Edgar Filing: Midstates Petroleum Company, Inc.

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 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, 2012

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 1900
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 o

Non-accelerated filer x		Smaller reporting company o

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 8, 2012 is shown below:

Class		Number of shares outstanding
Common stock, $0.01 par value		66,549,563

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MIDSTATES PETROLEUM COMPANY, INC.

QUARTERLY REPORT ON

FORM 10-Q

FOR THE SIX MONTHS ENDED JUNE 30, 2012

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	Page


Glossary of Oil and Natural Gas Terms	i

PART I - FINANCIAL INFORMATION

Item 1.- Financial Statements
Condensed Consolidated Balance Sheets at June 30, 2012 and December 31, 2011 (unaudited)	1
Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2012 and 2011 (unaudited)	2
Condensed Consolidated Statements of Changes in Stockholders’/Members’ Equity for the Six Months Ended June 30, 2012 (unaudited)	3
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2012 and 2011 (unaudited)	4
Notes to Unaudited Condensed Consolidated Financial Statements	5

Item 2. - Management’s Discussion and Analysis of Financial Condition and Results of Operations	18

Item 3. - Quantitative and Qualitative Disclosures About Market Risk	30

Item 4. - Controls and Procedures	32

PART II - OTHER INFORMATION

Item 1. - Legal Proceedings	33

Item 1A. - Risk Factors	33

Item 2. - Unregistered Sales of Equity Securities and Use of Proceeds	34

Item 3. - Defaults upon Senior Securities	34

Item 4. - Mine Safety Disclosures	34

Item 5. - Other Information	34

Item 6. - Exhibits	34

SIGNATURES	35

EXHIBIT INDEX	36

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GLOSSARY OF OIL AND NATURAL GAS TERMS

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

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

Boe/d: 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.

MMBoe: One million barrels of oil equivalent.

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, LKH, 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, HKO, 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 shall be 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 either 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, 2012			December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	11,689		$	7,344
Accounts receivable:
Oil and gas sales	18,777			23,792
Severance tax refund	275			3,413
Other	515			249
Prepayments	5,350			2,642
Inventory	6,496			5,713
Commodity derivative contracts	12,038			4,957
Total current assets	55,140			48,110

PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of full-cost accounting:
Proved properties	833,172			644,393
Unevaluated properties	95,600			76,857
Other property and equipment	2,168			1,672
Less accumulated depreciation, depletion, and amortization	(204,752		)	(148,843		)
Net property and equipment	726,188			574,079

OTHER ASSETS:
Commodity derivative contracts	6,247			588
Security deposit and other noncurrent assets	3,660			1,879
Total other assets	9,907			2,467

TOTAL	$	791,235		$	624,656

LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	27,122		$	35,731
Accrued liabilities	62,985			37,524
Commodity derivative contracts	360			12,599
Total current liabilities	90,467			85,854

LONG-TERM LIABILITIES:
Asset retirement obligations	9,398			7,627
Commodity derivative contracts	—			10,178
Long-term debt	151,700			234,800
Deferred income taxes	168,917			—
Other long-term liabilities	614			695
Total long-term liabilities	330,629			253,300

COMMITMENTS AND CONTINGENCIES (Note 12)

STOCKHOLDERS’/MEMBERS’ EQUITY
Capital contributions	—			322,496
Preferred stock, $0.01 par value, 50,000,000 shares authorized, no shares issued or outstanding, respectively	—			—
Common stock, $0.01 par value, 300,000,000 shares authorized, 66,549,563 shares issued and outstanding, respectively	665			—
Additional paid-in-capital	536,352			—
Retained deficit/accumulated loss	(166,878		)	(36,994		)
Total stockholders’/members’ equity	370,139			285,502

TOTAL	$	791,235		$	624,656

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,
	2012			2011			2012			2011

REVENUES:
Oil sales	$	48,056		$	45,994		$	93,138		$	81,577
Natural gas sales	2,379			4,962			5,829			9,035
Natural gas liquid sales	3,901			3,171			10,173			5,216
Gains (Losses) on commodity derivative contracts — net	48,143			10,477			23,478			(18,119		)
Other	103			60			207			114

Total revenues	102,582			64,664			132,825			77,823

EXPENSES:
Lease operating and workover	5,921			3,669			12,388			6,275
Severance and other taxes	6,272			5,370			11,648			9,495
Asset retirement accretion	164			39			298			86
General and administrative	4,956			10,641			11,019			14,544
Depreciation, depletion, and amortization	27,882			21,266			55,909			39,884

Total expenses	45,195			40,985			91,262			70,284

OPERATING INCOME	57,387			23,679			41,563			7,539

OTHER INCOME (EXPENSE)
Interest income	143			4			150			12
Interest expense — net of amounts capitalized	(990		)	(134		)	(2,680		)	(134		)

Total other income (expense)	(847		)	(130		)	(2,530		)	(122		)

INCOME BEFORE TAXES	56,540			23,549			39,033			7,417

Income tax expense	168,917			—			168,917			—

NET INCOME (LOSS)	$	(112,377	)	$	23,549		$	(129,884	)	$	7,417

Pro forma loss per share:
Basic and Diluted (Note 10)	$	(1.85	)	N/A			$	(2.39	)	N/A

Pro forma weighted average shares outstanding:
Basic and Diluted (Note 10)	60,887			N/A			54,261			N/A

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

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MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED STATEMENT OF CHANGES IN STOCKHOLDERS’/MEMBERS’ EQUITY

(Unaudited)

(In thousands)

	Common Stock			Capital			Additional Paid-		Retained Deficit/ Accumulated			Total Stockholders’/
	Number of Shares	Amount		Contributions			in-Capital		Loss			Members’ Equity
Balance as of December 31, 2011	—	$	—	$	322,496		$	—	$	(36,994	)	$	285,502
Issuance of common stock	47,634,353	476		(476		)	—		—			—
Reclassification of members’ contributions	—	—		(322,020		)	322,020		—			—
Proceeds from the sale of common stock	18,000,000	180		—			213,659		—			213,839
Stock-based compensation	915,210	9		—			673		—			682
Net loss	—	—		—			—		(129,884		)	(129,884		)
Balance as of June 30, 2012	66,549,563	$	665	$	—		$	536,352	$	(166,878	)	$	370,139

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,
	2012			2011

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(129,884	)	$	7,417
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Unrealized (gains) losses on commodity derivative contracts, net	(35,157		)	9,982
Asset retirement accretion	298			86
Depreciation, depletion, and amortization	55,909			39,884
Share-based compensation	682			7,949
Deferred income taxes	168,917			—
Amortization of deferred financing costs	376			383
Change in operating assets and liabilities:
Accounts receivable — oil and gas sales	5,015			(1,181		)
Accounts receivable — other	2,872			305
Prepayments and other assets	(2,708		)	117
Inventory	(783		)	(104		)
Accounts payable	(3,077		)	(6,920		)
Accrued liabilities	(2,371		)	9,069
Other	(126		)	(3		)

Net cash provided by operating activities	$	59,963		$	66,984

CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment	(184,245		)	(102,302		)

Net cash used in investing activities	$	(184,245	)	$	(102,302	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings	20,067			57,000
Repayment of long-term borrowings	(103,167		)	—
Proceeds from issuance of mandatorily redeemable convertible preferred units	65,000			—
Repayment of mandatorily redeemable convertible preferred units	(65,000		)	—
Proceeds from sale of common stock, net of initial public offering expenses of $6.1 million	213,839			—
Deferred loan costs	(2,112		)	(500		)
Cash received for units	—			170
Distributions to members	—			(22,811		)
Other	—			(3		)

Net cash provided by financing activities	$	128,627		$	33,856

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	4,345			(1,462		)

Cash and cash equivalents, beginning of period	7,344			11,917

Cash and cash equivalents, end of period	$	11,689		$	10,455

SUPPLEMENTAL INFORMATION:
Non-cash transactions — investments in property and equipment accrued — not paid	$	79,400		$	28,800

Cash paid for interest, net of capitalized interest of $2.4 million and $1.3 million, respectively	$	2,763		$	158

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 and natural gas liquids, and currently has oil and gas operations solely in the state of Louisiana. 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, which was previously a wholly-owned subsidiary of Midstates Petroleum 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, all of the interests in Midstates Petroleum Holdings LLC were exchanged for newly issued common shares 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 April 25, 2012, the Company completed its initial public offering of common stock pursuant to a registration statement on Form S-1 (File 333-177966), as amended and declared effective by the SEC on April 19, 2012. Pursuant to the registration statement, the Company registered the offer and sale of 27,600,000 shares of $0.01 par value common stock, which included 6,000,000 shares of stock sold by the selling shareholders and 3,600,000 shares of common stock sold by the selling stockholders pursuant to an option granted to the underwriters to cover over-allotments. The Company’s sale of the shares in its initial public offering closed on April 25, 2012 and its initial public offering terminated upon completion of the closing.

The proceeds of the Company’s initial public offering, based on the public offering price of $13.00 per share, were approximately $358.8 million. After subtracting underwriting discounts and commissions of $21.5 million and the net proceeds to the selling stockholders of $117.3 million, the Company received net proceeds of approximately $220.0 million from the registration and sale of 18,000,000 common shares (or $213.8 million net of offering expenses paid directly by the Company). The Company used $67.1 million of the net proceeds to redeem convertible preferred units in Holdings LLC, including interest and other charges, and $99.0 million to pay down a portion of the borrowings under its revolving credit facility. The Company used the remaining $47.7 million to fund the execution of its growth strategy through its drilling program. The Company did not receive any of the proceeds from the sale of the 9,600,000 shares by the selling stockholders. Immediately after the initial public offering and exercise of the option, First Reserve Midstates Interholding LP and its affiliates own approximately 41.4% of the Company’s outstanding common stock.

At June 30, 2012, the Company operated oil and natural gas properties as one reportable segment: the exploration, development and production of oil, natural gas and natural gas liquids. The Company’s management evaluated performance based on one reportable segment as there were not different economic environments within the operation of its oil and natural gas properties.

All pro forma and per share information presented in the accompanying unaudited financial statements have been adjusted to reflect the effects of the Company’s initial public offering.

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 included in MPCI’s Registration Statement on Form S-1, as amended (Registration No. 333-177966).

All intercompany transactions have been eliminated in consolidation. Certain reclassifications have been made to the prior year’s consolidated financial statements and related footnotes to conform them to the current year presentation. 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

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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, 2012, and determined that none would have a material impact on the Company’s condensed consolidated financial statements.

3. Fair Value Measurements of Financial Instruments

The Company uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further divided into the following fair value input hierarchy:

· Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date.

· Level 2 — Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are commodity derivative contracts with fair values based on inputs from actively quoted markets. The Company uses a market approach to estimate the fair values of its commodity derivative contracts, utilizing commodity futures price strips for the underlying commodities provided by a reputable third-party.

· Level 3 — Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability.

Assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

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, 2012 and December 31, 2011, all of the Company’s commodity derivative contracts were with three and two bank counterparties, respectively, and are classified as Level 2.

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	Fair Value Measurements at June 30, 2012
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in thousands)
Assets:
Commodity derivative oil swaps	$	—	$	14,799	$	—	$	14,799
Commodity derivative deferred premium puts	—		1,015		—		1,015
Commodity derivative collars	—		380		—		380
Commodity derivative differential swaps	—		7,371		—		7,371
Total assets	—		23,565		—		23,565

Liabilities:
Commodity derivative oil swaps	$	—	$	4,397	$	—	$	4,397
Commodity derivative deferred premium puts	—		180		—		180
Commodity derivative collars	—		10		—		10
Commodity derivative differential swaps	—		1,053		—		1,053
Total liabilities	$	—	$	5,640	$	—	$	5,640

	Fair Value Measurements at December 31, 2011
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in thousands)
Assets:
Commodity derivative oil swaps	$	—	$	—	$	—	$	—
Commodity derivative deferred premium puts	—		1,673		—		1,673
Commodity derivative collars	—		397		—		397
Commodity derivative differential swaps	—		4,200		—		4,200
Total assets	—		6,270		—		6,270

Liabilities:
Commodity derivative oil swaps	$	—	$	23,162	$	—	$	23,162
Commodity derivative deferred premium puts	—		340		—		340
Commodity derivative collars	—		—		—		—
Commodity derivative differential swaps	—		—		—		—
Total liabilities	$	—	$	23,502	$	—	$	23,502

Derivative instruments listed above are presented gross and include collars, swaps, and put options 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. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company classifying its derivatives as Level 2 instruments. This observable data includes the forward curve for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves.

For additional information on the Company’s derivative instruments and balance sheet presentation, see Note 4.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis in the Company’s condensed consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

Asset Retirement Obligations (ARO’s) — The Company initially estimates the fair value of ARO’s based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, the amount and timing of settlements, the credit-adjusted risk-free rate and inflation rates. See Note 5 for a summary of changes in ARO’s.

4. Risk Management and Derivative Instruments

The Company is exposed to fluctuations in crude oil and natural gas prices on its production. 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 and natural gas production. The Company utilizes various types of derivative financial instruments, including swaps and options, to

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manage fluctuations in cash flows resulting from changes in commodity prices. These derivative contracts are generally placed with major financial institutions that the Company believes are minimal credit risks. The oil and gas reference prices, upon which the commodity derivative contracts are based, reflect various market indices that management believes have a high degree of historical correlation with actual prices received by the Company for its oil and 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, 2012 would have been approximately $18.3 million.

