Accounts receivable — JIB and other	1,929			(7,739		)
Other current and noncurrent assets	(1,094		)	(2,147		)
Accounts payable	4,756			(4,546		)
Accrued liabilities	4,365			28,717
Other	711			(101		)

Net cash provided by operating activities	$	177,047		$	72,840

CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment	(279,033		)	(259,584		)
Investment in acquired property	—			(621,748		)
Proceeds from the sale of oil and gas properties	147,519			—

Net cash used in investing activities	$	(131,514	)	$	(881,332	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings	84,000			861,450
Repayment of long-term borrowings	(131,000		)	(34,300		)
Deferred financing costs	(545		)	(24,646		)
Acquisition of treasury stock	(1,491		)	(605		)

Net cash (used in) provided by financing activities	$	(49,036	)	$	801,899

NET DECREASE IN CASH AND CASH EQUIVALENTS	(3,503		)	(6,593		)

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

Cash and cash equivalents, end of period	$	29,660		$	12,285

SUPPLEMENTAL INFORMATION:
Non-cash transactions — investments in property and equipment accrued - not paid	$	115,000		$	104,161
Cash paid for interest, net of capitalized interest of $8.0 million and $14.9 million, respectively	63,383			19,494

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

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

1. Organization and Business

Midstates Petroleum Company, Inc., through its wholly owned subsidiary Midstates Petroleum Company LLC, engages in the business of drilling for, and production of, oil, natural gas liquids (“NGL”) and natural gas. Midstates Petroleum Company, Inc. was incorporated pursuant to the laws of the State of Delaware on October 25, 2011 to become a holding company for Midstates Petroleum Company LLC (“Midstates Sub”), which was previously a wholly owned subsidiary of Midstates Petroleum Holdings LLC (“Holdings LLC”). Pursuant to the terms of a corporate reorganization that was completed in connection with the closing of Midstates Petroleum Company, Inc.’s initial public offering on April 25, 2012, all of the interests in Midstates Petroleum Holdings LLC were exchanged for newly issued common shares of Midstates Petroleum Company, Inc., and as a result, Midstates Petroleum Company LLC became a wholly owned subsidiary of Midstates Petroleum Company, Inc. and Midstates Petroleum Holdings LLC ceased to exist as a separate entity. The terms “the Company,” “we,” “us,” “our,” and similar terms when used in the present tense, prospectively or for historical periods since April 25, 2012, refer to Midstates Petroleum Company, Inc. and its subsidiary, and for historical periods prior to April 25, 2012, refer to Midstates Petroleum Holdings LLC and its subsidiary, unless the context indicates otherwise. The term “Holdings LLC” refers solely to Midstates Petroleum Holdings LLC prior to the corporate reorganization.

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

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

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

2. Summary of Significant Accounting Policies

Basis of Presentation

These interim financial statements are unaudited and have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“GAAP”) for complete consolidated financial statements, and should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2013 included in the Company’s Annual Report on Form 10-K as filed with the SEC on March 24, 2014.

All intercompany transactions have been eliminated in consolidation. In the opinion of the Company’s management, the accompanying unaudited condensed consolidated financial statements include all adjustments, consisting of normal recurring adjustments, necessary to fairly present the financial position as of, and the results of operations for, all periods presented. In preparing the accompanying condensed consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the condensed consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

Recent Accounting Pronouncements

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

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3. Fair Value Measurements of Financial Instruments

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Derivative Instruments

Commodity derivative contracts reflected in the condensed consolidated balance sheets are recorded at estimated fair value. At June 30, 2014 and December 31, 2013, all of the Company’s commodity derivative contracts were with seven bank counterparties, and were classified as Level 2 in the fair value input hierarchy.

Derivative instruments listed below are presented gross and include collars and swaps that are carried at fair value. The Company records the net change in the fair value of these positions in “Gains (losses) on commodity derivative contracts — net” in the Company’s unaudited condensed consolidated statements of operations. See Note 4 for additional information on the Company’s derivative instruments and balance sheet presentation.

	Fair Value Measurements at June 30, 2014
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in thousands)
Assets:
Commodity derivative NGL swaps	$	—	$	153	$	—	$	153
Commodity derivative gas swaps	—		17		—		17
Commodity derivative oil collars	—		—		—		—
Commodity derivative gas collars	—		124		—		124
Commodity derivative differential swaps	—		613		—		613
Total assets	$	—	$	907	$	—	$	907

Liabilities:
Commodity derivative oil swaps	$	—	$	49,455	$	—	$	49,455
Commodity derivative NGL swaps	—		66		—		66
Commodity derivative gas swaps	—		3,830		—		3,830
Commodity derivative oil collars	—		528		—		528
Commodity derivative gas collars	—		32		—		32
Total liabilities	$	—	$	53,911	$	—	$	53,911

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

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

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4. Risk Management and Derivative Instruments

The Company’s production is exposed to fluctuations in crude oil, NGL and natural gas prices. The Company believes it is prudent to manage the variability in cash flows by entering into derivative financial instruments to economically hedge a portion of its crude oil, NGL and natural gas production. The Company utilizes various types of derivative financial instruments, including swaps and collars, to reduce fluctuations in cash flows resulting from changes in commodity prices. These derivative contracts are placed with major financial institutions that the Company believes are minimal credit risks. The oil, NGL and natural gas reference prices, upon which the commodity derivative contracts are based, reflect various market indices that management believes have a high degree of historical correlation with actual prices received by the Company for its crude oil, NGL and natural gas production.

Inherent in the Company’s portfolio of commodity derivative contracts are certain business risks, including market risk and credit risk. Market risk is the risk that the price of the commodity will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract. The Company does not require collateral from its counterparties but does attempt to minimize its credit risk associated with derivative instruments by entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. In addition, to mitigate its risk of loss due to default, the Company has entered into agreements with its counterparties on its derivative instruments that allow the Company to offset its asset position with its liability position in the event of default by the counterparty. Due to the netting arrangements, had the Company’s counterparties failed to perform under existing commodity derivative contracts, the maximum loss at June 30, 2014 would have been less than $0.1 million.

Commodity Derivative Contracts

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

	Hedged	Weighted-Average
	Volume	Fixed Price
Oil (Bbls):
WTI Swaps — 2014	2,194,000	$ 89.04
WTI Swaps — 2015	2,000,000	$87.60

WTI Collars — 2014	81,600	$ 87.83 - $ 97.86

WTI to LLS Basis Differential Swaps — 2014 (1)	229,500	$ 5.35

NGL (Bbls):
NGL Swaps — 2014	34,500	$ 61.43

Natural Gas (MMBtu):
Swaps — 2014 (2)	9,016,000	$ 4.17
Swaps — 2015	18,250,000	$ 4.13

Collars — 2014 (3)	691,002	$ 3.88 - $ 4.99

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

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

(3) Includes 101,000 MMBtus in natural gas collars that priced during the period, but had not cash settled as of June 30, 2014.

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Balance Sheet Presentation

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

Type	Balance Sheet Location (1)	June 30, 2014			December 31, 2013
Oil Swaps	Derivative financial instruments — Current Liabilities	(43,714		)	(28,871		)
Oil Swaps	Derivative financial instruments — Non-Current Liabilities	(5,741		)	(3,338		)
NGL Swaps	Derivative financial instruments — Current Assets	153			469
NGL Swaps	Derivative financial instruments — Current Liabilities	(66		)	(74		)
Gas Swaps	Derivative financial instruments — Current Assets	—			469
Gas Swaps	Derivative financial instruments — Non-Current Assets	17			19
Gas Swaps	Derivative financial instruments — Current Liabilities	(3,702		)	(496		)
Gas Swaps	Derivative financial instruments — Non-Current Liabilities	(128		)	(313		)
Oil Collars	Derivative financial instruments — Current Assets	—			64
Oil Collars	Derivative financial instruments — Current Liabilities	(528		)	(272		)
Gas Collars	Derivative financial instruments — Current Assets	124			751
Gas Collars	Derivative financial instruments — Current Liabilities	(32		)	(26		)
Basis Differential Swaps	Derivative financial instruments — Current Assets	613			806
Total derivative fair value at period end		$	(53,004	)	$	(30,812	)

(1) The fair values of commodity derivative instruments reported in the Company’s condensed consolidated balance sheets are subject to netting arrangements and qualify for net presentation. The following table summarizes the location and fair value amounts of all derivative instruments in the unaudited condensed consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the unaudited condensed consolidated balance sheets at June 30, 2014 and December 31, 2013, respectively (in thousands):

		June 30, 2014
Not Designated as ASC 815 Hedges:	Balance Sheet Classification	Gross Recognized Assets/ Liabilities		Gross Amounts Offset		Net Recognized Fair Value Assets/ Liabilities
Derivative assets:
Commodity contracts	Derivative financial instruments - current	$	890	$	890	$	—
Commodity contracts	Derivative financial instruments - noncurrent	17		—		17
		$	907	$	890	$	17
Derivative liabilities:
Commodity contracts	Derivative financial instruments - current	$	48,042	$	890	$	47,152
Commodity contracts	Derivative financial instruments - noncurrent	5,869		—		5,869
		$	53,911	$	890	$	53,021

		December 31, 2013
Not Designated as ASC 815 Hedges:	Balance Sheet Classification	Gross Recognized Assets/ Liabilities		Gross Amounts Offset		Net Recognized Fair Value Assets/ Liabilities
Derivative assets:
Commodity contracts	Derivative financial instruments - current	$	2,559	$	1,859	$	700
Commodity contracts	Derivative financial instruments - noncurrent	19		—		19
		$	2,578	$	1,859	$	719
Derivative liabilities:
Commodity contracts	Derivative financial instruments - current	$	29,739	$	1,859	$	27,880
Commodity contracts	Derivative financial instruments - noncurrent	3,651		—		3,651
		$	33,390	$	1,859	$	31,531