Commodity Derivative Contracts

As of June 30, 2012, the Company had the following open commodity positions:

	Hedged Volume	Weighted-Average Fixed Price

Oil (Bbls):
WTI Swaps — 2012	411,100	$		84.36
WTI Swaps — 2013	679,125			84.73
WTI Swaps — 2014	262,450			83.00

WTI Collars — 2012	82,800	$	85.00 -	127.28

WTI Deferred Premium Puts — 2012 (1)	276,000	$		79.01

WTI Basis Differential Swaps — 2012 (2)	505,300	$		9.73
WTI Basis Differential Swaps — 2013 (2)	679,125			6.30

LLS Swaps - 2012	315,180	$		116.55

Brent Swaps - 2013	1,021,749	$		111.89

(1) 2012 deferred premium puts represent the net effective floor price of a put with a strike price of $85.00/Bbl and a deferred premium of $5.99/Bbl. The premiums for these instruments are paid each month, concurrently with the settlement of the monthly put contracts.

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

Balance Sheet Presentation

The following table summarizes the gross fair value 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 condensed consolidated balance sheets at June 30, 2012 and December 31, 2011, respectively (in thousands):

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Type	Balance Sheet Location (1)	June 30, 2012			December 31, 2011
Oil Swaps	Derivative financial instruments — Current Assets	$	6,633		$	—
Oil Swaps	Derivative financial instruments — Non-Current Assets	8,166			—
Oil Swaps	Derivative financial instruments — Current Liabilities	(2,225		)	(13,046		)
Oil Swaps	Derivative financial instruments — Non-Current Liabilities	(2,172		)	(10,116		)
Deferred Premium Puts	Derivative financial instruments — Current Assets	1,015			1,673
Deferred Premium Puts	Derivative financial instruments — Non-Current Assets	—			—
Deferred Premium Puts	Derivative financial instruments — Current Liabilities	(180		)	(278		)
Deferred Premium Puts	Derivative financial instruments — Non-Current Liabilities	—			(62		)
Collars	Derivative financial instruments — Current Assets	380			397
Collars	Derivative financial instruments — Non-Current Assets	—			—
Collars	Derivative financial instruments — Current Liabilities	(10		)	—
Collars	Derivative financial instruments — Non-Current Liabilities	—			—
Basis Differential Swaps	Derivative financial instruments — Current Assets	7,060			3,612
Basis Differential Swaps	Derivative financial instruments — Non-Current Assets	311			588
Basis Differential Swaps	Derivative financial instruments — Current Liabilities	(996		)	—
Basis Differential Swaps	Derivative financial instruments — Non-Current Liabilities	(57		)	—
Total		$	17,925		$	(17,232	)

(1) The fair value of derivative instruments reported in the Company’s condensed consolidated balance sheets are subject to netting arrangements and qualify for net presentation. The following table reports the net derivative fair values as reported in the Company’s condensed consolidated balance sheets as of June 30, 2012 and December 31, 2011, respectively (in thousands):

	June 30, 2012		December 31, 2011
Consolidated balance sheet classification:
Current derivative instruments:
Assets	12,038		4,957
Liabilities	(360	)	(12,599	)

Non-current derivative instruments :
Assets	6,247		588
Liabilities	—		(10,178	)

Gains/Losses on Commodity Derivative Contracts

The Company does not designate its commodity derivative contracts as hedging instruments for financial reporting purposes. Accordingly, all gains and losses, including unrealized gains and losses from changes in the derivative instruments’ fair values, have been recorded in “Gains (losses) on commodity derivative contracts — net”, within revenues in the condensed consolidated statements of operations.

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2012		2011		2012		2011

Realized net gains (losses)	(5,180	)	(6,130	)	(11,679	)	(8,137	)
Unrealized net gains (losses)	53,323		16,607		35,157		(9,982	)

5. Asset Retirement Obligations

Asset retirement obligations represent the future abandonment costs of tangible assets, such as wells, service assets and other facilities. The fair value of the asset retirement obligation at inception is capitalized as part of the carrying amount of the related long-lived assets. Asset retirement obligations approximated $9.4 million and $7.6 million as of June 30, 2012 and December 31, 2011, respectively.

The liability has been accreted to its present value as of June 30, 2012 and December 31, 2011. The Company evaluated its wells and determined a range of abandonment dates through 2058.

The following table reflects the changes in the Company’s asset retirement obligations for the six months ended June 30, 2012 (in thousands):

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Asset retirement obligations at January 1, 2012	$	7,627
Liabilities incurred	1,470
Revisions	3
Liabilities settled	—
Current period accretion expense	298
Asset retirement obligations at June 30, 2012	$	9,398

6. Long-Term Debt

The Company’s long-term debt as of June 30, 2012 and December 31, 2011 is as follows (in thousands):

	June 30, 2012		December 31, 2011
Revolving credit facility	$	151,700	$	234,800
Less: current maturities of debt	—		—
Long-term debt	$	151,700	$	234,800

On June 8, 2012, Midstates Petroleum Company LLC entered into a Second Amended and Restated Credit Agreement among Midstates Petroleum Company LLC, as borrower, the Company, as guarantor, the lenders party thereto and SunTrust Bank, as the new administrative agent (the “Amended Credit Agreement”).

The Amended Credit Agreement increased the size of the revolving credit facility from $300 million to $500 million, added additional lenders to the bank group and set the initial borrowing base at $200 million. In addition, the lenders under the Amended Credit Agreement have agreed that there will be no reduction in the Company’s borrowing base under the Amended Credit Agreement for the issuance of up to $275 million of senior unsecured notes. In the event that the Company elects to issue senior unsecured notes in excess of $275 million, the borrowing base will be reduced by 25% of the face value (without giving effect to any original issue discount) of such notes in excess of $275 million. The Amended Credit Agreement also extended the maturity date of the revolving credit facility from December 10, 2014 to June 8, 2017. At the closing of the Amended Credit Agreement, the Company borrowed $20.0 million under the revolving credit facility.

Borrowings under the Amended Credit Agreement continue to be secured by substantially all of the Company’s oil and natural gas properties and currently bear interest at LIBOR plus an applicable margin between 1.75% and 2.75% per annum. At June 30, 2012 and December 31, 2011, the weighted-average interest rate was 2.9% and 3.2%, respectively.

In addition to interest expense, the Amended Credit Agreement 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 Amended Credit Agreement is subject to semiannual redeterminations in March and September 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 revolving credit facility, the Company is required to repay the amount by which the principal balance of its outstanding loans and its letter of credit obligations exceed its redetermined borrowing base. The Company is permitted to make such repayment in six equal successive monthly payments commencing 30 days following the administrative agent’s notice regarding such borrowing base reduction.

The revolving credit facility contains financial covenants, which, among other things, set a maximum ratio of debt to earnings before interest, income tax, depletion, depreciation, and amortization (EBITDA) of not more than 4.0 to 1, a minimum current ratio (as defined therein) of not less than 1.0 to 1.0 and various other standard affirmative and negative covenants including, but not limited to, restrictions on the Company’s ability to make any dividends, distributions or redemptions. As of June 30, 2012, the Company is in compliance with the financial debt covenants set forth in the Amended Credit Agreement.

In connection with the Amended Credit Agreement, the Company incurred legal fees and fees payable to the lending banks of approximately $2.1 million, which together with the remaining unamortized fees associated with the revolving credit facility prior to the amendment, will be amortized as additional interest expense over the new maturity date of June 8, 2017.

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The Company’s credit facility at December 31, 2011 and through June 7, 2012, consisted of a $300 million senior revolving credit facility (the “Facility”) with a borrowing base, as redetermined in March 2012, of $210 million. Prior to the amendment, the revolving credit facility had a maturity date of December 10, 2014 and bore interest at LIBOR plus an applicable margin between 2.00% and 2.75% per annum. In April 2012, the Company repaid $103.2 million of the outstanding Facility balance.

The Company believes the carrying amount of the Amended Credit Agreement at June 30, 2012 approximates its fair value (Level 2) due to the variable nature of the applicable interest rate.

7. Mandatorily Redeemable Convertible Preferred Units

In December 2011, Holdings LLC, FR Midstates Holdings LLC (“FR Midstates”) and Midstates Petroleum Holdings, Inc. (“Petroleum Inc.”) entered into an amended and restated limited liability company agreement, which was later amended in March 2012, to provide for the issuance of up to 65,000, or $65 million in aggregate value, of certain mandatorily redeemable convertible preferred units (the “Preferred Units”) between December 15, 2011 and June 10, 2015. The Preferred Units had a liquidation value of $1,000 per unit and bore interest, compounded quarterly, at a rate of 8% plus the greater of LIBOR or 1.5%. The Preferred Units were convertible into units of Holdings LLC on or after the one year anniversary of the date of issuance into a number of common units with a fair market value (as determined by the Board of Directors) equal to the liquidation value plus any accrued interest and were redeemable for cash at any time at the option of Holdings LLC, but were mandatorily redeemable for cash on June 10, 2015, unless otherwise converted. In addition, a fixed interest charge of 1.5% of the aggregate capital invested in the Preferred Units was payable upon redemption or conversion.

On January 4, 2012, and again on February 9, 2012, Holdings LLC issued 20,000 Preferred Units (for a total of 40,000 Preferred Units) to FR Midstates for aggregate cash proceeds of $40.0 million. On April 3, 2012, Holdings LLC issued an additional 25,000 preferred units to FR Midstates for aggregate cash proceeds of $25.0 million.

On April 26, 2012, Midstates Petroleum Company, Inc. used $67.1 million of the proceeds from its initial public offering to redeem the Preferred Units in full, including interest and other charges. As such, at June 30, 2012, the Preferred Units are no longer outstanding. Midstates Petroleum Company, Inc. recorded $2.1 million related to interest expense associated with these Preferred Units for the six months ended June 30, 2012.

8. Equity and Share-Based Compensation

At December 31, 2011, Holdings LLC had 256,742 common units issued and outstanding. On April 24, 2012, in connection with Midstates Petroleum Company, Inc.’s initial public offering, a corporate reorganization occurred and each common unit of Holdings LLC was converted into approximately 185.5 common shares of Midstates Petroleum Company, Inc. and as a result, Midstates Petroleum Company, Inc. issued 47,634,353 shares of its common stock.

On April 25, 2012, Midstates Petroleum Company Inc. completed its initial public offering of common stock pursuant to a registration statement on Form S-1 (File 333-177966), as amended and declared effective by the SEC on April 19, 2012. Pursuant to the registration statement, Midstates Petroleum Company, Inc. registered the offer and sale of 27,600,000 shares of $0.01 par value common stock, which included 6,000,000 shares of stock sold by the selling shareholders and 3,600,000 shares of common stock sold by the selling stockholders pursuant to an option granted to the underwriters to cover over-allotments. Midstates Petroleum Company, Inc.’s sale of the shares in its initial public offering closed on April 25, 2012.

After the corporate reorganization and the completion of its initial public offering discussed above, Midstates Petroleum Company, Inc. is authorized to issue up to a total of 300,000,000 shares of its common stock with a par value $0.01 per share, and 50,000,000 shares of its preferred stock with a par value of $0.01 per share. Holders of Midstates Petroleum Company, Inc.’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. At June 30, 2012, Midstates Petroleum Company, Inc. had 66,549,563 shares of its common stock issued and outstanding.

With respect to preferred shares, Midstates Petroleum Company, Inc. 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. At June 30, 2012, no preferred shares were issued or outstanding.

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Share-Based Compensation, pre Initial Public Offering

During the six months ended June 30, 2011, certain restricted and unrestricted shares in Petroleum Inc., through which Holdings LLC’s founders, members of management and certain employees previously held their equity interests, certain unrestricted units in Holdings LLC, and certain units in Midstates Incentive Holdings, LLC (“Midstates Incentive”) had been issued to employees of Holdings LLC.

Additionally, in March 2011, Holdings LLC’s Chief Executive Officer, in connection with the commencement of his employment, purchased 17.3 shares of common stock of Petroleum Inc. and contemporaneously received a grant of 24.6 shares of common stock in Petroleum Inc. that vested as described further below. No other shares or units were issued during the 2011 period. The Company determined the grant date fair value of the share based award to be $80,013 per Petroleum Inc. share ($3.4 million in aggregate), or after taking into account the corporate reorganization attributable to the initial public offering completed on April 25, 2012, $4.26 per share of Midstates Petroleum Company, Inc. common stock. The Company recognized stock compensation in accordance with ASC Topic 718, “Compensation — Stock Compensation” based upon the grant date fair value and immediately expensed the difference between the grant date fair value and the price paid for the purchased shares of Petroleum Inc., as well as additional compensation expense related to the liability accounting for the Company’s share-based awards discussed below.

Prior to December 5, 2011, due to certain rights to call shares and units in Holdings LLC for cash, Holdings LLC’s share-based payments awarded to employees were accounted for as liability awards pursuant to ASC Topic 718, “Compensation — Stock Compensation.” As such, Holdings LLC calculated the fair value of the share-based awards on a quarterly basis using estimated market value and the total fair value of the awards was recorded within “Other long-term liabilities” in Holding LLC’s condensed consolidated balance sheets. Any change in the fair value of the liability awards was recorded as share-based compensation expense within “General and administrative expense” in Holdings LLC’s condensed consolidated statements of operations, which was the same line item as cash compensation paid to the same employees.

Historically, Holdings LLC’s determination of the fair value of each of the units was affected by: i) Holdings LLC’s risk adjusted proved, possible, and probable reserves; ii) internal assessment of long-term commodity prices; iii) current values of Holdings LLC’s non-oil and gas assets and liabilities; and iv) a number of complex and subjective variables. Although the fair value of the share-based payments is determined in accordance with GAAP, that value may not be indicative of the fair value observed in a market transaction between a willing buyer and a willing seller.

Effective as of November 22, 2011, the Board of Directors of Petroleum Inc. accelerated the vesting of all restricted stock in Petroleum Inc. The vesting resulted in the recognition of previously unrecognized share-based compensation expense at the estimated fair market value of the restricted stock held by employees at November 22, 2011. Petroleum Inc. determined the fair market value of Petroleum Inc.’s common stock based on management’s estimates.

On December 5, 2011, Employment Agreements with employees of Midstates Petroleum Company LLC, a Stockholders’ Agreement by and among stockholders in Petroleum Inc. and a Unitholders’ Agreement by and among the members of Holdings LLC were either terminated or amended such that the rights within those agreements to call shares in Petroleum Inc. and units in Holdings LLC for cash no longer required Holdings LLC’s share-based payments awarded to employees to be accounted for as liability awards. As a result the Company transitioned as of December 5, 2011 from liability accounting to equity accounting for the Company’s share-based compensation plans and accordingly, the Company no longer recognized changes in the estimated fair value of outstanding share-based awards in the statements of operations.

Restricted Shares.

Restricted shares in Petroleum Inc. were awarded at no cost to the recipient with a vesting period that commenced on the grant date and terminated on the fifth anniversary or upon certain changes in control of Holdings LLC, including but not limited to mergers, acquisitions, or a public offering (a “Triggering Event”).

As a result of the vesting on November 22, 2011, as discussed above, there is no unrecognized compensation cost and as a result of the corporate reorganization in April 2012, each share of Petroleum Inc. was converted into 18,762 shares of common stock of Midstates Petroleum Company, Inc. As a result, there are no outstanding restricted shares in Petroleum Inc. as of June 30, 2012.

Unrestricted Shares and Units.

Unrestricted shares in Petroleum Inc. and units of Holdings LLC were purchased by the recipient on the grant date and were fully vested upon purchase, or represented restricted shares which have vested. For shares of Petroleum Inc and units of Holdings LLC purchased, any difference between the recipient’s purchase price and the grant date fair value was recognized as compensation expense on the grant date. As a result of the corporate reorganization in April 2012, each share of Petroleum, Inc. and each unit of

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Holdings LLC were converted into 18,762 and 185.5 shares respectively, of Midstates Petroleum Company, Inc. common stock. As a result, at June 30, 2012, there are no Petroleum, Inc. shares or Holdings LLC units outstanding.

Incentive Units.

At June 30, 2012, 1,659 incentive units were issued and outstanding. In connection with the corporate reorganization that occurred immediately prior to our initial public offering, these incentive units held in the Company were contributed to FR Midstates Interholding, LP (“FRMI”) in exchange for incentive units in FRMI. Holders of FRMI incentive units will receive, out of proceeds otherwise distributable to FRMI, a percentage interest in the amounts distributed to FRMI in excess of certain multiples of FRMI’s aggregate capital contributions and investment expenses (“FRMI Profits”). Although any future payments to the incentive unit holders will be made out of the proceeds otherwise distributable to FRMI and not by the Company, the Company will be required to record a non-cash compensation charge in the period any payment is made related to the FRMI incentive units. To date, no compensation expense related to the incentive units has been recognized by the Company, as any payout under the incentive units is not considered probable, and thus, the amount of FRMI Profits, if any, cannot be determined.

Share-based Compensation, Post-Initial Public Offering

2012 Long Term Incentive Plan

On April 20, 2012, Midstates Petroleum Company, Inc. established the 2012 Long Term Incentive Plan (the “2012 LTIP”) and filed a Form S-8 with the SEC, registering 6,563,435 shares for future issuance under the terms of the 2012 LTIP. 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. A total of 6,563,435 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.

Subsequent to the completion of the Company’s initial public offering and pursuant to the 2012 LTIP, the Company issued 916,594 shares of restricted common stock to directors, management and employees. Shares granted under the LTIP vest ratably over a period of three years (one-third on each anniversary of the grant).

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 three year service period. As of June 30, 2012, the Company assumed no annual forfeiture rate because of the Company’s lack of turnover and history for this type of award.

The following table summarizes the Company’s non-vested share award activity for the six months ended June 30, 2012:

	Shares		Weighted Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2011	—
Granted	916,594		$	13.16
Vested	—		$	—
Forfeited	(1,384	)	$	13.00
Non-vested shares outstanding at June 30, 2012	915,210		$	13.16

Unrecognized expense as of June 30, 2012 for all outstanding restricted stock awards was $11.4 million and will be recognized over a weighted average period of 2.8 years.

At June 30, 2012, 5,648,225 shares remain available for issuance under the terms of the 2012 LTIP.

The following table summarizes share-based compensation costs recognized by the Company for the periods presented (in thousands):

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	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2012		2011		2012		2011
Restricted and unrestricted Petroleum Inc. shares and Holdings LLC units	$	—	$	7,299	$	—	$	7,949
Incentive units	—		—		—		—
2012 LTIP restricted shares	682		—		682		—
Total share-based compensation expense	682		7,299		682		7,949

9. 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 IPO, the Company merged into a corporation and became subject to federal and state income taxes. The Company’s book and tax basis in assets and liabilities differed at the time of the corporate reorganization due primarily to different cost recovery periods utilized for book and tax purposes for the Company’s oil and natural gas properties. In the second quarter of 2012, the Company recorded a net deferred tax expense of $149.5 million to recognize a deferred tax liability related to the Company’s initial book and tax basis differences due to its change in tax status.

Subsequent to the corporate reorganization, the Company’s effective tax rate is expected to be 49.7% The Company’s effective tax rate differs from the federal statutory rate of 35% due to: (i) the inability to use pre-IPO losses to offset post-IPO earnings, and (ii) state income taxes. The Company expects to incur a tax loss in the current year (due principally to the ability to expense certain intangible drilling and development costs under current law) and thus no current income taxes are anticipated to be paid. This tax loss is expected to result in a Net Operating Loss carryforward at year-end; however, no valuation allowance has been recorded as management believes that there is sufficient future taxable income to fully utilize all tax attributes. This future taxable income arises from reversing temporary differences due to the excess of the book carrying value of oil and gas properties over their corresponding tax bases. Management is not relying on other sources of taxable income in concluding that no valuation allowance is needed.

As of June 30, 2012, the Company has not recorded a reserve for any uncertain tax positions.

10. Earnings (Loss) Per Share

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 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.

The following table is a calculation of the pro forma basic and diluted weighted-average shares outstanding for the three and six months ended June 30, 2012.

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	For the Three Months Ended June 30,
	2012							2011
	Income			Shares	Per Share			Income	Shares	Per Share
	(in thousands, except per share amounts)
Net Loss	$	(112,377	)
Loss Allocable to Nonvested Restricted Stock (1)	—
Basic Net Loss Attributable to Common Stock	$	(112,377	)	60,887	$	(1.85	)	N/A	N/A	N/A

Effect of Dilutive Securities:
N/A (2)	—			—
Diluted Net Loss Attributable to Common Stock	$	(112,377	)	60,887	$	(1.85	)	N/A	N/A	N/A

	For the Six Months Ended June 30,
	2012							2011
	Income			Shares	Per Share			Income	Shares	Per Share
	(in thousands, except per share amounts)
Net Loss	$	(129,884	)
Loss Allocable to Nonvested Restricted Stock (1)	—
Basic Net Loss Attributable to Common Stock	$	(129,884	)	54,261	$	(2.39	)	N/A	N/A	N/A

Effect of Dilutive Securities:
N/A (2)	—			—
Diluted Net Loss Attributable to Common Stock	$	(129,884	)	54,261	$	(2.39	)	N/A	N/A	N/A

(1) Due to the basic net loss attributable to common shareholders for the three and six months ended June 30, 2012, the Company excluded 626,921 and 313,460 weighted-average outstanding nonvested restricted stock, respectively, from the computations of net loss per share because these securities do not participate in undistributed net losses.

(2) At June 30, 2012, there were no other dilutive securities outstanding to consider for the periods presented as unvested restricted stock grants had already been considered as part of the two-class method.

The aggregate number of common and nonvested restricted shares outstanding at June 30, 2012 was 65,634,353 and 915,210, respectively.

11. Related Party Transactions

At June 30, 2012, a minority owner of Petroleum Inc. was also a significant owner of one of the Company’s vendors. For the three and six months ended June 30, 2012, the amount paid to this vendor was $0.8 million and $1.5 million, respectively. For the three and six months ended June 30, 2011, the amount paid to this vendor was $0.8 million and $1.1 million, respectively.

The amount payable at June 30, 2012 and December 31, 2011 was $0.2 million and $0.1 million, respectively.

12. Commitments and Contingencies

Contractual Obligations

At June 30, 2012, contractual obligations for drilling contracts, long-term operating leases, seismic contracts and other are as follows (in thousands):

	Total		2012 (remainder)		2013		2014		2015		2016 and beyond

Drilling contracts	$	6,150	6,150		—		—		—		—
Non-cancellable office lease commitments (1)	$	8,436	634		1,418		1,439		1,459		3,486
Seismic contracts	$	8,824	8,324		500		—		—		—
Other	$	1,110	1,110		—		—		—		—

Net minimum commitments	$	24,520	$	16,218	$	1,918	$	1,439	$	1,459	$	3,486

(1) On June 4, 2012, the Company executed an amendment to its office space lease agreement for relocation to a new floor within its current office building. Under the terms of the amendment, the Company’s obligation for its existing premises on

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two floors will terminate and rental obligations for the new premises will begin upon substantial completion of the remodeling work in the new premises, which is projected to be October 2012, and when the Company will take possession of the new premises. The amended lease agreement will have a term of 66 months.

Litigation

Clovelly Oil Company.

The Company is a defendant in an action brought by Clovelly Oil Company (the “Plaintiff” or “Clovelly”) in the 13th Judicial District Court in Louisiana in May 2009. The Plaintiff alleges that the Company is subject to an unrecorded Joint Operating Agreement (“JOA”) dated July 16, 1972, as a result of the Company’s 2007 purchase of a 43.75% working interest in certain acreage. The Plaintiff further alleges that the Company is bound by the 1972 JOA and that the Plaintiff is entitled to 56.25% of the Company’s 242.28-acre Crowell Land & Mineral lease. The Company was not a signatory to the JOA, and believes that it is protected by the Louisiana Public Records Doctrine, which generally provides that instruments involving real property are without effect as to third parties unless the instrument is filed of record in the appropriate mortgage or conveyance records of the parish in which such property is located.

The Company made a motion for summary judgment on all of the Plaintiff’s claims, and the 13th Judicial District Court granted that motion on August 14, 2009. The Plaintiff appealed the district court’s decision to the Third Circuit Court of Appeal, and on April 7, 2010, the Third Circuit Court of Appeal reversed and remanded the case to the district court for trial. On August 9, 2010, the Plaintiff amended its original petition to add Wells Fargo Bank, N. A., which holds a mortgage on the acreage, as a defendant.

In December 2010, the Company filed a Motion for Partial Summary Judgment asking the district court to declare that the JOA does not apply to any new leases acquired after July 16, 1972 which are not extension or renewal leases. On September 27, 2011, the district court granted the Company’s motion for partial summary judgment. The district court also granted a motion for summary judgment filed by Wells Fargo asserting that, as a mortgage holder of a mortgage covering the applicable lease, Wells Fargo is protected by the Public Records Doctrine. The Plaintiff again appealed.

On June 6, 2012, the Third Circuit Court of Appeal reversed the district court’s partial summary judgment decision that the JOA does not apply to any new leases. It held that, if the Company is subject to the JOA, then the JOA applies to leases acquired by the Company after the 2007 purchase that are within the acreage covered by the JOA. Separately, the Court of Appeal upheld the district’s court decision that Wells Fargo is protected by the Public Records Doctrine. The Court of Appeal then remanded the case to the district court for a determination of whether the Company had assumed the obligations under the JOA.

The Company timely filed an Application for Rehearing of the June 6 decision, and the Court of Appeal has not yet ruled on the application. If appropriate relief is not obtained from the Court of Appeal on rehearing, the Company will evaluate whether to file a writ of certiorari to the Louisiana Supreme Court seeking review and reversal of the Court of Appeal’s decision

A final adverse court decision that the Company is subject to the JOA could entitle Clovelly to a 56.25% interest in the leases affected by the litigation. Approximately 2.0 MMBOE of the Company’s 26.2 MMBOE of total proved reserves as of December 31, 2011 are attributable to properties that would potentially be subject to Clovelly’s interest. Such an adverse court decision could result in a material adverse effect on our financial condition, future planned operations and/or cash flow.