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Gains (losses) on Commodity Derivative Contracts

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

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2014			2013			2014			2013
	(in thousands)						(in thousands)
Realized net losses	$	(17,138	)	$	(1,071	)	$	(31,948	)	$	(6,075	)
Unrealized net gains (losses)	(14,329		)	23,492			(22,192		)	8,372
Gains (losses) on commodity derivative contracts - net	$	(31,467	)	$	22,421		$	(54,140	)	$	2,297

5. Property and Equipment

	June 30, 2014			December 31, 2013
	(in thousands)
Oil and gas properties, on the basis of full-cost accounting:
Proved properties	$	3,056,395		$	2,817,062
Unevaluated properties	134,532			243,599
Other property and equipment	12,691			11,113
Less accumulated depreciation, depletion, amortization and impairment	(1,201,060		)	(976,880		)
Net property and equipment	$	2,002,558		$	2,094,894

Oil and Gas Properties

The Company capitalizes internal costs directly related to exploration and development activities to oil and gas properties. During the three and six months ended June 30, 2014 and 2013, the Company capitalized the following (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013

Internal costs capitalized to oil and gas properties (1)	$	3,325	$	1,908	$	6,449	$	3,396

(1) Inclusive of $0.6 million and $0.4 million of qualifying share-based compensation expense for the three months ended June 30, 2014 and 2013, respectively. For the six months ended June 30, 2014 and 2013, inclusive of $1.2 million and $0.7 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 unproved and unevaluated properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanying condensed consolidated statements of operations.

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At June 30, 2014 and June 30, 2013 capitalized costs did not exceed the ceiling and an impairment to oil and gas properties was not required. An impairment of $83.5 million (after tax) to oil and gas properties was recorded during the six months ended June 30, 2014 as a result of the capitalized costs exceeding the ceiling at March 31, 2014.

Depreciation, depletion and amortization is calculated using the Units of Production Method (“UOP”). The UOP calculation multiplies the percentage of estimated proved reserves produced by the cost of those reserves. The result is to recognize expense at the same pace that the reservoirs are estimated to be depleting. The amortization base in the UOP calculation includes the sum of proved property costs net of accumulated depreciation, depletion and amortization (“DD&A”), estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs that are not already included in oil and gas property, less related salvage value. The following table presents depletion expense related to oil and gas properties for the three and six months ended June 30, 2014 and 2013, respectively:

	Three Months Ended June 30,								Six Months Ended June 30,
	2014		2013		2014		2013		2014		2013		2014		2013
	(in thousands)				(per Boe)				(in thousands)				(per Boe)
Depletion expense	$	70,323	$	52,256	$	24.22	$	29.24	$	136,527	$	93,845	$	24.76	$	28.92
Depreciation on other property	751		574		0.25		0.32		1,448		961		0.26		0.29
Depreciation, depletion, and amortization	$	71,074	$	52,830	$	24.47	$	29.56	$	137,975	$	94,806	$	25.02	$	29.21

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 $134.5 million at June 30, 2014 compared to $243.6 million at December 31, 2013, decreasing primarily due to property transfers with a value of approximately $61.9 million and $48.3 million related to the Anadarko Basin and Mississippian Lime areas, 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.

Anadarko Basin Acquisition—May 2013

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

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

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

Net assets acquired	$	619,060

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

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Actual and Pro Forma Information

Revenues attributable to the Anadarko Basin Acquisition included in the Company’s unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2014 were $51.6 million and $102.4 million, respectively. Revenues attributable to the Anadarko Basin Acquisition included in the Company’s unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2013 was $14.2 million for both periods.

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

	For the Three Months Ended June 30, 2013			For the Six Months Ended June 30, 2013
Revenues and other	$	154,225		$	267,086
Net income (loss)	9,949			(1,695		)
Preferred stock dividends	(2,709		)	(6,826		)
Net income (loss) attributable to common shareholders	$	7,240		$	(8,521	)
Net income (loss) per common share - basic and diluted	$	0.11		$	(0.13	)

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

Pine Prairie Disposition

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

6. Other Noncurrent Assets

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

	June 30, 2014		December 31, 2013
	(in thousands)
Deferred financing costs	$	41,055	$	44,706
Field inventory	9,676		9,682
Other	211		209
Other noncurrent assets	$	50,942	$	54,597

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7. Accrued Liabilities

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

	June 30, 2014		December 31, 2013
	(in thousands)
Accrued oil and gas capital expenditures	$	87,838	$	87,202
Accrued revenue and royalty distributions	60,488		64,370
Accrued lease operating and workover expense	8,052		8,279
Accrued interest	21,521		21,341
Accrued taxes	7,026		4,386
Other	23,058		18,803
Accrued liabilities	$	207,983	$	204,381

8. Asset Retirement Obligations

Asset Retirement Obligations (“AROs”) represent the future abandonment costs of tangible assets, such as wells, service assets and other facilities. The fair value of the ARO at inception is capitalized as part of the carrying amount of the related long-lived assets. AROs approximated $20.4 million and $26.3 million as of June 30, 2014 and December 31, 2013, respectively, and the liability has been accreted to its present value as of June 30, 2014 and December 31, 2013.

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

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

Asset retirement obligations at January 1, 2014	$	26,308
Liabilities incurred	844
Revisions	—
Liabilities settled	(47		)
Liabilities eliminated through asset sale (1)	(7,652		)
Current period accretion expense	929
Asset retirement obligations at June 30, 2014	$	20,382

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

9. Long-Term Debt

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

	At June 30, 2014		At December 31, 2013
	(in thousands)
Revolving credit facility, due 2018	$	354,150	$	401,150
Senior notes, due 2020	600,000		600,000
Senior notes, due 2021	700,000		700,000
Long-term debt	$	1,654,150	$	1,701,150

Reserve-based Credit Facility

As of June 30, 2014, the Company’s credit facility consisted of a $750 million senior revolving credit facility (the “Credit Facility”) with a borrowing base supported by the Company’s Mississippian Lime and Anadarko Basin oil and gas assets of $475 million, as recently reaffirmed in the Fifth Amendment thereto on March 28, 2014. At June 30, 2014, outstanding letters of credit obligations total $0.2 million.

The Fifth Amendment amended the Credit Facility to (i) permit Midstates Sub to enter into the $125 million Senior Secured Bridge Facility (“Bridge Facility”) secured by the Company’s Gulf Coast Assets and intended to provide the Company with additional sources of liquidity in the event the sale of the Company’s Pine Prairie assets was delayed for any reason, (ii) affirm the current borrowing base thereunder of $500 million, and (iii) provide for a decrease of the borrowing base to $475 million upon, among other things, the closing of the sale of Midstates Sub’s ownership interest in developed and undeveloped acreage in the Pine Prairie field

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area of Evangeline Parish, Louisiana for consideration equal to or greater than $100 million (“Pine Prairie Disposition”) or the entry into the Bridge Facility. Additionally, the Fifth Amendment amended certain provisions of the Credit Facility to, among other things, (i) subject to certain events, including the closing of the Pine Prairie Disposition, release Midstates Sub’s Louisiana assets from liens securing the Credit Facility, (ii) increase the applicable margin for LIBOR Loans from a range of 1.75% to 2.75% depending on borrowing base utilization to a range of 2.00% to 3.00%, with corresponding changes to the applicable margin for base rate loans, (iii) amend the leverage ratio to be (A) 4.75:1.00 for the quarter ending March 31, 2014, (B) 4.50:1.00 for the quarter ending June 30, 2014, (C) 4.25:1.00 for the quarters ending September 30, 2014 and December 31, 2014 and (D) 4.00:1.00 for each quarter thereafter; provided that the leverage ratio shall be increased by 0.50 for the quarter of, and the two quarters following, the consummation of the Pine Prairie Disposition and (iv) allow for the Bridge Facility to be secured by a second lien on Midstates Sub’s Mississippian Lime and Anadarko Basin assets. As consideration for the participating lenders’ consent to the Fifth Amendment, Midstates Sub paid a 0.10% amendment fee on the $475 million borrowing base.

On May 1, 2014, the Company completed the Pine Prairie Disposition (see Note 5) and concurrently terminated the commitment to provide the Bridge Facility that was entered into on March 9, 2014 with SunTrust Bank, SunTrust Robinson Humphrey, Inc., Morgan Stanley Senior Funding, Inc., Bank of America N.A., Goldman Sachs Bank USA, Merrill Lynch, Piece, Fenner & Smith Incorporated, Natixis New York Branch and Royal Bank of Canada and paid commitment fees and expenses of $2.3 million pursuant to the terms of the commitment letter.

With the completion of the Pine Prairie Disposition and pursuant to the Fifth Amendment, the borrowing base under the Company’s Credit Facility was reduced to $475 million and the leverage ratio covenant thereunder was amended to be (i) 5:00:1.00 for the quarter ending June 30, 2014, and (ii) 4.75:1.00 for the quarters ending September 30, 2014 and December 31, 2014. The leverage ratio decreases to 4.00:1.00 for each quarter thereafter.

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, 2014 and 2013, the weighted average interest rate was 2.8% and 2.5%, respectively.

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

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

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

As of June 30, 2014, the Company was in compliance with the minimum current ratio and the ratio of debt to EBITDA covenants as set forth in the Credit Facility. The Company’s current ratio at June 30, 2014 was 1.31 to 1.0. At June 30, 2014, the Company’s ratio of debt to EBITDA was 3.96 to 1.0.