The Company disputes the allegations and intends to continue to vigorously defend against this litigation.

Other.

We are involved in other disputes or legal actions arising in the ordinary course of our business. We may not be able to predict the timing or outcome of these or future claims and proceedings with certainty, and an unfavorable resolution of one or more of such matters could have a material adverse effect on our financial condition, results of operations or cash flows. Currently, we are not party to any legal proceedings that, individually or in the aggregate, are reasonably expected to have a material adverse effect on our financial position, results of operations, or cash flows.

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13. Subsequent Events

New Commodity Hedges

In July 2012, the Company entered into several commodity derivative transactions to more closely align the reference prices of its commodity derivative prices to the actual prices received for oil production. On August 10, 2012, the Company had the following open commodity positions:

	Hedged Volume	Weighted-Average Fixed Price

Oil (Bbls):
Swaps – 2012	644,130	$		95.77
Swaps – 2013	1,700,874	95.55
Swaps – 2014	262,450	83.00

Collars – 2012	68,850	$	85.00 - $	127.28

Deferred Premium Puts – 2012 (1)	229,500	$		79.01

Basis Differential Swaps – 2012 (2)	789,480	$		9.81
Basis Differential Swaps – 2013 (2)	1,700,874	$		5.91

Long-term Debt

On July 13, 2012, the Company borrowed an additional $20.0 million pursuant to the terms of the Amended Credit Facility.

Eagle Acquisition

On August 11, 2012, the Company and Midstates Petroleum Company, LLC (“Midstates Sub”), a wholly owned subsidiary of the Company, entered into an Asset Purchase Agreement (the “Agreement”) with Eagle Energy Production, LLC (“Eagle”), pursuant to which Midstates Sub agreed to acquire certain interests in producing oil and natural gas assets, unevaluated leasehold acreage in Oklahoma and Kansas and the related hedging instruments (the “Eagle Acquisition”). The aggregate purchase price, subject to adjustment as provided in the Agreement, consists of (a) $325 million in cash and (b) 325,000 shares of Series A Preferred Stock of the Company with an initial liquidation preference of $1,000 per share.

Eagle, the Company and Midstates Sub have made customary representations, warranties and covenants in the Agreement. Eagle has made certain additional customary covenants, including, among others, covenants to conduct its business in the ordinary course between the execution of the Agreement and the closing of the Eagle Acquisition and not to engage in certain kinds of transactions during that period, subject to certain exceptions. The Company has agreed not to take certain specified actions without Eagle’s consent during the time between execution of the Agreement and the closing of the Eagle Acquisition.

Consummation of the Eagle Acquisition is subject to various conditions, including, among others, (1) the accuracy of representations and warranties of the parties as of the closing date, including the absence of any material adverse effect with respect to each of Eagle’s business and the Company’s business, (2) the release of certain liens in connection with the repayment of Eagle’s indebtedness, (3) the execution of certain ancillary documents and (4) other customary closing conditions. The Eagle Acquisition will be effective June 1, 2012 and closing is expected to occur on or about October 1, 2012. The Agreement may be terminated under customary circumstances.

The Series A Preferred Stock will not become convertible into shares of the Company’s common stock until the 21st day after the date on which the Company mails to its stockholders an information statement regarding the issuance of the Series A Preferred Stock, and the holders of the Series A Preferred Stock may not convert before the first anniversary of the closing date of the Eagle Acquisition. After such time, the Series A Preferred Stock may be converted, in whole but not in part, at the option of the holders of a majority of the outstanding shares of Series A Preferred Stock, into a number of shares of the Company’s common stock calculated by dividing the then-current liquidation preference by the conversion price of $13.50 per share. In addition, the Series A Preferred Stock will be subject to mandatory conversion into shares of the Company’s common stock on September 30, 2015 at a conversion price no greater than $13.50 per share and no less than $11.00 per share. Dividends on the Series A Preferred Stock will accrue at a rate of 8.0% per annum, payable semi-annually, at the sole option of the Company, in cash or through an increase in the liquidation preference. The Series A Preferred Stock will also have the other rights and terms set forth on the Certificate of Designation, including voting rights that are similar to those belonging to holders of the Company’s common stock on an as-converted basis (except with respect to the election of directors and the approval of certain transactions where the holders of the Series A Preferred Stock would be entitled to consideration at least equal to the liquidation preference) until such time as holders of the Series A Preferred Stock are permitted to convert their shares into common stock and the market price of the Company’s common stock is above the conversion price for 15 consecutive trading days. In addition, the holders of the Series A Preferred Stock will have the right, subject to the terms and conditions set forth in the Certificate of Designations, to elect one member of the board of directors, and to approve certain corporate actions. The Series A Preferred Stock will rank senior to the Company’s common stock with respect to dividend rights. The issuance of the Series A Preferred Stock to Eagle pursuant to the Agreement has been approved by stockholders holding a majority of the outstanding shares of the Company’s common stock.

The purchase will be accounted for using the acquisition method of accounting. Under the acquisition method of accounting, the Company is required to allocate the purchase price to tangible and identifiable intangible assets acquired and liabilities assumed based on their fair values at the Closing Date. The excess of the purchase price over those fair values, if any, is recorded as goodwill. Disclosures required by ASC 805, Business Combinations, will be provided once the closing occurs and the initial accounting for the acquisition is complete.

Commitment for Bridge Credit Facility and Amendment to Revolver

In connection with the execution of the Agreement, on August 11, 2012, the Company and Midstates Sub entered into a commitment letter with (after giving effect to certain subsequent joinders) Bank of America, N.A., Merrill Lynch, Pierce Fenner & Smith Incorporated, SunTrust Bank and SunTrust Robinson Humphrey, Inc., Goldman Sachs Lending Partners LLC and Morgan Stanley Senior Funding, Inc. to, among other things, (A) provide for an unsecured bridge credit facility in the amount of up to $500 million and (B) provide a commitment to amend the existing secured revolving credit facility to increase the borrowing base to $250 million and to accommodate, among other things, the issuance, incurrence and/or compliance with the terms of the Preferred Stock, bridge loans and other debt securities that may be issued or loans that may be incurred in lieu of, or in connection with the replacement of the bridge loans, including senior unsecured notes. The availability of loans under the bridge credit facility and the effectiveness of the amended revolving credit facility are subject to the consummation of the Eagle Acquisition and other customary conditions. The proceeds of the bridge credit facility may be used solely to fund the Eagle Acquisition, to pay transaction costs and expenses in connection therewith or repay existing outstanding debt under the existing revolving credit facility. If entered into, the bridge credit facility will initially bear interest at LIBOR, subject to a 1.50% floor, plus 9.0% and thereafter such 9.0% margin is subject to increases. The bridge credit facility matures on the first anniversary of the closing date of the Eagle Acquisition and contains customary terms regarding the conversion of the bridge loans into other debt instruments subject to certain caps on yield, the highest of which is set at 13.25%. The obligations under the bridge credit facility would be guaranteed by the same entities that guaranty the existing secured revolving credit facility. If entered into, the amended revolving credit facility would mature on the fifth anniversary of the entrance into the facility and the aggregate amount available under the credit facility would increase to $250 million, subject to reduction in the event that the amount of assets acquired in connection with the Eagle Acquisition is less than expected. In addition, it would increase the allowance for the incurrence of certain unsecured indebtedness, without a corresponding reduction in the borrowing base, from $275 million to $500 million thereby permitting the incurrence of the bridge loans or the issuance of other debt without causing a $0.25 reduction in the borrowing base for every $1 of debt incurred or issued above $275 million. The definitive loan documentation for the bridge loan facility will contain representations and warranties, affirmative, negative and financial covenants and events of default similar to those in other similar transactions and will otherwise be similar to the terms set forth in the existing secured revolving credit facility. The definitive loan documentation for the amended revolving credit facility will contain representations and warranties, affirmative, negative and financial covenants and events of default similar to the terms set forth in the existing secured revolving credit facility and which address the above mentioned accommodations.

In addition, on August 11, 2012, the Company and Midstates Sub entered into a second commitment letter with SunTrust Bank, SunTrust Robinson Humphrey, Inc., Bank of America N.A. and Merrill Lynch, Pierce Fenner & Smith Incorporated to underwrite an amendment to the existing secured revolving facility which provides for $35 million of non-conforming borrowing base loans (thereby increasing the borrowing base under the existing secured revolving credit facility from $200 million to $235 million) and waives the requirement to comply with the minimum current ratio financial covenant for the quarters ending September 30, 2012 and December 31, 2012. This amendment is not dependent upon the consummation of the Eagle Acquisition. The availability of non-conforming borrowing base loans will end upon the earliest to occur of (i) the closing of the Eagle Acquisition, (ii) the issuance of certain unsecured indebtedness permitted under the existing secured revolving credit facility and (iii) the scheduled March 2013 borrowing base redetermination. Thereafter, subject to the other commitments contemplated by the other commitment letter discussed above, the borrowing base would reduce to $200 million and loans would be permitted subject to the $200 million borrowing base. Borrowings under the terms of the amended revolving credit facility would bear interest at the same rates applicable to the existing secured revolving credit facility, provided that if borrowing base usage exceeded $200 million the amount of applicable margin would increase to up to 3.00% in the case of base rate loans and 4.00% in the case of LIBOR loans. Similarly, commitment fees would be the same rates applicable to the existing secured revolving credit facility subject to an increase up to 0.625% if borrowing base usage exceeded $200 million. The definitive loan documentation for this amended revolving credit facility will be effective upon the satisfaction of customary conditions and contain representations and warranties, affirmative, negative and financial covenants and events of default substantially the same as the terms set forth in the existing secured revolving credit facility.

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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, 2011, and the related management’s discussion and analysis contained in our final prospectus dated April 19, 2012 and filed with the Securities and Exchange Commission (“SEC”) pursuant to Rule 424(b) on April 20, 2012, as well as the unaudited condensed consolidated financial statements and notes thereto included in this quarterly report on Form 10-Q and in our quarterly report on Form 10-Q for quarter ended March 31, 2012.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in or incorporated by reference into this report that express a belief, expectation, or intention, or that are not statements of historical fact, 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, plans and objectives of management are forward-looking statements. When used in this quarterly report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” and similar expressions are intended to identify forward looking statements, although not all forward looking statements contain such identifying words. In particular, the factors discussed in this report on Form 10-Q, our quarterly report on Form 10-Q for the quarter ended March 31, 2012 and detailed in our prospectus dated April 19, 2012 and filed with the SEC pursuant to Rule 424(b) on April 20, 2012, 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;

· reserves;

· 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;

· 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 closing, financing, integration and benefits of the Eagle Acquisition or the effects of the acquisition on our cash position and levels of indebtedness;

· property acquisitions;

· 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;

· estimated future net reserves and present value thereof; and

· plans, objectives, expectations and intentions contained in this prospectus 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 make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we

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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 development of oil-prone resources in the Upper Gulf Coast Tertiary trend onshore in central Louisiana. Our current acreage positions and evaluation efforts are concentrated in the Wilcox interval of the trend. We are currently focused on the development of our inventory of identified drilling locations, which we will selectively allocate capital to by applying rigorous investment analysis in an effort to maximize our potential returns. We are focused on maximizing the net present value of our drilling opportunities by measuring risk and financial return, among other factors. In addition, we are the operator of the substantial majority of our properties, which enables us to better control timing, costs and drilling and completion techniques.

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, 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.

With the completion of our initial public offering, we became a publicly traded company, the common stock of which is listed on the NYSE under the ticker symbol “MPO.” 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 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.

Eagle Energy Asset Acquisition

On August 11, 2012, the Company and Midstates Petroleum Company, LLC (“Midstates Sub”), a wholly owned subsidiary of the Company, entered into an Asset Purchase Agreement (the “Agreement”) with Eagle Energy Production, LLC (“Eagle”), pursuant to which Midstates Sub agreed to acquire certain interests in producing oil and natural gas assets, unevaluated leasehold acreage in Oklahoma and Kansas and the related hedging instruments (the “Eagle Acquisition”). The aggregate purchase price, subject to adjustment as provided in the Agreement, consists of (a) $325,000,000 in cash and (b) 325,000 shares of Series A Preferred Stock of the Company with an initial liquidation preference of $1,000 per share.

In connection with the Eagle Acquisition, on August 11, 2012 the Company entered into a commitment letter to, among other things, (A) provide for a Bridge Facility in the amount of up to $500 million and (B) provide a commitment to amend the Amended Credit Agreement to increase the borrowing base to $250 million and to accommodate, among other things, the issuance, incurrence and/or compliance with the terms of senior notes, bridge loans and other financing in connection with the Eagle Acquisition.

The commitment letter provides that the Bridge Facility will be in an aggregate principal amount of up to $500 million (the “Bridge Loans”). The proceeds of the Bridge Loans will be used by the Company on the Eagle Acquisition closing date solely to consummate the Eagle Acquisition transactions, to pay transaction costs and expenses in connection therewith or repay existing outstanding debt of the Company under the existing revolving credit facility. The Bridge Facility is to contain representations and warranties and affirmative and negative covenants customarily found in similar transactions. Midstates will use the proceeds from this financing or other debt financing to fund the cash portion of the Eagle Acquisition and to enhance the Company’s liquidity. Please read “-Liquidity and Capital Resources” for more information about the terms of the Bridge Facility and the amendment to the Amended Credit Agreement, as provided for by the commitment letter.

The consummation of the Eagle Acquisition is subject to customary closing considerations and is expected to close on October 1, 2012.

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Operations Update

Since December 31, 2011, we spud 33 gross wells during the six months ended June 30, 2012, of which 20 were spud during the second quarter, including one horizontal well. In addition, one horizontal sidetrack was spud. Of these 33 wells, 20 were producing, seven were awaiting completion and six were drilling at quarter end. Since June 30, 2012, we spud an additional seven wells and one horizontal sidetrack. As of June 30, 2012, our properties consisted of approximately 121 gross active producing wells, 95% of which we operate. We hold an average working interest of 97%.

During the three and six months ended June 30, 2012, our average daily production was 7,904 Boe/d and 8,090 Boe/d, respectively. Our average daily production for the three months ended June 30, 2012 was below our average for the first quarter of 8,275 Boe/day. Oil production increased by approximately 10%, while natural gas and NGLs decreased approximately 21%, primarily due to continued severe declines on two higher gas oil ratio (“GOR”) wells in our Central Fault Block area of South Bearhead Creek. Results that were below expectations from recent West Gordon wells and unplanned downtime were responsible for lower than projected volumes, which will be described in further detail below.

We are revising our drilling plan for the remainder of 2012 to increase focus on the Pine Prairie project area while we continue to analyze the results of our drilling programs in the other areas.

As of June 30, 2012 our total capital expenditure budget for 2012 has been revised from $380 to $365 million, which consists of:

· $292 million for drilling and completion capital;

· $52 million for acquisition of acreage and seismic data; and

· $21 million in unallocated funds which are available for facilities and other capital expenditures.

Through June 30, 2012, approximately $206.5 million of our 2012 capital expenditure budget had been incurred.

Set forth below is a discussion of our operating results and projected activity for the remainder of 2012 by area.

Pine Prairie

In Pine Prairie, we drilled 11 vertical wells during the second quarter of 2012, eight of which targeted the Wilcox interval and three of which targeted the shallower Miocene and Frio intervals. All of these wells are currently on production.

We now expect to drill 34 vertical wells and one vertical sidetrack in Pine Prairie during the second half of 2012, an increase of 11 wells from our prior drilling program projections. The program will consist of 21 Wilcox wells and 13 shallower Miocene/Frio wells. We anticipate that capital expenditures in our Pine Prairie area for the second half of 2012 will be approximately $87 million, or 55% of our total capital expenditure budget for the period. This results in an increase of $43 million expected to be spent in the area versus our prior capital expenditure budget.

During the three months ended June 30, 2012, average production from these properties was 4,669 net Boe/d, an increase of 548 net Boe/d compared to the three months ended March 31, 2012.

Our Wilcox program is performing consistent with our expectations and our shallower Miocene/Frio program is performing above expectations. During the three months ended June 30, 2012, the Miocene/Frio drilling program experienced a delay due to the shallow rig not arriving until June.

South Bearhead Creek

In the South Bearhead Creek area, we drilled a total of four wells during the second quarter of 2012, three of which were vertical wells and one of which was a horizontal well. One of the vertical wells and the horizontal well drilled in this area are currently on production, and we are currently completing a second vertical well. One vertical well drilled in this area was not commercially successful; however a vertical or horizontal sidetrack is currently being evaluated.

We expect to drill one horizontal sidetrack and one horizontal well in the South Bearhead Creek area in the second half of 2012. We are replacing five wells from our previously disclosed program with a horizontal sidetrack. We anticipate that capital expenditures in our South Bearhead Creek area for the second half of 2012 will be approximately $13 million, or 8% of our total capital expenditure budget for the period, which is a decrease of $10 million expected to be spent in the area under our prior capital expenditure budget.

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During the three months ended June 30, 2012, average production from these properties was 2,266 net Boe/d, a decrease of 821 net Boe/d compared to the three months ended March 31, 2012. The decline in average production was a result of continued severe declines from two of the four wells that produce from our only significant water drive reservoir. These four wells had average daily production of 698 net Boe/d in the three months ended June 30, 2012 compared with average daily production of 1,823 net Boe/d in the three months ended March 31, 2012.

West Gordon

In West Gordon, we drilled two vertical wells during the second quarter of 2012, one of which is currently on production and is producing at type curve expectations. The second well drilled produced below expectations results and is currently being evaluated.

We currently expect to drill two horizontal sidetracks and one horizontal well in the West Gordon area in the second half of 2012. We are replacing one well from our previously disclosed program with the two horizontal sidetracks. We anticipate that capital expenditures in our West Gordon area for the second half of 2012 will be approximately $21 million, or 13% of our capital expenditure budget for the period, which is an increase of $2 million expected to be spent in the area under our prior capital expenditure budget.

During the three months ended June 30, 2012, our average production from these properties was 675 net Boe/d, a decrease of 124 net Boe/d compared to the three months ended March 31, 2012. While average daily production decreased in this area compared to the prior quarter and decline rates in our West Gordon area are higher than anticipated, we believe this is attributable to mechanical issues arising after drilling and completion activities are complete. We continue to evaluate the results from these wells and are currently developing plans to address the mechanical issues.

North Cowards Gully

We did not spud any wells in our North Cowards Gully area during the second quarter of 2012. We plan to drill one horizontal well in the area for the remainder of 2012 which is currently drilling, which is a decrease of one well from our prior drilling program. We anticipate that capital expenditures in our North Cowards Gully area for the second half of 2012 will be approximately $7 million, or 4% of our capital expenditure budget for the period, which is a decrease of $4 million expected to be spent in the area under our prior capital expenditure budget.

During the three months ended June 30, 2012, our average production from these properties was 67 net Boe/d, a decrease of 45 net Boe/d compared to the three months ended March 31, 2012.

Expansion Areas

We spud three wells and one horizontal sidetrack in our expansion areas during the second quarter of 2012. Two of the wells are currently undergoing testing and the third well encountered significant amounts of water. The horizontal sidetrack in the South Fulton area is currently undergoing a workover to clean out sand and shale in the wellbore and we expect to have it back on production during the third quarter. We do not plan to drill any further wells in our expansion areas during the second half of 2012 while we reevaluate our drilling programs in these areas, which is a decrease of 10 wells from our prior drilling plans.

Our expectations with respect to our drilling program for the second half of 2012 do not reflect the Eagle Acquisition and may change as a result of the consummation of that transaction. We do not currently anticipate that we would be able to fund our current drilling program for the second half of 2012 without accessing the capital markets or other external funding sources. In the event that we are unable to access additional funding through debt or equity markets or secure other external sources of funding, we would be required to significantly reduce our capital program for the second half of 2012. See “—Liquidity and Capital Resources.”

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Capital Expenditures

During the three and six months ended June 30, 2012, we incurred capital expenditures of $108.8 million and $206.5 million, respectively, consisting primarily of (in thousands):

	For the Three Months Ended June 30, 2012		For the Six Months Ended June 30, 2012
Drilling and completion activities	$	86,086	$	158,148
Acquisition of acreage and seismic data	14,913		32,524
Facilities and other capital expenditures	7,780		15,874
Total capital expenditures incurred	$	108,779	$	206,546

Through August 1, 2012, we also increased our acreage in the trend to approximately 158,900 total net acres, comprised of approximately 103,900 net leased acres and approximately 55,000 net optioned acres, an increase of 46% in total net acres since December 31, 2011.

Amended and Restated Credit Agreement

On June 8, 2012, we entered into a Second Amended and Restated Credit Agreement among Midstates Petroleum Company LLC, as borrower, us as guarantor, the lenders party thereto and SunTrust Bank, as the new administrative agent (the “Amended Credit Agreement”). The Amended Credit Agreement increased the size of the revolving credit facility from $300 million to $500 million, added additional lenders to the bank group and set the initial borrowing base at $200 million. At the closing of the Amended Credit Agreement, we borrowed $20.0 million under the revolving credit facility. On July 13, 2012, we borrowed an additional $20.0 million pursuant to the terms of the Amended Credit Facility. On August 11, 2012, we entered into a commitment letter relating to an Amendment to the Amended Credit Agreement, subject to certain conditions. Please see “—Liquidity and Capital Resources—Significant Sources of Capital—Reserve-based Credit Facility” for more information.

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 30 for discussion of our hedging and hedge positions.

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

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Results of Operations

Revenues

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

	For the Three Months Ended June 30,										For the Six Months Ended June 30,
	2012					2011					2012					2011
	(in thousands)
REVENUES:
Oil sales	$	48,056		47	%	$	45,994		71	%	$	93,138		70	%	$	81,577		105	%
Natural gas sales	2,379			2	%	4,962			8	%	5,829			4	%	9,035			11	%
Natural gas liquid sales	3,901			4	%	3,171			5	%	10,173			8	%	5,216			7	%
Total oil, natural gas, and natural gas liquids sales	54,336			53	%	54,127			84	%	109,140			82	%	95,828			123	%

Realized gains (losses) on commodity derivative contracts, net	(5,180		)	-5	%	(6,130		)	-9	%	(11,679		)	-9	%	(8,137		)	-10	%
Unrealized gains (losses) on commodity derivative contracts, net	53,323			52	%	16,607			25	%	35,157			27	%	(9,982		)	-13	%
Gains (Losses) on commodity derivative contracts — net	48,143			47	%	10,477			16	%	23,478			18	%	(18,119		)	-23	%

Other	103			0	%	60			0	%	207			0	%	114			0	%

Total revenues	$	102,582		100	%	$	64,664		100	%	$	132,825		100	%	$	77,823		100	%

Production

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2012	2011	% Change		2012	2011	% Change
PRODUCTION DATA:
Oil (MBbls)	447	391	14	%	852	753	13	%
Natural gas (MMcf)	1,047	1,043	0	%	2,369	1,924	23	%
Natural gas liquids (MBbls)	98	70	41	%	225	117	92	%
Oil equivalents (MBoe)	719	635	13	%	1,472	1,190	24	%

Average daily production (Boe/d)	7,904	6,976	13	%	8,090	6,577	23	%

Prices

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012		2011		% Change		2012		2011		% Change
AVERAGE SALES PRICES:
Oil, without realized derivatives (per Bbl)	$	107.56	$	117.48	-8	%	$	109.30	$	108.34	1	%
Oil, with realized derivatives (per Bbl)	$	95.97	$	101.83	-6	%	$	95.59	$	97.53	-2	%
Natural gas (per Mcf)	$	2.27	$	4.76	-52	%	$	2.46	$	4.70	-48	%
Natural gas liquids (per Bbl)	$	39.83	$	45.58	-13	%	$	45.14	$	44.67	1	%

Three Months Ended June 30, 2012 as Compared to the Three Months Ended June 30, 2011

Oil, natural gas and natural gas liquids revenues. Our oil, natural gas and natural gas liquids (“NGL”) sales revenues increased by $0.2 million, or less than 1%, to $54.3 million during the second quarter of 2012 as compared to $54.1 million for the second quarter of 2011. Our revenues are a function of oil, natural gas, and NGL production volumes sold and average sales prices received for those volumes. Of the $0.2 million revenue variance, sales volume increases contributed $7.8 million, offset by unfavorable price variances of $7.6 million. Average daily production sold increased by 928 Boe per day, or 13%, to 7,904 Boe per day during the second quarter of 2012 as compared to 6,976 Boe per day during the second quarter of 2011. The increase in average daily production sold was primarily due to a greater number of producing wells during the 2012 period resulting from our increased drilling activity. Average oil

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sales prices, without realized derivatives, decreased by $9.92 per barrel or 8% to $107.56 per barrel for the second quarter of 2012 as compared to $117.48 per barrel for the second quarter of 2011.

Gains/losses on commodity derivative contracts - net. Net gains (losses) on our mark-to-market (“MTM”) derivative positions increased $37.6 million, or 359%, to a net gain of $48.1 million for the three months ended June 30, 2012 compared to a net gain of $10.5 million for the three months ended June 30, 2011. Our derivative positions moved from an unrealized gain of $16.6 million in the second quarter of 2011 to an unrealized gain of $53.3 million in the second quarter of 2012. The increase in our unrealized gains for the 2012 period were primarily attributable to an increase in volumes covered by derivative instruments and a general decline in oil prices during the 2012 period. The value of our derivative positions move inversely to the price of oil. The realized loss on derivatives for the three months ended June 30, 2012 was $5.2 million compared to a realized loss of $6.1 million for the three months ended June 30, 2011. Realized oil sales prices, with realized derivatives, averaged $95.97 per barrel for the second quarter of 2012 compared to $101.83 per barrel for the same period in 2011.