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

2020 Senior Notes

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

The 2020 Senior Notes Indenture contains covenants that, among other things, restrict the Company’s ability to: (i) incur additional indebtedness, guarantee indebtedness or issue certain preferred shares; (ii) make loans, investments and other restricted payments; (iii) pay dividends

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

The estimated fair value of the 2020 Senior Notes was $681.0 million as of June 30, 2014 (Level 2 in the fair value measurement hierarchy based on the limited trading volume on the secondary market), based on quoted market prices for these same debt securities. The effective annual interest rate for the 2020 Senior Notes was approximately 11.1% for the three and six months ended June 30, 2014 and 2013.

2021 Senior Notes

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

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

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

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

The estimated fair value of the 2021 Senior Notes was $770.0 million as of June 30, 2014 (Level 2 in the fair value measurement hierarchy based on the limited trading volume on the secondary market), based on quoted market prices for these same debt securities. The effective annual interest rate for the 2021 Senior Notes was approximately 9.6% for the three and six months ended June 30, 2014 and approximately 9.9% for the three and six months ended June 30, 2013.

10. Equity and Share-Based Compensation

Common and Preferred Shares

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

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

Series A Preferred Stock

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

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weighted average price of the Company’s common stock during the 15 trading days immediately prior to September 30, 2015. The Series A Preferred Stock was issued on October 1, 2012.

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

For the three months ended March 31, 2014, the $2.6 million Series A Preferred Stock dividend (paid through the adjustment to the liquidation preference) was based upon the estimated fair value of 639,127 common shares that would have been issued had the Series A preferred Stock dividend for the three months been converted into common shares using a conversion price of $11.00 per share.

The Company did not declare any dividends on the Series A Preferred Stock for the three months ended June 30, 2014; however, if it had, Series A Preferred Stockholders would have been entitled to $7.3 million of cash dividends or, if paid through an adjustment to the Series A Preferred Share liquidation preference, a number of additional common shares issuable upon conversion of the Series A Preferred Shares of between 541,601 and 664,692, the ultimate number of common shares dependent upon the then in effect conversion price. 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, 2014, the $4.8 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 664,692 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 $11.00 per share.

Share Activity

The following table summarizes changes in the number of outstanding shares since December 31, 2013:

	Number of Shares
	Series A Preferred Stock	Common Stock		Treasury Stock
Share count as of December 31, 2013	325,000	68,925,745		(118,702	)
Grants of restricted stock	—	3,000,128		—
Forfeitures of restricted stock	—	(1,068,797	)	—
Acquisition of treasury stock	—	—		(279,354	)
Share count as of June 30, 2014	325,000	70,857,076		(398,056	)

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, 2014, 1,179 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.

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Share-based Compensation, Post-Initial Public Offering

2012 Long Term Incentive Plan

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

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

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

Non-vested Stock Awards

At June 30, 2014, the Company had 3,907,992 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, 2014:

	Shares		Weighted Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2013	2,963,672		$	7.78
Granted	3,000,128		$	4.90
Vested	(987,011	)	$	7.79
Forfeited	(1,068,797	)	$	7.32
Non-vested shares outstanding at June 30, 2014	3,907,992		$	5.69

Unrecognized expense, adjusted for estimated forfeitures, as of June 30, 2014 for all outstanding restricted stock awards was $18.0 million and will be recognized over a weighted average period of 2.3 years.

At June 30, 2014, 3,415,712 shares remain available for issuance under the terms of the 2012 LTIP.

11. Income Taxes

Prior to its corporate reorganization (See Note 1), the Company was a limited liability company and not subject to federal income tax or state income tax (in most states). Accordingly, no provision for federal or state income taxes was recorded prior to the corporate reorganization as the Company’s equity holders were responsible for income tax on the Company’s profits. In connection with the closing of the Company’s initial public offering, the Company merged into a corporation and became subject to federal and state income taxes.

The Company has recorded a tax benefit on its year-to-date pre-tax loss. The Company believes this methodology to be more appropriate at this time due to uncertainty in forecasting the annual effective tax rate (or benefit) on 2014 income (or loss) due to previously recorded property impairments and the effects of federal and state valuation allowance adjustments.

For the six months ended June 30, 2014, the Company’s effective tax rate was a benefit of approximately 2.6%. 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. This year, the Company recorded $30.1 million in additional valuation allowance in light of the impairment of oil and gas properties bringing the total valuation allowance to $75.8 million at June 30, 2014. 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.

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

12. Earnings (Loss) Per Share

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

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

The following table (in thousands, except per share amounts) provides a reconciliation of net income (losses) to preferred shareholders, common shareholders, and non-vested restricted shareholders for purposes of computing net income (loss) per share for the three and six months ended June 30, 2014 and 2013, respectively:

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Net income (loss)	$	(2,098	)	$	3,338		$	(85,743	)	$	(4,611	)
Preferred Dividend (1)	(4,806		)	(2,709		)	(7,426		)	(6,826		)
Net income (loss) attributable to shareholders	$	(6,904	)	$	629		$	(93,169	)	$	(11,437	)

Participating securities - Series A Preferred Stock (2)	—			(154		)	—			—
Participating securities - Non-vested Restricted Stock (2)	—			(16		)	—			—
Net income (loss) attributable to common shareholders	$	(6,904	)	$	459		$	(93,169	)	$	(11,437	)

Weighted average shares outstanding	66,453			68,441			66,221			65,699
Net income (loss) per share	$	(0.10	)	$	0.01		$	(1.41	)	$	(0.17	)

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

(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, 2014 was 70,459,020 of which 3,907,992 were non-vested restricted shares. The aggregate number of shares of Series A Preferred Stock outstanding at June 30, 2014 was 325,000, each with a liquidation preference of $1,147 representing on an as-converted basis approximately 33,899,311 million common shares based upon a conversion price of $11.00 per share, which have been excluded from the weighted average shares outstanding for EPS purposes for the three and six months ended June 30, 2014 due to their anti-dilutive effect.

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13. Commitments and Contingencies

Contractual Obligations

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

	Total		2014		2015		2016		2017 and beyond
Drilling contracts	$	10,110	$	10,110	$	—	$	—	$	—
Non-cancellable office lease commitments	10,239		918		1,858		1,878		5,585
Seismic contracts	3,192		3,192		—		—		—
Net minimum commitments	$	23,541	$	14,220	$	1,858	$	1,878	$	5,585

For the three months ended June 30, 2014 and 2013, the Company expensed $0.7 million and $0.5 million, respectively, for office rent. For the six months ended June 30, 2014 and 2013, the Company expensed $1.2 million and $0.9 million, respectively, for office rent.

In addition to the commitments noted in the above table, the Company is party to a gas transportation, gathering and processing contract (as amended and effective June 1, 2013) in the Mississippian Lime region, which includes certain minimum natural gas and NGL volume commitments. To the extent the Company does not deliver natural gas volumes in sufficient quantities to generate, when processed, the minimum levels of recovered NGL, the Company would be required to reimburse the counterparty an amount equal to the sum of the monthly shortfall, if any, multiplied by a fee of roughly $0.06 to $0.125 per gallon (subject to annual escalation). The NGL volume commitments range from 2,800 Bbls to 5,460 Bbls per day over the remaining term of the contract. Additionally, the Company is obligated to deliver a total of 38,100,000 MMBtus and 76,200,000 MMBtus during the first 30 months and 60 months of the contract, respectively. During the first 30 months, any shortfall in delivered volumes would result in a payment to the counterparty equal to the shortfall amount multiplied by a fee of approximately $0.36 per MMBtu. During the first 60 months, any shortfall in delivered volumes would result in a payment to the counterparty equal to the shortfall amount multiplied by a fee of approximately $0.36 per MMBtu, provided that the Company would receive volumetric credit for any deficiency payment made after the initial 30 months. The Company is currently delivering at least the minimum volumes required under these contractual provisions and does not expect to incur any future volumetric shortfall payments during the term of this contract.

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

Litigation

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

14. Subsequent Events

On June 25, 2014, the Company entered into an exploration agreement with PetroQuest Energy LLC (“PetroQuest”) with an effective date of May 1, 2014, in which the Company conveyed to PetroQuest an undivided 50% of its right, title and interest in and to its acreage and other interests in its Fleetwood prospect area in Louisiana and added PetroQuest as an additional licensee under the terms of its 3D license agreement.

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

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

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

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in or incorporated by reference into this report are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, and the plans, beliefs, expectations, intentions and objectives of management are forward-looking statements. When used in this quarterly report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” and similar expressions are intended to identify forward looking statements, although not all forward looking statements contain such identifying words. In particular, the factors discussed in this report on Form 10-Q and detailed in our annual report filed on Form 10-K dated and filed with the SEC on March 24, 2014, could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements.

Forward-looking statements may include statements about our:

· business strategy;

· estimated future net reserves and present value thereof;

· technology;

· cash flows and liquidity;

· financial strategy, budget, projections and operating results;

· oil and natural gas realized prices;

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

· availability of drilling and production equipment;

· availability of oilfield labor;

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

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

· availability and terms of capital;

· drilling of wells, including our identified drilling locations;

· successful results from our identified drilling locations;

· marketing of oil and natural gas;

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

· infrastructure for salt water disposal and electricity;

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

· costs of developing our properties and conducting other operations;

· general economic conditions;

· effectiveness of our risk management activities;

· environmental liabilities;

· counterparty credit risk;

· the outcome of pending and future litigation;

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

· developments in oil producing and natural gas producing countries;

· uncertainty regarding our future operating results; and

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

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

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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, 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 million in cash (the “Anadarko Basin Acquisition”), before customary post-closing adjustments. The Company funded the purchase price with a portion of the net proceeds from the private placement of $700 million in aggregate principal amount of 9.25% senior unsecured notes due 2021 (the “2021 Senior Notes” and, together with the 2020 Senior Notes, the “Senior Notes”), which also closed on May 31, 2013. Subsequent to the closing of the Eagle Property Acquisition and the Anadarko Basin Acquisition, the Company has oil and gas operations and properties in Louisiana, Oklahoma and Texas.

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

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

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

Pine Prairie Disposition

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

Exploration Agreement with PetroQuest

On June 25, 2014, we entered into an exploration agreement with PetroQuest Energy LLC (“PetroQuest”) with an effective date of May 1, 2014, in which we conveyed to PetroQuest an undivided 50% of our right, title and interest in and to our acreage and other interests in the Fleetwood prospect area in Louisiana and added PetroQuest as an additional licensee under the terms of our 3D license agreement.

With the execution of the agreement, PetroQuest paid us $3.0 million in cash consideration (paid on July 3, 2014) and, on or before January 5, 2015, PetroQuest will pay additional cash of $7.0 million. As further consideration, PetroQuest granted a credit to us (or will pay on our behalf) an additional non-interest bearing total sum of $14.0 million, to be credited or paid against our share of cost or expenses incurred to develop the prospect area, including but not limited to, all mineral lease acquisition or maintenance costs and all

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drilling, completion, equipping and facility costs. For any amounts not fully paid or credited on or before December 31, 2015, we can elect to take the remaining portion in cash.

Operations Update

Mississippian Lime

At June 30, 2014 our Mississippian Lime assets consisted of approximately 77,500 net prospective acres in the Mississippian Lime trend, with 73,000 net acres in Woods and Alfalfa Counties of Oklahoma, which we currently believe is the core of the trend. We currently plan to develop these liquids rich properties using horizontal wells. We also own approximately 12,900 net acres in Lincoln County, Oklahoma, which produces from, and is prospective in, the Hunton formation. At quarter-end, we held an average working interest in our Mississippian Lime and Hunton acreage of 68%.

At June 30, 2014, our properties in the Mississippian Lime (also including Hunton) area consisted of approximately 242 gross active producing wells, 90% of which we operate.

For the three months ended June 30, 2014 and March 31, 2014, our average daily production from the Mississippian Lime area was as follows:

	Three Months Ended June 30, 2014	Three Months Ended March 31, 2014	Increase (Decrease) in Production

Average daily production:
Oil (Bbls)	8,221	6,081	35	%
Natural gas liquids (Bbls)	4,445	3,497	27	%
Natural gas (Mcf)	48,185	40,816	18	%
Net boe/day	20,698	16,381	26	%

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 2014:

		Total Number of Gross Horizontal Wells Spud (1)		Total Number of Gross Horizontal Wells Brought into Production
Mississippian Lime		23		25

(1) We had seven rigs drilling in the Mississippian Lime horizontal well program at June 30, 2014. Of the 23 wells spud, 10 were producing, nine were awaiting completion and four were being drilled at quarter-end.

Overall production increased by 26% versus the first quarter of 2014 as a result of our increased drilling and completion activity. In addition, first quarter production was negatively impacted by significant weather related downtime and consequent delays in well completions.

In the second quarter of 2014, we invested approximately $93.0 million on completions and drilling new wells. We also fracture stimulated and returned to production 10 wells initially produced as ‘open hole’ completions.

Anadarko Basin

Our Anadarko Basin assets were acquired on May 31, 2013, and at June 30, 2014, consisted of approximately 131,500 net acres in the Anadarko Basin, of which 100,500 acres were located in Texas and 31,000 acres were located in western Oklahoma. At quarter-end, we held an average working interest in our Anadarko Basin acreage of 80%.

At June 30, 2014, our properties in the Anadarko Basin area consisted of approximately 353 gross active producing wells, 85% of which we operate.

For the three months ended June 30, 2014 and March 31, 2014, our average daily production from our Anadarko Basin area was as follows:

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	Three Months Ended June 30, 2014	Three Months Ended March 31, 2014	Increase in Production

Average daily production:
Oil (Bbls)	4,380	4,343	1	%
Natural gas liquids (Bbls)	1,780	1,693	5	%
Natural gas (Mcf)	16,348	14,040	16	%
Net boe/day	8,885	8,376	6	%

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

		Total Number of Gross Horizontal Wells Spud (1)		Total Number of Gross Horizontal Wells Brought into Production
Anadarko Basin		9		15

(1) We had three rigs drilling in the Anadarko Basin area at June 30, 2014. Of the nine wells spud, three were producing, four were awaiting completion and two were being drilled at quarter-end.

Overall production increased by 6% versus the first quarter of 2014 as a result of increased drilling and completion activity. Additionally, first quarter production was negatively impacted by significant weather downtime. During the second quarter we invested approximately $45.5 million on completions and new drilling, spud nine wells and brought 15 wells online (comprised of eight Cleveland wells, two Cottage Grove wells and five Marmaton wells).

Gulf Coast

In our Gulf Coast region, our current acreage positions and evaluation efforts are concentrated in Louisiana in the Wilcox interval of the Upper Gulf Coast Tertiary trend. We have applied modern formation evaluation, drilling and completion techniques to the trend and our historical development operations in the Gulf Coast area focused on drilling vertical and horizontal wells and commingling production from multi-stage hydraulically-fractured completions across stacked oil-producing intervals.

As discussed above, we closed on the sale of producing properties and undeveloped acreage in the Pine Prairie Field area of Evangeline Parish, Louisiana on May 1, 2014 for estimated net proceeds of $147.5 million in cash, after post-closing adjustments. The sale has an effective date of November 1, 2013. Acreage subject to the transaction totaled 3,907 gross (3,757 net) acres, and does not include our acreage and production in the western part of Louisiana in Beauregard Parish or other undeveloped acreage held outside the Pine Prairie field. These assets contributed approximately 1,264 Boe/day to our production through the six months ended June 30, 2014.

At June 30, 2014, after the Pine Prairie Disposition, we had approximately 71,400 net acres in the trend (45,700 net acres after accounting for the exploration agreement with PetroQuest which closed subsequent to June 30, 2014). At quarter-end, we held an average working interest of 97% in our Gulf Coast acreage.

At June 30, 2014, our properties in the Gulf Coast area consisted of approximately 49 gross active producing wells, 100% of which we operate.

For the three months ended June 30, 2014 and March 31, 2014, our average daily production from the Gulf Coast area was as follows:

	Three Months Ended June 30, 2014	Three Months Ended March 31, 2014	Decrease in Production

Average daily production:
Oil (Bbls)	1,688	2,993	-44	%
Natural gas liquids (Bbls)	384	722	-47	%
Natural gas (Mcf)	1,544	3,192	-52	%
Net boe/day	2,329	4,247	-45	%

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Overall production decreased by 45% versus the first quarter of 2014, as second quarter results included only one month of production from the assets that were sold as part of the Pine Prairie Disposition effective May 1, 2014. In addition, we have continued to devote our capital to developing our Mississippian Lime and Anadarko Basin assets; however, we plan to continue to evaluate our acreage as well as other potential exploration opportunities in the Gulf Coast area.

For the quarter ended June 30, 2014, we invested approximately $2.2 million in the Gulf Coast area. No wells were spud or brought into production in our Gulf Coast area of operation during the second quarter of 2014.

Capital Expenditures

During the three and six months ended June 30, 2014, we incurred operational capital expenditures of $140.6 million and $275.9 million, respectively, which consisted primarily of:

	For the Three Months Ended June 30, 2014		For the Six Months Ended June 30, 2014
	(in thousands)
Drilling and completion activities	$	132,287	$	264,379
Acquisition of acreage and seismic data	8,324		11,476
Operational capital expenditures incurred	$	140,611	$	275,855
Capitalized G&A, Office, ARO, & Other	4,533		7,377
Capitalized interest	3,344		7,962
Total capital expenditures incurred	$	148,488	$	291,194

Operational capital expenditures were incurred in the various areas:

	For the Three Months		For the Six Months
	Ended June 30, 2014		Ended June 30, 2014
	(in thousands)
Mississippian Lime	$	92,988	$	178,771
Anadarko Basin	45,452		91,812
Gulf Coast	2,171		5,272
Total capital expenditures incurred	$	140,611	$	275,855

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

Factors that Significantly Affect our Results

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

We generally hedge a portion of our expected future oil and gas production to reduce our exposure to fluctuations in commodity price. By removing a portion of commodity price volatility, we expect to reduce some of the variability in our cash flow from operations. See “Item 3. — Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Exposure” beginning on page 38 for discussion of our hedging and hedge positions.