Six Months Ended June 30, 2012 as Compared to the Six Months Ended June 30, 2011

Oil, natural gas and natural gas liquids revenues. Our oil, natural gas and NGL sales revenues increased by $13.3 million, or 14%, to $109.1 million during the first six months of 2012 as compared to $95.8 million for the first six months of 2011. Our revenues are a function of oil, natural gas, and NGL production volumes sold and average sales prices received for those volumes. Of the $13.3 million revenue variance, sales volume increases contributed $17.7 million of the total, offset by unfavorable price variances of $4.4 million. Average daily production sold increased by 1,513 Boe per day, or 23%, to 8,090 Boe per day during the first six months of 2012 as compared to 6,577 Boe per day during the first six months of 2011. The increase in average daily production sold was primarily due to a greater number of producing wells during the 2012 period resulting from our increased drilling activity. Average oil sales prices, without realized derivatives, increased by $0.96 per barrel or 1% to $109.30 per barrel for the first six months of 2012 as compared to $108.34 per barrel for the first six months of 2011.

Gains/losses on commodity derivative contracts - net. Net gains (losses) on our MTM derivative positions increased $41.6 million, or 229%, to a $23.5 million gain for the six months ended June 30, 2012 compared to a net loss of $18.1 million for the six months ended June 30, 2011. Our derivative positions moved from an unrealized loss of $10.0 million in the six months ended June 30, 2011 to an unrealized gain of $35.2 million in the six months ended June 30, 2012. The increase in our unrealized gain for the 2012 period is primarily attributable to increases in volumes covered by derivative instruments and a general decline in oil prices during the latter part of the 2012 period. The value of our hedging instruments moves inversely to the price of oil. The realized loss on derivatives for the six months ended June 30, 2012 was $11.7 million compared to a realized loss of $8.1 million in the six months ended June 30, 2011. Realized oil sales prices, with realized derivatives, averaged $95.59 per barrel for the first six months of 2012 compared to $97.53 per barrel for the same period in 2011.

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.

	For the Three Months Ended June 30,								For the Six Months Ended June 30,
	2012		2011		2012		2011		2012		2011		2012		2011
	(in thousands)				(per Boe)				(in thousands)				(per Boe)
EXPENSES:
Lease operating and workover	$	5,921	$	3,669	$	8.24	$	5.78	$	12,388	$	6,275	$	8.42	$	5.27
Severance and other taxes	6,272		5,370		$	8.72	$	8.46	11,648		9,495		$	7.91	$	7.98
Asset retirement accretion	164		39		$	0.23	$	0.06	298		86		$	0.20	$	0.07
Depreciation, depletion, and amortization	27,882		21,266		$	38.78	$	33.49	55,909		39,884		$	37.98	$	33.52
General and administrative	4,956		10,641		$	6.89	$	16.76	11,019		14,544		$	7.49	$	12.22

Total expenses	$	45,195	$	40,985	$	62.86	$	64.55	$	91,262	$	70,284	$	62.00	$	59.06

Three Months Ended June 30, 2012 as Compared to the Three Months Ended June 30, 2011

Lease operating and workover expenses. Lease operating and workover expenses increased $2.2 million, or 59%, to $5.9 million for the second quarter of 2012 compared to $3.7 million for the second quarter of 2011. Lease operating expenses increased $1.9 million, or 58%, to $5.2 million for the second quarter of 2012 as compared to $3.3 million for the second quarter of 2011. This increase was due to higher surface maintenance costs of $0.6 million due to increased road and lease maintenance, higher saltwater disposal costs of $0.5 million primarily attributable to central fault block wells in our South Bearhead Creek/Oretta operating area, and additional costs

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of $0.7 million, related to compression, well work charges and labor related costs, due to a greater number of producing wells period over period. Workover expenses increased $0.3 million, or 75%, to $0.7 million for the second quarter of 2012 as compared to $0.4 million for the second quarter of 2011. We completed ten workovers in the second quarter of 2012, which was an increase of four projects over the six workovers completed in the second quarter of 2011. Lease operating and workover expenses increased to $8.24 per Boe for the quarter ended June 30, 2012 from $5.78 per Boe for the quarter ended June 30, 2011, an increase of 43%, which was primarily attributable to the factors discussed above.

Severance and other taxes. Severance and other taxes increased $0.9 million, or 17%, to $6.3 million for the second quarter of 2012 compared to $5.4 million for the second quarter of 2011. Severance taxes increased $0.4 million, or 8%, to $5.5 million for the second quarter of 2012 as compared to $5.1 million for the second quarter of 2011. This increase was primarily attributable to slightly higher oil, natural gas and NGL sales revenue during the second quarter of 2012. Our severance taxes as a percentage of oil, natural gas and NGL sales revenue were 10.1% for the second quarter of 2012, compared to 9.5% in the second quarter of 2011. Ad valorem taxes increased $0.6 million, or 300%, to $0.8 million for the second quarter of 2012 as compared to $0.2 million for the second quarter of 2011, corresponding to a related increase in producing wells.

Depreciation, depletion and amortization (DD&A). DD&A expense increased $ 6.6 million, or 31%, to $27.9 million for the second quarter of 2012 compared to $21.3 million for the second quarter of 2011. The DD&A rate for second quarter of 2012 was $38.78 per Boe compared to $33.49 per Boe for the second quarter of 2011. The increase in the DD&A rate per Boe versus the comparable 2011 period is primarily attributable to wells spud during the 2012 period on drilling locations that have probable and possible reserve classifications. We drill these wells to extend our proved reserves within the play. The impact on the DD&A rate is directly related to the timing of our evaluation of the well results and our ability to assign proved reserves to those wells.

General and administrative. Our general and administrative expenses (“G&A”) decreased by $5.6 million, or 53%, to $5.0 million for the second quarter of 2012 compared to $10.6 million for the second quarter of 2011. The overall decrease is driven by a reduction in equity-based compensation expense of $6.6 million; in the second quarter of 2012, the Company recorded $0.7 million in share-based compensation related to restricted stock awards granted during the quarter compared to $7.3 million recorded in the second quarter 2011. This decrease was partially offset by an increase over the same periods of $1.1 million in other employee related costs, including salary and insurance, which relates to an overall increase in headcount from 48 full time employees during three months ended June 30, 2011 to 86 full time employees during the three months ended June 30, 2012.

Six Months Ended June 30, 2012 as Compared to the Six Months Ended June 30, 2011

Lease operating and workover expenses. Lease operating and workover expenses increased $6.1 million, or 97%, to $12.4 million for the six months ended June 30, 2012 compared to $6.3 million for the six months ended June 30, 2011. Lease operating expenses increased $5.2 million, or 93%, to $10.8 million for the six months ended June 30, 2012 as compared to $5.6 million for the six months ended June 30, 2011. This increase was due to higher surface maintenance costs of $1.2 million due to increased road and lease maintenance, higher saltwater disposal of $1.4 million primarily attributable to central fault block wells in our South Bearhead Creek/Oretta operating area, and additional costs of $2.0 million, related to compression, well work charges and labor related costs due to a greater number of producing wells period over period. Workover expenses increased $0.8 million, or 114%, to $1.5 million for the six months ended June 30, 2012 as compared to $0.7 million for the six months ended June 30, 2011. We completed 19 workovers in the six months ended June 30, 2012, which was an increase of ten projects over the nine workovers completed in the six months ended June 30, 2011. Lease operating and workover expenses increased to $8.42 per Boe for the six months ended June 30, 2012 from $5.27 per Boe for the six months ended June 30, 2011, an increase of 60%, which was primarily a result of the incurrence of lease operating and workover costs during 2012 at a higher rate than the overall increase in production during the period.

Severance and other taxes. Severance and other taxes increased $2.1 million, or 23%, to $11.6 million for the six months ended June 30, 2012 compared to $9.5 million for the six months ended June 30, 2011. Severance taxes increased $0.9 million, or 10%, to $10.0 million for the six months ended June 30, 2012 as compared to $9.1 million for the six months ended June 30, 2011. This increase was primarily attributable to higher oil, natural gas and NGL sales revenue during the six months ended June 30, 2012. Our severance taxes as a percentage of oil, natural gas and NGL sales revenue were 9.1% for the six months ended June 30, 2012, compared to 9.5% in the six months ended June 30, 2011. Ad valorem taxes increased $1.3 million, or 325%, to $1.7 million for the six months ended June 30, 2012 as compared to $0.4 million for the six months ended June 30, 2011, corresponding primarily to a related increase in producing wells.

Depreciation, depletion and amortization (DD&A). DD&A expense increased $16.0 million, or 40%, to $55.9 million for the six months ended June 30, 2012 compared to $39.9 million for the six months ended June 30, 2011. The DD&A rate for the six months ended June 30, 2012 was $37.97 per Boe compared to $33.52 per Boe for the six months ended June 30, 2011. The increase in DD&A

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expense for the six months ended June 30, 2012 was primarily due to higher production volumes during the 2012 period, as well as capital expenditures incurred during the 2012 period, without a corresponding proportionate increase in the total proved reserve base.

General and administrative. Our G&A expenses decreased by $3.5 million, or 24%, to $11.0 million for the six months ended June 30, 2012 compared to $14.5 million for the six months ended June 30, 2011. Primarily driving the decrease is a reduction in share-based compensation of $7.3 million, as $0.7 million was recorded during the six months ended June 30, 2012 compared to $7.9 million recorded during the six months ended June 30, 2011. This decrease was partially offset by the other components of general and administrative expenses, which increased primarily due to the overall growth in the company and headcount between June 30, 2011 and June 30, 2012. As of June 30, 2012, we had 86 full time employees compared to 48 employees as of June 30, 2011. The 79% increase in headcount resulted in a $2.3 million increase in employee-related costs to $5.5 million for the six months ended June 30, 2012, compared to $3.2 million for the six months ended June 30, 2011. Rent expense increased $0.4 million, or 133%, to $0.7 million for the six months ended June 30, 2012 compared to $0.3 million for the six months ended June 30, 2011, as the Company requires more workspace to accommodate the increase in headcount. Professional expenses increased $0.8 million, or 50%, to $1.6 million for the six months ended June 30, 2012 compared to $0.8 million for the six months June 30, 2011 primarily due to expenses associate with becoming a public company.

Other Income (Expenses)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)						(in thousands)
OTHER INCOME (EXPENSE)
Interest income	$	143		$	4		$	150		$	12

Interest expense	(2,701		)	(856		)	(5,064		)	(1,460		)
Capitalized Interest	1,711			722			2,384			1,326
Interest expense — net of amounts capitalized	$	(990	)	$	(134	)	$	(2,680	)	$	(134	)

Total other income (expense)	$	(847	)	$	(130	)	$	(2,530	)	$	(122	)

Three Months Ended June 30, 2012 as Compared to the Three Months Ended June 30, 2011

Interest expense. Interest expense for the three months ended June 30, 2012 and for the three months ended June 30, 2011 was $2.7 million and $0.9 million, respectively. The increase in interest expense was primarily due to the higher average outstanding balances under our revolving credit facility during the 2012 period. Our average outstanding balance was $163.7 million during the 2012 period, versus $116.2 million for the 2011 period, and related to $1.0 million of the total interest expense of $2.7 million. The remainder of the interest expense for the three months ended June 30, 2012, $1.7 million, is attributable to interest expense of $1.5 million associated with our Preferred Units, which were redeemed in April 2012, and amortization of deferred loan costs of $0.2 million. Of total interest expense, $1.7 million and $0.7 million was capitalized, resulting in $1.0 million and $0.1 million in interest expense for the three months ended June 30, 2012 and June 30, 2011, respectively.

Six Months Ended June 30, 2012 as Compared to the Six Months Ended June 30, 2011

Interest expense. Interest expense for the six months ended June 30, 2012 and for the six months ended June 30, 2011 was $5.1 million and $1.5 million, respectively. The increase in interest expense was primarily due to the higher average outstanding balances under our revolving credit facility during the 2012 period. Our average outstanding balance was $199.2 million during the 2012 period, versus $107.3 million for the 2011 period, and related to $2.8 million of the total interest expense of $5.1 million. The remainder of the interest expense for the six months ended June 30, 2012, $2.3 million, related to interest expense of $2.1 million associated with our Preferred Units, which were redeemed in April 2012, and amortization of deferred loan costs of $0.2 million. Of total interest expense, $2.4 million and $1.3 million was capitalized, resulting in $2.7 million and $0.1 million in interest expense for the six months ended June 30, 2012 and June 30, 2011, respectively.

Provision for Income Taxes

Three and Six Months Ended June 30, 2012 as Compared to the Three and Six Months Ended June 30, 2011

Income tax expense was $168.9 million during the three and six months ended June 30, 2012. We were not a tax paying entity during the 2011 corresponding periods and therefore, no income tax expense was recorded. With the consummation of our corporate reorganization (“Reorganization”) in connection with our initial public offering completed on April 25, 2012, we became a tax paying entity and as such, were required to record a charge against income equal to the estimated tax effect of the excess of the book carrying value of our net assets (primarily producing oil and gas properties) over their collective estimated tax bases as of the Reorganization

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date. As a result, during the three and six months ended June 30, 2012, we recorded a tax charge of $149.5 million associated with the Reorganization.

During the three and six months ended June 30, 2012, we also recorded $19.4 million of income tax expense. This represents an application of our estimated effective tax rate (including state income taxes) for the three and six months ended June 30, 2012 of 34.4% and 49.7%, respectively, to our income earned from the Reorganization date through the quarter end.