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

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

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

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

· facility or equipment availability and unexpected downtime;

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

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

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

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Results of Operations

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

Revenues

	For the Three Months Ended June 30,										For the Six Months Ended June 30,
	2014					2013					2014					2013
	(in thousands)										(in thousands)
REVENUES:
Oil sales	$	131,273		73	%	$	77,636		75	%	$	247,495		71	%	$	149,854		77	%
Natural gas liquid sales	23,020			13	%	10,998			11	%	48,539			14	%	20,717			11	%
Natural gas sales	24,994			14	%	14,464			14	%	50,379			15	%	23,259			12	%
Total oil, natural gas, and natural gas liquids sales	179,287			100	%	103,098			100	%	346,413			100	%	193,830			100	%

Realized losses on commodity derivative contracts, net	(17,138		)	54	%	(1,071		)	-5	%	(31,948		)	59	%	(6,075		)	-264	%
Unrealized gains (losses) on commodity derivative contracts, net	(14,329		)	46	%	23,492			105	%	(22,192		)	41	%	8,372			364	%
Gains (losses) on commodity derivative contracts - net	(31,467		)	100	%	22,421			100	%	(54,140		)	100	%	2,297			100	%

Other	170					489					379					903

Total revenues	$	147,990				$	126,008				$	292,652				$	197,030

Production

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2014	2013	% Change		2014	2013	% Change
PRODUCTION DATA:
Oil (MBbls)	1,300	796	63	%	2,508	1,510	66	%
Natural gas liquids (MBbls)	601	311	93	%	1,134	589	93	%
Natural gas (MMcf)	6,013	4,078	47	%	11,237	6,879	63	%
Oil equivalents (MBoe)	2,904	1,787	63	%	5,514	3,245	70	%

Oil (Boe/day)	14,290	8,747	63	%	13,856	8,345	66	%
Natural gas liquids (Boe/day)	6,609	3,419	93	%	6,263	3,251	93	%
Natural gas (Mcf/day)	66,078	44,808	47	%	62,085	38,005	63	%
Average daily production (Boe/day)	31,912	19,634	63	%	30,466	17,930	70	%

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Prices

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2014		2013		% Change		2014		2013		% Change
AVERAGE SALES PRICES:
Oil, without realized derivatives (per Bbl)	$	100.95	$	97.54	3	%	$	98.69	$	99.21	-1	%
Oil, with realized derivatives (per Bbl)	$	89.12	94.86		-6	%	$	88.13	94.13		-6	%
Natural gas liquids, without realized derivatives (per Bbl)	$	38.27	35.34		8	%	$	42.82	35.20		22	%
Natural gas liquids, with realized derivatives (per Bbl)	$	38.52	37.41		3	%	$	42.88	36.89		16	%
Natural gas, without realized derivatives (per Mcf)	$	4.16	3.55		17	%	$	4.48	3.38		33	%
Natural gas, with realized derivatives (per Mcf)	$	3.84	3.65		5	%	$	3.99	3.47		15	%

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

Oil, natural gas liquids and natural gas sales revenues

Our oil, NGL and natural gas sales revenues increased by $76.2 million, or 74%, to $179.3 million during the three months ended June 30, 2014, as compared to $103.1 million during the three months ended June 30, 2013.

Our oil sales revenues increased by $53.7 million, or 69%, to $131.3 million during the three months ended June 30, 2014, as compared to $77.6 million for the three months ended June 30, 2013. Oil volumes sold increased 5,543 Boe/day, or 63%, to 14,290 Boe/day for the three months ended June 30, 2014, from 8,747 Boe/day for the three months ended June 30, 2013. This increase in oil volumes sold was attributable to increased production quarter over quarter in the Mississippian Lime area of 4,817 Boe/day, and 3,113 Boe/day of additional production volumes from our Anadarko Basin area (the 2013 comparative period included only one month of results due to the timing of the Anadarko Basin Acquisition), partially offset by a decrease in volumes from our Gulf Coast region of 2,387 Boe/day primarily due to the Pine Prairie Disposition and reduced development drilling activity during the 2014 period. Average oil sales prices, without realized derivatives, increased by $3.41 per barrel to $100.95 per barrel during the three months ended June 30, 2014 as compared to $97.54 per barrel for the three months ended June 30, 2013.

Our NGL sales revenues increased by $12.0 million, or 109%, to $23.0 million during the three months ended June 30, 2014, as compared to $11.0 million for the three months ended June 30, 2013. NGL volumes sold increased 3,190 Boe/day, or 93%, to 6,609 Boe/day for the three months ended June 30, 2014, from 3,419 Boe/day for the three months ended June 30, 2013. This increase in NGL volumes sold was attributable to the increased production quarter over quarter in the Mississippian Lime area of 2,669 Boe/day and 1,226 Boe/day of additional production volumes from our Anadarko Basin area (the 2013 comparative period included only one month of results due to the timing of the Anadarko Basin Acquisition), partially offset by a 705 Boe/day decrease in production from our Gulf Coast area primarily due to the Pine Prairie Disposition and reduced development drilling activity during the 2014 period. Average NGL sales prices, without realized derivatives, increased by $2.93 per barrel, or 8%, to $38.27 per barrel during the three months ended June 30, 2014 as compared to $35.34 per barrel for the corresponding period in 2013.

Our natural gas sales revenues increased by $10.5 million, or 72%, to $25.0 million during the three months ended June 30, 2014, as compared to $14.5 million for the three months ended June 30, 2013. Natural gas volumes sold increased 21,270 Mcf/day or 47%, to 66,078 Mcf/day for the three months ended June 30, 2014, from 44,808 Mcf/day for the three months ended June 30, 2013. This increase in natural gas volumes sold was attributable to increased production of 16,709 Mcf/day in the Mississippian Lime area and 11,274 Mcf/day of additional production volumes from our Anadarko Basin area (the 2013 comparative period included only one month of results due to the timing of the Anadarko Basin Acquisition), partially offset by a decrease in production of 6,713 Mcf/day from our Gulf Coast area primarily due to the Pine Prairie Disposition and reduced development drilling activity during the 2014 period. Average natural gas sales prices, without realized derivatives, increased by $0.61 per Mcf, or 17% to $4.16 per Mcf during the three months ended June 30, 2014 as compared to $3.55 per Mcf for the three months ended June 30, 2013.

Gains/losses on commodity derivative contracts - net

Our mark-to-market (“MTM”) derivative positions moved from an unrealized gain of $23.5 million for the three months ended June 30, 2013 to an unrealized loss of $14.3 million for the three months ended June 30, 2014. We entered into additional derivative contracts during the second quarter of 2014. The NYMEX WTI closing price on June 30, 2014 was $105.37 per barrel compared to a closing price of $96.56 per barrel on June 28, 2013 (the last day of trading for the period).

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The realized loss on derivatives for the three months ended June 30, 2014 was $17.1 million, compared to a realized loss of $1.1 million for the three months ended June 30, 2013. The following table presents realized gain (loss) by type of commodity contract for the three months ended June 30, 2014:

	For the Three Months Ended June 30, 2014
	Realized Gain (Loss)			Average Sales Price
	(in thousands)
Oil commodity contracts	$	(15,389	)	$	89.12
Natural gas liquids commodity contracts	151			38.52
Natural gas commodity contracts	(1,900		)	3.84
Realized losses on commodity derivative contracts, net	$	(17,138	)

Six Months Ended June 30, 2014 as Compared to the Six Months Ended June 30, 2013

Oil, natural gas liquids and natural gas sales revenues

Our oil, NGL and natural gas sales revenues increased by $152.6 million, or 79%, to $346.4 million during the six months ended June 30, 2014, as compared to $193.8 million during the six months ended June 30, 2013.

Our oil sales revenues increased by $97.7 million, or 65%, to $247.5 million during the six months ended June 30, 2014, as compared to $149.8 million for the six months ended June 30, 2013. Oil volumes sold increased 5,511 Boe/day, or 66%, to 13,856 Boe/day for the six months ended June 30, 2014, from 8,345 Boe/day for the six months ended June 30, 2013. This increase in oil volumes sold was attributable to increased production period over period in the Mississippian Lime area of 3,744 Boe/day and 3,724 Boe/day of additional production volumes from our Anadarko Basin area (the 2013 comparative period included only one month of results due to the timing of the Anadarko Basin Acquisition), partially offset by a decrease in volumes from our Gulf Coast region of 1,957 Boe/day primarily due to the Pine Prairie Disposition and reduced development drilling activity during the 2014 period. Average oil sales prices, without realized derivatives, decreased by $0.52 per barrel to $98.69 per barrel during the six months ended June 30, 2014 as compared to $99.21 per barrel for the six months ended June 30, 2013.

Our NGL sales revenues increased by $27.8 million, or 134%, to $48.5 million during the six months ended June 30, 2014, as compared to $20.7 million for the six months ended June 30, 2013. NGL volumes sold increased 3,012 Boe/day, or 93%, to 6,263 Boe/day for the six months ended June 30, 2014, from 3,251 Boe/day for the six months ended June 30, 2013. This increase in NGL volumes sold was attributable to the increased production period over period in the Mississippian Lime area of 2,035 Boe/day and 1,459 Boe/day of additional production volumes from our Anadarko Basin area (the 2013 comparative period included only one month of results due to the timing of the Anadarko Basin Acquisition), partially offset by a 482 Boe/day decrease in production from our Gulf Coast area primarily due to the Pine Prairie Disposition and reduced development drilling activity during the 2014 period. Average NGL sales prices, without realized derivatives, increased by $7.62 per barrel, or 22%, to $42.82 per barrel during the six months ended June 30, 2014 as compared to $35.20 per barrel for the corresponding period in 2013.

Our natural gas sales revenues increased by $27.1 million, or 116%, to $50.4 million during the six months ended June 30, 2014, as compared to $23.3 million for the six months ended June 30, 2013. Natural gas volumes sold increased 24,080 Mcf/day or 63%, to 62,085 Mcf/day for the six months ended June 30, 2014, from 38,005 Mcf/day for the six months ended June 30, 2013. This increase in natural gas volumes sold was attributable to increased production of 16,939 Mcf/day in the Mississippian Lime area and 12,648 Mcf/day of additional production volumes from our Anadarko Basin area (the 2013 comparative period included only one month of results from these properties due to the timing of the Anadarko Basin Acquisition), partially offset by a decrease in production of 5,507 Mcf/day from our Gulf Coast area primarily due to the Pine Prairie Disposition and reduced development drilling activity during the 2014 period. Average natural gas sales prices, without realized derivatives, increased by $1.10 per Mcf, or 33% to $4.48 per Mcf during the six months ended June 30, 2014, as compared to $3.38 per Mcf for the six months ended June 30, 2013.

Gains/losses on commodity derivative contracts - net

Our mark-to-market (“MTM”) derivative positions moved from an unrealized gain of $8.4 million for the six months ended June 30, 2013 to an unrealized loss of $22.2 million for the six months ended June 30, 2014. The NYMEX WTI closing price on June 30, 2014 was $105.37 per barrel compared to a closing price of $96.56 per barrel on June 28, 2013 (the last day of trading for the period).

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The realized loss on derivatives for the six months ended June 30, 2014 was $31.9 million compared to a realized loss of $6.1 million for the six months ended June 30, 2013. The following table presents realized gain (loss) by type of commodity contract for the six months ended June 30, 2014:

	For the Six Months Ended June 30, 2014
	Realized Gain (Loss)			Average Sales Price
	(in thousands)
Oil commodity contracts	$	(26,482	)	$	88.13
Natural gas liquids commodity contracts	61			42.88
Natural gas commodity contracts	(5,527		)	3.99
Realized losses on commodity derivative contracts, net	$	(31,948	)

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,
	2014		2013		2014		2013		2014		2013		2014		2013
	(in thousands)				(per Boe)				(in thousands)				(per Boe)
EXPENSES:
Lease operating and workover	$	19,721	$	17,575	$	6.79	$	9.83	$	39,848	$	31,446	$	7.23	$	9.69
Gathering and transportation	2,940		—		1.01		—		5,795		—		1.05		—
Severance and other taxes	5,632		6,579		1.94		3.68		13,279		12,534		2.41		3.86
Asset retirement accretion	432		313		0.15		0.18		929		567		0.17		0.17
Depreciation, depletion, and amortization	71,074		52,830		24.47		29.56		137,975		94,806		25.02		29.21
Impairment of oil and gas properties	—		—		—		—		86,471		—		15.68		—
General and administrative	13,434		15,272		4.63		8.55		25,118		26,298		4.56		8.10
Acquisition and transaction costs	2,483		11,492		0.86		6.43		2,611		11,492		0.47		3.54
Other	609		—		0.21		—		939		—		0.17		—
Total expenses	$	116,325	$	104,061	$	40.06	$	58.23	$	312,965	$	177,143	$	56.76	$	54.57

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

Lease operating and workover expenses

Lease operating and workover expenses increased $2.1 million, or 12%, to $19.7 million for the three months ended June 30, 2014 compared to $17.6 million for the three months ended June 30, 2013. Lease operating expenses increased $3.0 million, or 20%, to $18.2 million for the three months ended June 30, 2014 as compared to $15.2 million for the related period in 2013. The increase in total expenses was primarily due to a full quarter of expense related to our Anadarko Basin Assets (the 2013 comparable period included only one month of expense due to the timing of the Anadarko Basin Acquisition) and costs associated with the increase in producing well count period over period, partially offset by the lease operating expenses eliminated in the Pine Prairie Disposition. Workover expenses decreased $0.9 million, or 38%, to $1.5 million for the three months ended June 30, 2014 compared to $2.4 million for the three months ended June 30, 2013. Lease operating and workover expenses decreased to $6.79 per Boe for the three months ended June 30, 2014, a decrease of $3.04, or 31%, over the $9.83 per Boe for the three months ended June 30, 2013. This decrease was largely attributable to increased production during the 2014 period, the realization of expense benefits of investments to reduce salt water disposal costs in the Mississippian Lime area, the migration from diesel fired electric generators to sourcing electricity from the local power grid in the Mississippian Lime area, most of which were implemented after the second quarter of 2013 and the closing of the Pine Prairie Disposition on May 1, 2014 where production had relatively higher per Boe rates.

Gathering and transportation

Gathering and transportation expenses were $2.9 million for the three months ended June 30, 2014. These expenses are primarily attributable to an amended gas transportation, gathering and processing contract, which commenced during the third quarter of 2013 in the Mississippian Lime and included a $0.36 per Mmbtu gathering fee based upon wellhead volumes. As such, there is no comparable amount for the three months ended June 30, 2013.

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Severance and other taxes

	Three Months Ended June 30,
	2014			2013

Total oil, natural gas, and natural gas liquids sales	$	179,287		$	103,098

Severance taxes	4,353			5,362
Ad valorem and other taxes	1,279			1,217
Severance and other taxes	$	5,632		$	6,579

Severance taxes as a percentage of sales	2.4		%	5.2		%
Severance and other taxes as a percentage of sales	3.1		%	6.4		%

Severance and other taxes decreased $1.0 million, or 15%, to $5.6 million for the three months ended June 30, 2014 compared to $6.6 million for the three months ended June 30, 2013. Severance taxes decreased $1.1 million, or 20%, to $4.3 million for the three months ended June 30, 2014, as compared to $5.4 million for the three months ended June 30, 2013. Severance taxes as a percentage of sales changed from 5.2% for the three months ended June 30, 2013 to 2.4% for the corresponding 2014 period due to lower effective severance tax rates in our Mississippian Lime and Anadarko areas and lower production period-over-period in the relatively higher tax Gulf Coast region, resulting from reduced drilling activity in 2014 and the Pine Prairie Disposition. Ad valorem taxes increased $0.1 million, or 8%, to $1.3 million for the three months ended June 30, 2014, as compared to $1.2 million for the three months ended June 30, 2013, corresponding to a related increase in producing wells and increased development drilling, partially offset by reduced ad valorem taxes in the Gulf Coast area attributable to the Pine Prairie Disposition.

Depreciation, depletion and amortization (DD&A)

DD&A expense increased $18.3 million, or 35%, to $71.1 million for the three months ended June 30, 2014 compared to $52.8 million for the three months ended June 30, 2013. The DD&A rate for the 2014 period was $24.47 per Boe, compared to $29.56 per Boe for the 2013 period. Overall DD&A expense increased due to higher production, partially offset by the lower DD&A rate noted above.

General and administrative (G&A)

Our G&A expenses decreased by $1.9 million, or 12%, to $13.4 million for the three months ended June 30, 2014, compared to $15.3 million for the three months ended June 30, 2013. The decrease is primarily attributable to COPAS recoveries, which increased as a result of the Anadarko Basin Acquisition.

Acquisition and transaction costs

Our acquisition and transaction costs were $2.5 million for the three months ended June 30, 2014, compared to $11.5 million for the three months ended June 30, 2013. For the 2014 period, these costs represent our expenses related to the Pine Prairie Disposition discussed above. For the 2013 period, these costs represent our expenses related to the Anadarko Basin Acquisition, which closed in May 2013.

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.

Six Months Ended June 30, 2014 as Compared to the Six Months Ended June 30, 2013

Lease operating and workover expenses

Lease operating and workover expenses increased $8.4 million, or 27%, to $39.8 million for the six months ended June 30, 2014 compared to $31.4 million for the six months ended June 30, 2013. Lease operating expenses increased $11.2 million, or 43%, to $37.5 million for the six months ended June 30, 2014 as compared to $26.3 million for the related period in 2013. The increase in total expenses was primarily due to six months of expense related to our Anadarko Basin Assets (the 2013 comparable period included only one month of expense due to the timing of the Anadarko Basin Acquisition) and costs associated with the increase in producing well count period over period, partially offset by the lease operating expenses eliminated in the Pine Prairie Disposition. Workover expenses decreased $2.8 million, or 55%, to $2.3 million for the six months ended June 30, 2014 compared to $5.1 million for the six months ended June 30, 2013. Lease operating and workover expenses decreased to $7.23 per Boe for the six months ended June 30, 2014, a decrease of $2.46, or 25%, from the $9.69 per Boe for the six months ended June 30, 2013. This decrease was primarily attributable to increased production during the 2014 period, the realization of expense benefits of our investments to reduce salt water disposal costs in the Mississippian Lime area, the migration from diesel fired electric generators to sourcing electricity from the local power grid in the Mississippian Lime area, most of which were implemented after the second quarter of 2013 and the closing of the Pine Prairie Disposition on May 1, 2014, where production had relatively higher per Boe rates.

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Gathering and transportation

Gathering and transportation expenses were $5.8 million for the six months ended June 30, 2014. These expenses are primarily attributable to an amended gas transportation, gathering and processing contract, which commenced during the third quarter of 2013 in the Mississippian Lime that included a $0.36 per Mmbtu gathering fee based upon wellhead volumes. As such, there is no comparable amount for the six months ended June 30, 2013.

Severance and other taxes

	Six Months Ended June 30,
	2014		2013

Total oil, natural gas, and natural gas liquids sales	$	346,413	$	193,830

Severance taxes	10,162		10,215
Ad valorem and other taxes	3,117		2,319
Severance and other taxes	$	13,279	$	12,534

Severance taxes as a percentage of sales	2.9%		5.3%
Severance and other taxes as a percentage of sales	3.8%		6.5%

Severance and other taxes increased $0.8 million, or 6%, to $13.3 million for the six months ended June 30, 2014, compared to $12.5 million for the six months ended June 30, 2013. Severance taxes were flat at $10.2 million for the six months ended June 30, 2014, as compared to $10.2 million for the six months ended June 30, 2013. Severance taxes as a percentage of sales changed from 5.3% for the six months ended June 30, 2013 to 2.9% for the corresponding 2014 period due to lower effective severance tax rates in our Mississippian Lime and Anadarko areas and lower production period-over-period in the relatively higher tax Gulf Coast region, attributable to lower drilling activity in 2014 and the Pine Prairie Disposition. Ad valorem taxes increased $0.8 million, or 35%, to $3.1 million for the six months ended June 30, 2014, as compared to $2.3 million for the six months ended June 30, 2013, corresponding to a related increase in producing wells due to the Anadarko Basin Acquisition and increased development drilling, partially offset by reduced ad valorem taxes in the Gulf Coast area attributable to the Pine Prairie Disposition.