Liquidity and Capital Resources

Recent Developments Impacting our Liquidity

Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital. In the event that the Eagle Acquisition closes during the third quarter of 2012, we anticipate that the financing activities undertaken in connection with the Eagle Acquisition, our available cash, execution of our planned drilling program, anticipated future cash flows from operations and borrowings under our revolving credit facility will be sufficient to meet our operating needs through 2013. In the event that we are unable to access additional funding through debt or equity markets or secure other external sources of funding, we would be required to significantly reduce our capital program for the second half of 2012. If we reduce our future planned exploration and development expenditures, we believe that those steps, together with our available cash, anticipated future cash flows from operations and borrowings under our revolving credit facility will be sufficient to meet our reduced expenditures and operating needs through 2013.

Commitment Letter for Bridge Credit Facility and Amendment to Revolver

As part of the Eagle Acquisition, we will be required to provide $325 million of cash consideration, subject to adjustment as provided in the purchase agreement, and pay transaction costs and expenses, including advisors’ fees.

In connection with the execution of the purchase agreement for the Eagle Acquisition, on August 11, 2012, the Company and Midstates Sub entered into a commitment letter with (after giving effect to certain subsequent joinders) Bank of America, N.A., Merrill Lynch, Pierce Fenner & Smith Incorporated, SunTrust Bank and SunTrust Robinson Humphrey, Inc., Goldman Sachs Lending Partners LLC and Morgan Stanley Senior Funding, Inc. to, among other things, (A) provide for an unsecured bridge credit facility in the amount of up to $500 million and (B) provide a commitment to amend the existing secured revolving credit facility to increase the borrowing base to $250 million and to accommodate, among other things, the issuance, incurrence and/or compliance with the terms of the Preferred Stock, bridge loans and other debt securities that may be issued or loans that may be incurred in lieu of, or in connection with the replacement of the bridge loans, including senior unsecured notes. The availability of loans under the bridge credit facility and the effectiveness of the amended revolving credit facility are subject to the consummation of the Eagle Acquisition and other customary conditions. The proceeds of the bridge credit facility may be used solely to fund the Eagle Acquisition, to pay transaction costs and expenses in connection therewith or repay existing outstanding debt under the existing revolving credit facility. If entered into, the bridge credit facility will initially bear interest at LIBOR, subject to a 1.50% floor, plus 9.0% and thereafter such 9.0% margin is subject to increases. The bridge credit facility matures on the first anniversary of the closing date of the Eagle Acquisition and contains customary terms regarding the conversion of the bridge loans into other debt instruments subject to certain caps on yield, the highest of which is set at 13.25%. The obligations under the bridge credit facility would be guaranteed by the same entities that guaranty the existing secured revolving credit facility. If entered into, the amended revolving credit facility would mature on the fifth anniversary of the entrance into the facility and the aggregate amount available under the credit facility would increase to $250 million, subject to reduction in the event that the amount of assets acquired in connection with the Eagle Acquisition is less than expected. The definitive loan documentation for the bridge loan facility will contain representations and warranties, affirmative, negative and financial covenants and events of default similar to those in other similar transactions and will otherwise be similar to the terms set forth in the existing secured revolving credit facility. The definitive loan documentation for the amended revolving credit facility will contain representations and warranties, affirmative, negative and financial covenants and events of default similar to the terms set forth in the existing secured revolving credit facility and which address the above mentioned accommodations.

In addition, on August 11, 2012, the Company and Midstates Sub entered into a second commitment letter with SunTrust Bank, SunTrust Robinson Humphrey, Inc., Bank of America N.A. and Merrill Lynch, Pierce Fenner & Smith Incorporated to underwrite an amendment to the existing secured revolving facility which provides for $35 million of non-conforming borrowing base loans (thereby increasing the borrowing base under the existing secured revolving credit facility from $200 million to $235 million) and waives the requirement to comply with the minimum current ratio financial covenant for the quarters ending September 30, 2012 and December 31, 2012. This amendment is not dependent upon the consummation of the Eagle Acquisition. The availability of non-conforming borrowing base loans will end upon the earliest to occur of (i) the closing of the Eagle Acquisition, (ii) the issuance of certain unsecured indebtedness permitted under the existing secured revolving credit facility and (iii) the scheduled March 2013 borrowing base redetermination. Thereafter, subject to the other commitments contemplated by the other commitment letter discussed above, the borrowing base would reduce to $200 million and loans would be permitted subject to the $200 million borrowing base. Borrowings under the terms of the amended revolving credit facility would bear interest at the same rates applicable to the existing secured revolving credit facility, provided that if borrowing base usage exceeded $200 million the amount of applicable margin would increase to up to 3.00% in the case of base rate loans and 4.00% in the case of LIBOR loans. Similarly, commitment fees would be the same rates applicable to the existing secured revolving credit facility subject to an increase up to 0.625% if borrowing base usage exceeded $200 million. In addition, it would increase the allowance for the incurrence of certain unsecured indebtedness, without a corresponding reduction in the borrowing base, from $275 million to $500 million thereby permitting the incurrence of the bridge loans or the issuance of other debt without causing a $0.25 reduction in the borrowing base for every $1 of debt incurred or issued above $275 million. The definitive loan documentation for this amended revolving credit facility will be effective upon the satisfaction of customary conditions and contain representations and warranties, affirmative, negative and financial covenants and events of default substantially the same as the terms set forth in the existing secured revolving credit facility.

Significant Sources of Capital

Reserve-based Credit Facility

The Amended Credit Agreement increased the size of the revolving credit facility from $300 million to $500 million, added additional lenders to the bank group and set the initial borrowing base at $200 million. In addition, the lenders under the Amended Credit Agreement have agreed that there will be no reduction in our borrowing base under the Amended Credit Agreement for the issuance of up to $275 million of senior unsecured notes. In the event that we elect to issue senior unsecured notes in excess of $275 million, the borrowing base will be reduced by 25% of the face value (without giving effect to any original issue discount) of such notes in excess of $275 million. The Amended Credit Agreement also extended the maturity date of the revolving credit facility from December 10, 2014 to June 8, 2017. At the closing of the Amended Credit Agreement, we borrowed $20.0 million under the revolving credit facility.

Borrowings under the Amended Credit Agreement continue to be secured by substantially all of our oil and natural gas properties and currently bear interest at LIBOR plus an applicable margin between 1.75% and 2.75% per annum. At June 30, 2012 and December 31, 2011, the weighted-average interest rate was 2.9% and 3.2%, respectively. In addition to interest expense, the Amended Credit Agreement 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 Amended Credit Agreement is subject to redeterminations in March and September, 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 Amended Credit Facility, we are required to repay the amount by which the principal balance of our outstanding loans and our letter of credit obligations exceed our 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 to us regarding such borrowing base reduction.

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The Amended Credit Agreement contains financial covenants, which, among other things, set a maximum ratio of debt to earnings before interest, income tax, depletion, depreciation, and amortization (EBITDA) of not more than 4.00 to 1, a minimum current ratio (as defined therein) of not less than 1.0 to 1.0 and various other standard affirmative and negative covenants including, but not limited to, restrictions on our ability to make any dividends, distributions or redemptions. As of June 30, 2012, we are in compliance with the financial debt covenants set forth in the Amended Credit Agreement.

Prior to the amendment, our credit facility consisted of a $300 million senior revolving credit facility with a borrowing base, as redetermined in March 2012, of $210 million. The maturity date was December 10, 2014 and borrowings were secured by substantially all of our oil and natural gas properties. Borrowings under the facility bore interest at LIBOR plus an applicable margin between 2.00% and 2.75% per annum. In April 2012, we repaid $103.2 million of the outstanding balance.

As described under our “— Recent Developments Impacting our Liquidity,” on August 11, 2012, we entered into a commitment letter to, among other things, provide for an amendment to our Amended Credit Facility which will increase the aggregate amount available under the Amended Credit Facility to $235 million. This amendment is not dependent upon the consummation of the Eagle Acquisition. In addition, we received a waiver of the requirement under the revolving credit facility that we maintain a current ratio, consisting of consolidated current assets, including the unused amount of the total commitments and any letters of credit issued for the benefit of the lenders, to consolidated current liabilities, of not less than 1.0 to 1.0, excluding non-cash derivative assets and liabilities, as of the last day of any fiscal quarter. This waiver is in effect for the third quarter and fourth quarter of 2012.

Mandatorily Redeemable Convertible Preferred Units

In December 2011, Midstates Petroleum Holdings LLC (“Holdings LLC”), FR Midstates Holdings LLC (“FR Midstates”) and Midstates Petroleum Holdings, Inc. (“Petroleum Inc.”) entered into an amended and restated limited liability company agreement, which was later amended in March 2012, to provide for the issuance of up to 65,000, or $65 million in aggregate value, of certain mandatorily redeemable convertible preferred units (the “Preferred Units”) between December 15, 2011 and June 10, 2015. The Preferred Units had a liquidation value of $1,000 per unit and bore interest, compounded quarterly, at a rate of 8% plus the greater of LIBOR or 1.5%. The Preferred Units were convertible into units of Holdings LLC on or after the one year anniversary of the date of issuance into a number of common units with a fair market value (as determined by the Board) equal to the liquidation value plus any accrued interest and were redeemable for cash at any time at the option of Holdings LLC, but were mandatorily redeemable for cash on June 10, 2015, unless otherwise converted. In addition, a fixed interest charge of 1.5% of the aggregate capital invested in the Preferred Units was payable upon redemption or conversion.

On April 26, 2012, we used $67.1 of the proceeds from our initial public offering to redeem the Preferred Units in full, including interest and other charges. Accordingly, there are no Preferred Units outstanding as of June 30, 2012. We recorded $0.8 million related to interest expense associated with these Preferred Units for the six months ended June 30, 2012.

Initial Public Offering

On April 25, 2012, we completed our initial public offering. Our estimated net proceeds from the sale of 18,000,000 of our common shares in the initial public offering, after underwriting discounts and commissions, was $220.0 million (or $213.8 million after offering expenses paid directly by us). Of the net proceeds, $67.1 million was used to redeem the Preferred Units, including interest and other charges, and $99.0 million was used to repay a portion of our borrowings under the Revolving Credit Facility. The remaining proceeds were retained to fund the execution of our growth strategy through our drilling program.

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 (dollars in thousands). 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.

	For the Six Months Ended June 30,
	2012			2011
Net cash provided by operating activities	$	59,963		$	66,984
Net cash used in investing activities	(184,245		)	(102,302		)
Net cash provided by financing activities	128,627			33,856

Net change in cash	$	4,345		$	(1,462	)

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

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the impact of changing prices on our financial position, see “Item 3. — Quantitative and Qualitative Disclosures About Market Risk” beginning on page 30.

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

Cash flows provided by operating activities.

Net cash provided by operating activities was $60.0 million and $67.0 million for the six months ended June 30, 2012 and June 30, 2011, respectively. The decrease in net cash provided by operating activities was primarily the result of a decrease in realized oil, natural gas and NGL prices offset by a slight increase in production and favorable working capital changes in the 2012 period as compared to the same period of 2011.

Cash flows used in investing activities

We had net cash used in investing activities of $184.2 million and $102.3 million during the six months ended June 30, 2012 and June 30, 2011, respectively, as a result of our capital expenditures for drilling, development and acquisition costs. The increase in net cash used in investing activities during first six months of 2012 compared to first six months of 2011 is attributable to continued expansion of our drilling programs, and acreage position, as well as growth of our business.

Capital Expenditures

Through June 30, 2012, approximately $206.5 million of our 2012 capital expenditure budget had been incurred.

While, the ultimate amount of capital we will expend may fluctuate materially, we do not currently anticipate that we would be able to fund our current drilling program for the second half of 2012 without accessing the capital markets or other external funding sources. In the event that we are unable to access additional funding through debt or equity markets or secure other external sources of funding, we would be required to significantly reduce our capital program for the second half of 2012.

Cash flows provided by financing activities

Net cash provided by financing activities was $128.6 million and $33.9 million for the six months ended June 30, 2012 and June 30, 2011, respectively. For these periods, cash sourced through financing activities was provided primarily by proceeds from the completion of our initial public offering (April 2012) and borrowings under our revolving credit facilities. Our outstanding amounts under the Revolving Credit Facility at June 30, 2012 and June 30, 2011 were $151.7 million and $146.6 million, respectively. During the 2012 period, we completed our initial public offering which resulted in net proceeds of $213.8 million, of which $99.0 million was used to repay a portion of our Revolving Credit Facility and $65.0 million was used to redeem the Preferred Units held by an affiliate of First Reserve.

Critical Accounting Policies and Estimates

A discussion of our critical accounting policies and estimates is included in Midstates Petroleum Company, Inc.’s Registration Statement on Form S-1, as amended (Registration No. 333-177966). There have been no material changes to those policies.

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

Other Items

Contractual Obligations

The following table summarizes our contractual obligations as of June 30, 2012 (in thousands):

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	Payments due by Period (1)
	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Revolving credit facility	$	151,700	—		151,700		—		—
Drilling contracts (2)	$	6,150	6,150		—		—		—
Operating leases (2)	$	8,436	634		2,857		2,939		2,006
Seismic contracts (2)	$	8,824	8,324		500		—		—
Asset retirement obligations (3)	$	9,398	—		—		—		9,398
Other (2)	$	1,110	1,110		—		—		—
Total contractual obligations	$	185,618	$	16,218	$	155,057	$	2,939	$	11,404

(1) Less than 1 year represents amounts for the remainder of 2012 (July 1 through December 31), 1-3 years represents amounts for 2013 and 2014, 3-5 years represents amounts for 2015 and 2016, and more than 5 years represents amounts after 2016.

(2) See Note 12 in the Notes to the Unaudited Condensed Consolidated Financial Statements for a description of operating lease, drilling contract, seismic contract and other contract obligations.

(3) Amounts represent our estimate of future asset retirement obligations on an undiscounted 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 environment. See Note 5 in the Notes to the Unaudited Condensed Consolidated Financial Statements.

Off-Balance Sheet Arrangements

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

Related Party Transactions

With respect to related party transactions, see Note 11 in the Notes to the Unaudited Condensed Consolidated Financial Statements.

Recent Accounting Pronouncements

The Company reviewed recently issued accounting pronouncements that became effective during the three months ended June 30, 2012, and determined that none would have a material impact on our condensed consolidated financial statements.

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, 2012, we utilized fixed price swaps, collars, deferred-premium puts and basis differential swaps to reduce the volatility of oil prices on a portion of our future expected oil production.

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

The following is a summary of our commodity derivative contracts as of June 30, 2012:

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	Hedged Volume	Weighted-Average Fixed Price

Oil (Bbls):
WTI Swaps — 2012	411,100	$		84.36
WTI Swaps — 2013	679,125	84.73
WTI Swaps — 2014	262,450	83.00

WTI Collars — 2012	82,800	$	85.00 - 127.28

WTI Deferred Premium Puts — 2012 (1)	276,000	$		79.01

WTI Basis Differential Swaps — 2012 (2)	505,300	$		9.73
WTI Basis Differential Swaps — 2013 (2)	679,125	6.30

LLS Swaps - 2012	315,180	$		116.55

Brent Swaps - 2013	1,021,749	$		111.89

	Six Months Ended June 30, 2012
	(in thousands)
Derivative fair value at period end - asset (included in the balance sheet)	$	17,925

Realized net (loss) (included in the statement of operations)	$	(11,679	)

Unrealized net gain (included in the statement of operations)	$	35,157

At June 30, 2012 and December 31, 2011, all of our commodity derivative contracts were with three and two bank counterparties, respectively. Our policy is to net derivative liabilities and assets where there is a legally enforceable master netting agreement with the counterparty.

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	Hedged Volume	Weighted-Average Fixed Price

Oil (Bbls):
Swaps — 2012	644,130	$		95.75
Swaps — 2013	1,700,874	95.55
Swaps — 2014	262,450	83.00

Collars — 2012	68,850	$	85.00 - 127.28

Deferred Premium Puts — 2012 (1)	229,500	$		79.01

Basis Differential Swaps — 2012 (2)	789,480	$		9.81
Basis Differential Swaps — 2013 (2)	1,700,874	$		5.91

Interest Rate Risk. At June 30, 2012, we had indebtedness outstanding under our credit facility of $151.7 million, which bore interest at floating rates. The average annual interest rate incurred on this indebtedness for the three months ended June 30, 2012 and June 30, 2011 was approximately 2.5% and 3.0%, respectively. The average annual interest rate incurred on this indebtedness for the six months ended June 30, 2012 and June 30, 2011 was approximately 2.9% and 2.8%, respectively. A 1.0% increase in each of the average LIBOR and federal funds rate for the three months ended June 30, 2012 and three months ended June 30, 2011 would have resulted in an estimated $0.4 million and $0.3 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, 2012 and six months ended June 30, 2011 would have resulted in an estimated $1.0 million and $0.5 million, respectively, increase in interest expense, of which a portion may be capitalized.

We may utilize interest rate derivatives to mitigate our exposure to change in interest rates. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

Item 4. — Controls and Procedures

Evaluation of Disclosure Controls and Procedures

During the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer, 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 President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. Based upon that evaluation, our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer concluded that our disclosure controls and procedures at June 30, 2012 are effective.

Changes in Internal Control over Financial Reporting

Prior to the completion of our initial public offering, we were a private company with limited accounting personnel to adequately execute our accounting processes and limited other supervisory resources with which to address our internal control over financial reporting. The lack of adequate staffing levels resulted in insufficient time spent on review and approval of certain information used to prepare our financial statements. Our independent registered accounting firm and we concluded that these control deficiencies represented a material weakness in internal control over financial reporting as of December 31, 2011.

During the six months ended June 30, 2012, we have continued to address the causes of this material weakness by putting into place new accounting processes and control procedures, including implementation of disclosure checklists and other reporting tools. In addition, since December 31, 2011, we have added six experienced accounting personnel in response to our identification of gaps in our skills base and expertise of the staff required to meet the financial reporting requirements of a public company. We believe that these corrective actions have improved our internal controls over financial reporting and remediated the material weakness identified at December 31, 2011.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings

See Part I, Item 1, Note 12 to our unaudited condensed consolidated financial statements entitled “Commitments and Contingencies,” 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.

The following risks are provided to supplement the Risk Factors that appear in MPCI’s prospectus dated April 19, 2012 and filed with the SEC pursuant to Rule 424(b) on April 20, 2012, and in our quarterly report on Form 10-Q for the quarter ended March 31, 2012.

We are subject to risks in connection with acquisitions, including the Eagle Acquisition, and the integration of significant acquisitions may be difficult.

We have entered into a purchase agreement for the Eagle Acquisition. Although it is expected to close on or about October 1, 2012, it may not close as expected and we may not incur the expected benefits therefrom. In addition, we will continue to evaluate other acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of substantially all the assets of Eagle or other producing properties requires an assessment of several factors, including:

· recoverable reserves;

· future oil and natural gas prices and their appropriate differentials;

· development and operating costs;

· potential for future drilling and production;

· validity of the seller’s title to the properties, which may be less than expected at the time of signing the purchase agreement; and

· potential environmental issues, litigation and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. Indemnification from Eagle will generally be limited to an escrow account equal to 20% of the Preferred Stock issued as consideration, effective only during the 12-month period after the closing and subject to certain dollar limitations and minimums.

Significant acquisitions and other strategic transactions may involve other risks, including:

· diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

· the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of our operations while carrying on our ongoing business;

· difficulty associated with coordinating geographically separate organizations;

· an inability to secure, on acceptable terms, sufficient financing that may be required in connection with expanded operations and unknown liabilities; and

· the challenge of attracting and retaining personnel associated with acquired operations.

The process of integrating operations, including Eagle’s operations, could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

In addition, even if we successfully integrate Eagle’s operations or another acquisition, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices in oil and natural gas industry conditions, risks and uncertainties relating to the exploratory prospects of the combined assets or operations, failure to retain key personnel, an increase in operating or other costs or other difficulties. We may experience additional challenges integrating the business of a privately operated company, like Eagle. If we fail to realize the benefits we anticipate from an acquisition, our results of operations and stock price may be adversely affected.

As a consequence of the proposed Eagle Acquisition, we will incur substantial additional indebtedness and may materially reduce our cash balance.

Pursuant to the terms of the purchase agreement, the total cash consideration to be paid by the Company for the Eagle Acquisition is $325 million, subject to customary adjustments to reflect the economic effective date of June 1, 2012 and claims for title and environmental defects. We will also incur material costs and expenses in connection with the consummation and integration of the Eagle Acquisition. Specifically, in connection with Eagle Acquisition, we expect to incur an additional $500

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million of indebtedness. Upon the completion of the Eagle Acquisition and after giving effect to our increased borrowing base under our revolving credit facility, we expect to have $500 of debt outstanding and a borrowing base of $250 million under our revolving credit facility, $210 million of which we expect to be available for future borrowings. We have entered into a 364-day bridge term loan facility to provide debt financing for the transaction, subject to customary conditions. We expect to consider opportunities to replace that facility either before or after the closing of the acquisition, which could include replacing that debt financing through an offering in the debt capital markets. However, we may not be able to replace or refinance the bridge facility in a timely manner, or at all. In such event, our potential lower cash balance and increased indebtedness resulting from the proposed acquisition financing could adversely affect our business. In particular, it could increase our vulnerability to sustained, adverse macroeconomic weakness, limit our ability to obtain further financing and limit our ability to pursue certain operational and strategic opportunities. In addition, the covenants contained in the agreements governing our outstanding indebtedness will limit, among other things, our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments and any indenture for high yield debt securities may impose more stringent covenants than our existing credit agreement. For more information about the risks the Company may face as a result of our level of indebtedness, please read “Risk Factors - Our level of indebtedness may increase and reduce our financial flexibility.” in our prospectus dated April 19, 2012 and filed with the SEC pursuant to Rule 424(b) on April 20, 2012.

An unfavorable resolution of the Clovelly litigation could have a material adverse effect on our business, financial condition, results of operations and cash flows.

In May 2009, Clovelly Oil Company, or Clovelly, filed a lawsuit against us in the 13th Judicial District Court in Louisiana. Clovelly alleges that we are subject to an unrecorded Joint Operating Agreement dated July 16, 1972 (the “JOA”), as a result of our 2007 purchase of a 43.75% working interest in certain acreage, and accordingly, that it is entitled to 56.25% of the leases affected by the litigation. Approximately 2.0 MMBOE of our 26.2 MMBOE of total proved reserves as of December 31, 2011 are attributable to properties that would therefore potentially be subject to Clovelly’s interest and we intend to continue to develop these reserves as part of our 2012 drilling program. We cannot predict the outcome of the Clovelly lawsuit or the amount of time and expense that will be required to resolve the lawsuit. An unfavorable resolution of such litigation could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, such litigation could divert the attention of management and resources in general from day-to-day operations.

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

None.

Item 3. Defaults upon Senior Securities

None.

Item 4. Mine Safety Disclosures

None.

Item 5. Other Information

On August 11, 2012, in connection with the execution of the purchase agreement for the Eagle Acquisition, FR Midstates Interholding, LP, which owns 27,147,651 shares of our common stock, and certain members of management, who collectively own 8,973,895 shares of our common stock, executed and delivered to Midstates a written consent in lieu of a stockholders’ meeting. The written consent authorized and approved the issuance of the Preferred Stock to be issued in the Eagle Acquisition and the common stock to be issued upon the conversion of the Preferred Stock. Because these stockholders approved these matters by the execution of the written consent in accordance with Delaware law and Midstates’ certificate of incorporation and bylaws, Midstates does not intend to solicit proxies from, or hold a meeting of, stockholders to approve such matters. Midstates intends to file with the SEC and mail to all stockholders an information statement relating to the issuance of the Preferred Stock.

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 14, 2012		/s/ John A. Crum
		John A. Crum
		Chief Executive Officer and President

Dated: August 14, 2012		/s/ Thomas L. Mitchell
		Thomas L. Mitchell
		Executive Vice President and Chief Financial Officer

Dated: August 14, 2012		/s/ Nelson M. Haight
		Nelson M. Haight
		Vice President and Controller

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EXHIBIT INDEX

Exhibit Number		Exhibit Description
2.1		Master Reorganization Agreement (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)
3.1		Amended and Restated Certificate of Incorporation (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		Amended and Restated Bylaws (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)
4.1		Specimen Stock Certificate (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-1/A filed on February 29, 2012, and incorporated herein by reference)
10.1		Stockholders’ Agreement among Midstates Petroleum Company, Inc. and certain equity owners (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 25, 2012, and incorporated herein by reference)
10.2		Executive Employment Agreement - John A. Crum (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 30, 2012, and incorporated herein by reference)
10.3		Executive Employment Agreement - Thomas L. Mitchell (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on April 30, 2012, and incorporated herein by reference)
10.4		Executive Employment Agreement - Stephen C. Pugh (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on April 30, 2012, and incorporated herein by reference)
10.5		Executive Employment Agreement - John P. Foley (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on April 30, 2012, and incorporated herein by reference)
10.6		2012 Long Term Incentive Plan (filed as Exhibit 4.3 to the Company’s Current Report on Form 8-K filed on April 20, 2012, and incorporated herein by reference)
10.7		Form of Restricted Stock Agreement (Time Vesting) (filed as Exhibit 10.10 to the Company’s Registration Statement on Form S-1/A filed on January 20, 2012, and incorporated herein by reference)
10.8		Form of Notice of Restricted Stock Agreement (Time Vesting) (filed as Exhibit 10.11 to the Company’s Registration Statement on Form S-1/A filed on January 20, 2012 and incorporated herein by reference).
10.9		Form of Indemnification Agreement between Midstates Petroleum Company, Inc. and each of the directors and executive officers thereof (filed as Exhibit 10.12 to the Company’s Registration Statement on Form S-1/A filed on February 16, 2012, and incorporated herein by reference)
10.10		Second Amended and Restated Credit Agreement, dated as of June 8, 2012, among Midstates Petroleum Company, Inc., Midstates Petroleum LLC, SunTrust Bank as administrative agent and other lender parties thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 13, 012, and incorporated herein by reference)
31.1*		Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
31.2*		Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
32.1**		Certification of the Chief Executive Officer and Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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