Depreciation, depletion and amortization (DD&A)

DD&A expense increased $43.2 million, or 46%, to $138.0 million for the six months ended June 30, 2014 compared to $94.8 million for the six months ended June 30, 2013. The DD&A rate for the 2014 period was $25.02 per Boe, compared to $29.21 per Boe for the 2013 period. Overall DD&A expense increased due to higher production, partially offset by the lower DD&A rate noted above.

Impairment of oil and gas properties

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

General and administrative (G&A)

Our G&A expenses decreased by $1.2 million, or 5%, to $25.1 million for the six months ended June 30, 2014, compared to $26.3 million for the six months ended June 30, 2013. The decrease is primarily attributable to COPAS recoveries, which increased as a result of the Anadarko Basin Acquisition, partially offset by an increase in employee related expenses (including salary, share-based compensation expense and bonus) resulting from an increase in headcount from 158 employees at June 30, 2013 to 199 employees at June 30, 2014.

Acquisition and transaction costs

Our acquisition and transaction costs were $2.6 million for the six months ended June 30, 2014, compared to $11.5 million for the six months ended June 30, 2013. For the 2014 period, these costs represent our expenses related to the Pine Prairie Disposition discussed above. For the 2013 period, these costs represent our expenses related to the Anadarko Basin Acquisition discussed above.

Other

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

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Other Income (Expenses)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2014			2013			2014			2013
	(in thousands)						(in thousands)
OTHER INCOME (EXPENSE)
Interest income	$	9		$	5		$	19		$	10

Interest expense	(37,157		)	(24,482		)	(75,722		)	(42,403		)
Capitalized Interest	3,344			7,861			7,962			14,915
Interest expense — net of amounts capitalized	(33,813		)	(16,621		)	(67,760		)	(27,488		)

Total other income (expense)	$	(33,804	)	$	(16,616	)	$	(67,741	)	$	(27,478	)

Interest expense

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

Interest expense for the three months ended June 30, 2014 and 2013 was $37.1 million and $24.5 million, respectively. The increase in interest expense was primarily due to the issuance of the 2021 Senior Notes in May 2013 in connection with the Anadarko Basin Acquisition. Our average outstanding balance under our revolver was $370.1 million during the three months ended June 30, 2014, compared to $221.0 million for the three months ended June 30, 2013, and related to $2.8 million of the total interest expense of $37.1 million for 2014. Of the remainder, $16.4 million was interest incurred under the 2021 Senior Notes, $16.1 million was interest incurred under the 2020 Senior Notes and $1.8 million represented amortization of deferred financing costs. Of the total interest expense for both periods, $3.3 million and $7.9 million was capitalized to oil and gas properties, resulting in $33.8 million and $16.6 million in interest expense, net of capitalized interest, for the three months ended June 30, 2014 and 2013, respectively.

Six Months Ended June 30, 2014 as Compared to the Six Months Ended June 30, 2013

Interest expense for the six months ended June 30, 2014 and 2013 was $75.7 million and $42.4 million, respectively. The increase in interest expense was primarily due to the issuance of the 2021 Senior Notes in May 2013 in connection with the Anadarko Basin Acquisition. Our average outstanding balance under our revolver was $385.5 million during the six months ended June 30, 2014, compared to $179.6 million for the six months ended June 30, 2013, and related to $6.7 million of the total interest expense of $75.7 million for 2014. Of the remainder, $32.6 million was interest incurred under the 2021 Senior Notes, $32.2 million was interest incurred under the 2020 Senior Notes and $4.2 million represented amortization of deferred financing costs. Of the total interest expense for both periods, $8.0 million and $14.9 million was capitalized to oil and gas properties, resulting in $67.7 million and $27.5 million in interest expense, net of capitalized interest, for the six months ended June 30, 2014 and 2013, respectively.

Provision for Income Taxes

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

Our income tax benefit was $0.1 million for the three months ended June 30, 2014 and a provision of $2.0 million for the three months ended June 30, 2013. For the three months ended June 30, 2014, the Company’s effective tax rate was a benefit of approximately 1.9%. The Company’s effective tax rate for the second quarter of 2014 differs from the federal statutory rate of 35% due to state income taxes and the recording of $0.4 million of additional valuation allowance in light of the impairment of oil and gas properties during the first quarter. 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.

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

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Six Months Ended June 30, 2014 as Compared to the Six Months Ended June 30, 2013

Our income tax benefit was $2.3 million for the six months ended June 30, 2014 and a benefit of $3.0 million for the six months ended June 30, 2013. For the six months ended June 30, 2014, the Company’s effective tax rate was a benefit of approximately 2.6%. The Company’s effective tax rate for the six months ended June 30, 2014 differs from the federal statutory rate of 35% due to the effect of state income taxes and changes in the valuation. This year, the Company recorded $30.1 million in additional valuation allowance in light of the impairment of oil and gas properties bringing the total valuation allowance to $75.8 million at June 30, 2014.

Liquidity and Capital Resources

At June 30, 2014, our liquidity was $150 million, consisting of $120 million of available borrowing capacity under our revolving credit facility and $30 million of cash and cash equivalents.

Expenditures for exploration and development of oil and natural gas properties are the primary use of our capital resources. We expect to invest between $500 million and $550 million of capital for exploration, development and lease and seismic acquisition during the year ended December 31, 2014. Additionally, we expect to capitalize between $16.0 million and $22.0 million of interest expense during that same period. Our future success in growing proved reserves and production will be highly dependent on our ability to access additional outside sources of capital, via either the debt or equity markets, through growth in our reserve based credit facility or by securing other external sources of funding. As part of that process, on March 5, 2014, we executed a PSA to sell all of our ownership interest in developed and undeveloped acreage in the Pine Prairie field area of Evangeline Parish, Louisiana to a private buyer for a purchase price of $170 million in cash, subject to standard post-closing adjustments. On May 1, 2014, we closed on the sale for estimated net proceeds of $147.5 million, of which $131 million was used to reduce amounts outstanding under our revolving credit facility, with the remainder retained for transaction expenses and working capital purposes.

We believe that the proceeds from the Pine Prairie Disposition discussed above, together with expected cash flow from operations and borrowings available under our amended Credit Facility, will be sufficient to fund our current capital spending plans through 2015. We plan to continue pursuing additional strategic options that would improve our financial flexibility and provide additional long-term liquidity, including the sale of our remaining Gulf Coast producing assets, other non-core asset sales and possibly joint-ventures or farm-outs on our properties. Discussions are in various states of progress with a variety of interested third parties regarding assets sales or potential joint-ventures, but we are currently unable to predict the timing of any transaction and no assurance can be given that we will reach any agreement with a potential counterparty.

Though we have no current plans to do so, we may from time to time seek to retire, purchase or exchange our outstanding debt in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Significant Sources of Capital

Reserve-based Credit Facility

As of June 30, 2014, our credit facility consisted of a $750 million senior revolving credit facility (the “Credit Facility”) with a borrowing base supported by our Mississippian Lime and Anadarko Basin oil and gas assets of $475 million, as recently reaffirmed in the Fifth Amendment thereto on March 28, 2014. At June 30, 2014 and 2013, the weighted average interest rate was 2.8% and 2.5%, respectively. At June 30, 2014, outstanding letters of credit obligations total $0.2 million.

The Fifth Amendment amended the Credit Facility to (i) permit Midstates Sub to enter into the $125 million Senior Secured Bridge Facility (“Bridge Facility”) secured by our Gulf Coast Assets and intended to provide us with additional sources of liquidity in the event the sale of our Pine Prairie assets was delayed for any reason, (ii) affirm the current borrowing base thereunder of $500 million, and (iii) provide for a decrease of the borrowing base to $475 million upon, among other things, the closing of the Pine Prairie Disposition or the entry into the Bridge Facility. Additionally, the Fifth Amendment amended certain provisions of the Credit Facility to, among other things, (i) subject to certain events, including the closing of the Pine Prairie Disposition, release Midstates Sub’s Louisiana assets from liens securing the Credit Facility, (ii) increase the applicable margin for LIBOR Loans from a range of 1.75% to 2.75% depending on borrowing base utilization to a range of 2.00% to 3.00%, with corresponding changes to the applicable margin for base rate loans, (iii) amend the leverage ratio to be (A) 4.75:1.00 for the quarter ending March 31, 2014, (B) 4.50:1.00 for the quarter ending June 30, 2014, (C) 4.25:1.00 for the quarters ending September 30, 2014 and December 31, 2014 and (D) 4.00:1.00 for each quarter thereafter; provided that the leverage ratio shall be increased by 0.50 for the quarter of, and the two quarters following, the consummation of the Pine Prairie Disposition and (iv) allow for the Bridge Facility to be secured by a second lien on Midstates Sub’s Mississippian Lime and Anadarko Basin assets. As consideration for the participating lenders’ consent to the Fifth Amendment, Midstates Sub paid a 0.10% amendment fee on the $475 million borrowing base.

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On May 1, 2014, we completed the Pine Prairie Disposition and terminated the Bridge Facility commitment. With the completion of the Pine Prairie Disposition and pursuant to the Fifth Amendment, the borrowing base under the Company’s Credit Facility was reduced to $475 million and the leverage ratio thereunder was amended to be (i) 5:00:1.00 for the quarter ending June 30, 2014, and (ii) 4.75:1.00 for the quarters ending September 30, 2014 and December 31, 2014. The leverage ratio decreases to 4.00:1.00 for each quarter thereafter.

The Credit Facility matures on May 31, 2018 and borrowings thereunder are secured by substantially all of our oil and natural gas properties and bear interest at LIBOR plus an applicable margin, depending upon our borrowing base utilization, between 2.00% and 3.00% per annum.

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

Under the terms of the Credit Facility, we are required to repay the amount by which the principal balance of its outstanding loans and its letter of credit obligations exceeds its redetermined borrowing base. 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.

As of June 30, 2014, we were in compliance with the minimum current ratio and the ratio of debt to EBITDA covenants as set forth in the Credit Facility. Our current ratio at June 30, 2014 was 1.31 to 1.0. At June 30, 2014, our ratio of debt to EBITDA was 3.96 to 1.0.

2020 Senior Notes

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

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

2021 Senior Notes

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

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

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

On or prior to May 31, 2014, we may redeem up to $100.0 million of aggregate principal amount of the 2021 Senior Notes with the net cash proceeds from any Equity Offerings (as such term is defined in the 2021 Senior Notes Indenture) at a redemption price equal to 103% of the principal amount plus accrued and unpaid interest.

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

Cash Flows from Operating, Investing and Financing Activities

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

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

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,
	2014			2013
Net cash provided by operating activities	$	177,047		$	72,840
Net cash used in investing activities	(131,514		)	(881,332		)
Net cash provided by (used in) financing activities	(49,036		)	801,899

Net change in cash	$	(3,503	)	$	(6,593	)

Cash flows provided by operating activities

Net cash provided by operating activities was $177.0 million and $72.8 million for the six months ended June 30, 2014 and 2013, respectively. The increase in net cash provided by operating activities was primarily the result of an increase in oil and natural gas revenues attributable to higher production and favorable working capital changes, partially offset by lower realized commodity prices.

Cash flows used in investing activities

Net cash used in investing activities was $131.5 million and $881.3 million during the six months ended June 30, 2014 and 2013, respectively. During the six months ended June 30, 2014, $279.0 million was spent on our drilling program, offset by $147.5 million in proceeds received for the Pine Prairie Disposition. During the six months ended June 30, 2013, $259.6 million was spent on our drilling program, in addition to $621.7 million for the Anadarko Basin Acquisition.

Cash flows (used in) provided by financing activities

Net cash used in financing activities was $49.0 million for the six months ended June 30, 2014, compared to $801.9 million provided by financing activities for the six months ended June 30, 2013. During the six months ended June 30, 2014, we had draws on the revolver of $84.0 million and repayments of $131.0 million. During six months ended June 30, 2013, cash was sourced through the issuance of the 2021 Senior Notes of $700.0 million and draws of our revolving credit facility of $161.5 million.

Critical Accounting Policies and Estimates

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

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

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Other Items

Contractual Obligations

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

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

Revolving credit facility (2)	$	354,150	$	—	$	354,150	$	—	$	—
2020 Senior Notes (3)	1,003,125		64,500		193,500		129,000		616,125
2021 Senior Notes (3)	1,153,250		64,750		194,250		129,500		764,750
Drilling contracts (4)	10,110		10,110		—		—		—
Non-cancellable office lease commitments (4)	10,239		1,847		5,735		1,932		725
Seismic contracts (4)	3,192		3,192		—		—		—
Asset retirement obligations (5)	20,382		—		—		—		20,382
Net minimum commitments	$	2,554,448	$	144,399	$	747,635	$	260,432	$	1,401,982

(1) Less than one year includes commitments from July 2014 through June 2015; 1-3 years includes commitments from July 2015 through June 2018; 3-5 years includes commitments from July 2018 through June 2020; and 5+ years includes commitments from July 2020 and beyond.

(2) Amount excludes interest on our revolving credit facility as both the amount borrowed and applicable interest rates are variable. As of June 30, 2014, we had $354.2 million of indebtedness outstanding under our revolving credit facility. See Note 9 to our unaudited condensed consolidated financial statements.

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

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

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

Off-Balance Sheet Arrangements

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

Recent Accounting Pronouncements

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

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

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

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

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

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

	Hedged	Weighted-Average
	Volume	Fixed Price
Oil (Bbls):
WTI Swaps — 2014	2,194,000	$				89.04
WTI Swaps — 2015	2,000,000	$				87.60

WTI Collars — 2014	81,600	$	87.83	-	$	97.86

WTI to LLS Basis Differential Swaps — 2014 (1)	229,500	$				5.35

NGL (Bbls):
NGL Swaps — 2014	34,500	$				61.43

Natural Gas (MMBtu):
Swaps — 2014 (2)	9,016,000	$				4.17
Swaps — 2015	18,250,000	$				4.13

Collars — 2014 (3)	691,002	$	3.88	-	$	4.99

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

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

(3) Includes 101,000 MMBtus in natural gas collars that priced during the period, but had not cash settled as of June 30, 2014.

	For the Six Months Ended June 30, 2014
	(in thousands)
Derivative fair value at period end - liability (included in balance sheet)	$	(53,004	)
Realized net loss (included in the statement of operations)	$	(17,138	)
Unrealized net loss (included in the statement of operations)	$	(14,329	)

At June 30, 2014 and December 31, 2013, all of our commodity derivative contracts were with seven bank counterparties. Our policy is to net derivative liabilities and assets where there is a legally enforceable master netting agreement with the counterparty.

In July 2014, the Company entered into additional commodity derivative transactions. On August 8, 2014 the Company had the following open commodity positions:

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	Hedged	Weighted-Average
	Volume	Fixed Price
Oil (Bbls):
WTI Swaps — 2014	2,194,000	$				89.04
WTI Swaps — 2015	2,180,000	$				88.38

WTI Collars — 2014	81,600	$	87.83	-	$	97.86

WTI to LLS Basis Differential Swaps — 2014	229,500	$				5.35

NGL (Bbls):
NGL Swaps — 2014	34,500	$				61.43

Natural Gas (MMBtu):
Swaps — 2014	9,016,000	$				4.17
Swaps — 2015	18,250,000	$				4.13

Collars — 2014	691,002	$	3.88	-	$	4.99

Interest Rate Risk. At June 30, 2014, we had indebtedness outstanding under our credit facility of $354.2 million, which bore interest at floating rates, we had $600 million outstanding in 2020 Senior Notes (placed October 1, 2012), which bore interest at 10.75%, and we had $700 million outstanding in 2021 Senior Notes (placed May 31, 2013), which bore interest at 9.25%. The average annual interest rate incurred on the credit facility for the three months ended June 30, 2014 and 2013 was 2.8% and 2.5%, respectively. The average annual interest rate incurred on the credit facility for the six months ended June 30, 2014 and 2013 was 2.8% and 2.5%, respectively.

A 1.0% increase in each of the average LIBOR and federal funds rate for the three months ended June 30, 2014 and 2013 would have resulted in an estimated $1.0 million and $0.6 million, respectively, increase in interest expense, of which a portion may be capitalized. A 1.0% increase in each of the average LIBOR and federal funds rate for the six months ended June 30, 2014 and 2013 would have resulted in an estimated $1.9 million and $0.9 million, respectively, increase in interest expense, of which a portion may be capitalized.

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

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

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

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting except that we are in the process of implementing management’s plan for remediation of our material weakness over the preparation of oil and gas reserve estimates, as outlined in Item 9A of our Annual Report on Form 10-K. However, our remediation efforts are not yet complete and therefore, management has concluded that a material weakness continues to exist in our internal controls over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

Our business faces many risks. Any of the risks discussed in this Form 10-Q and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.

Risk factors relating to us are contained in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2013. No material change to such risk factors has occurred during the three months ended June 30, 2014.

Item 6. Exhibits

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

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SIGNATURES

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

	MIDSTATES PETROLEUM COMPANY, INC.

Dated: August 7, 2014	/s/ Dr. Peter J. Hill
	Dr. Peter J. Hill
	Interim President and Chief Executive Officer
	(Principal Executive Officer)

Dated: August 7, 2014	/s/ Nelson M. Haight
	Nelson M. Haight
	Senior Vice President and Chief Financial Officer
	(Principal Financial and Accounting Officer)

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EXHIBIT INDEX

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

10.1	***	Form of Cash Retention Award (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 9, 2014 and incorporated herein by reference).
10.2		Fifth Amendment to Second Amended and Restated Credit Agreement, dated as of June 8, 2012, by and among Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC, SunTrust Bank as administrative agent and the other lender parties thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 3, 2014 and incorporated herein by reference).
31.1	*	Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
31.2	*	Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
32.1	**	Sarbanes-Oxley Section 906 certification of Principal Executive Officer and Principal Financial Officer
101.INS		XBRL Instance Document.
101.SCH		XBRL Schema Document.
101.CAL		XBRL Calculation Linkbase Document.
101.DEF		XBRL Definition Linkbase Document.
101.LAB		XBRL Labels Linkbase Document
101.PRE		XBRL Presentation Linkbase Document.

*		Filed herewith
**		Furnished herewith
***		Management contract or compensatory plan or arrangement

Amplify Energy Corp. - FORM 10-Q - August 7, 2014

Attached files

Amplify Energy Corp. Reports