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 September 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 November 5, 2012 is shown below:

Class		Number of shares outstanding
Common stock, $0.01 par value		66,605,396

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MIDSTATES PETROLEUM COMPANY, INC.

QUARTERLY REPORT ON

FORM 10-Q

FOR THE NINE MONTHS ENDED SEPTEMBER 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 September 30, 2012 and December 31, 2011 (unaudited)	1
Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2012 and 2011 (unaudited)	2
Condensed Consolidated Statements of Changes in Stockholders’/Members’ Equity for the Nine Months Ended September 30, 2012 (unaudited)	3
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 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	20

Item 3. - Quantitative and Qualitative Disclosures About Market Risk	34

Item 4. - Controls and Procedures	35

PART II - OTHER INFORMATION

Item 1. - Legal Proceedings	35

Item 1A. - Risk Factors	35

Item 2. - Unregistered Sales of Equity Securities and Use of Proceeds	40

Item 3. - Defaults upon Senior Securities	40

Item 4. - Mine Safety Disclosures	41

Item 5. - Other Information	41

Item 6. - Exhibits	41

SIGNATURES	42

EXHIBIT INDEX	43

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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)

	September 30, 2012			December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	4,674		$	7,344
Accounts receivable:
Oil and gas sales	22,599			23,792
Severance tax refund	187			3,413
Other	521			249
Prepayments	270			2,642
Inventory	7,036			5,713
Commodity derivative contracts	987			4,957
Total current assets	36,274			48,110

PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of full-cost accounting:
Proved properties	936,476			644,393
Unevaluated properties	102,173			76,857
Other property and equipment	2,758			1,672
Less accumulated depreciation, depletion, and amortization	(235,444		)	(148,843		)
Net property and equipment	805,963			574,079

OTHER ASSETS:
Commodity derivative contracts	594			588
Other noncurrent assets	13,454			1,879
Total other assets	14,048			2,467

TOTAL	$	856,285		$	624,656

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	39,488		$	35,731
Accrued liabilities	64,507			37,524
Commodity derivative contracts	9,244			12,599
Total current liabilities	113,239			85,854

LONG-TERM LIABILITIES:
Asset retirement obligations	11,804			7,627
Commodity derivative contracts	3,978			10,178
Long-term debt	216,300			234,800
Deferred income taxes	157,326			—
Other long-term liabilities	573			695
Total long-term liabilities	389,981			253,300

COMMITMENTS AND CONTINGENCIES (Note 12)

STOCKHOLDERS’/MEMBERS’ EQUITY
Capital contributions	—			322,496
Preferred stock, $0.01 par value, 49,675,000 shares authorized; no shares issued or oustanding	—			—
Series A mandatorily convertible preferred stock, $1,000 liquidation value; 8% cumulative dividends; 325,000 shares designated, no shares issued or outstanding	—			—
Common stock, $0.01 par value, 300,000,000 shares authorized; 66,533,872 shares issued and oustanding	665			—
Additional paid-in-capital	537,082			—
Retained deficit/accumulated loss	(184,682		)	(36,994		)
Total stockholders’/members’ equity	353,065			285,502

TOTAL	$	856,285		$	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 September 30,						For the Nine Months Ended September 30,
	2012			2011			2012			2011

REVENUES:
Oil sales	$	53,143		$	41,241		$	146,281		$	122,817
Natural gas sales	2,257			5,779			8,086			14,813
Natural gas liquid sales	4,134			4,732			14,307			9,949
Gains (Losses) on commodity derivative contracts — net	(33,726		)	40,560			(10,249		)	22,442
Other	124			146			331			260

Total revenues	25,932			92,458			158,756			170,281

EXPENSES:
Lease operating and workover	6,569			3,861			18,957			10,136
Severance and other taxes	6,450			(443		)	18,098			9,052
Asset retirement accretion	165			119			463			205
General and administrative	7,948			17,064			18,966			31,608
Acquisition and transition costs	2,675			—			2,675			—
Depreciation, depletion, and amortization	30,692			22,747			86,601			62,631

Total expenses	54,499			43,348			145,760			113,632

OPERATING INCOME (LOSS)	(28,567		)	49,110			12,996			56,649

OTHER INCOME (EXPENSE)
Interest income	80			3			229			15
Interest expense — net of amounts capitalized	(908		)	(601		)	(3,587		)	(735		)

Total other income (expense)	(828		)	(598		)	(3,358		)	(720		)

INCOME (LOSS) BEFORE TAXES	(29,395		)	48,512			9,638			55,929

Income tax expense (benefit)	(11,592		)	—			157,326			—

NET INCOME (LOSS)	$	(17,803	)	$	48,512		$	(147,688	)	$	55,929

Loss per share (1)
Basic and Diluted (Note 11)	$	(0.27	)	N/A			$	(2.54	)	N/A

Weighted average shares outstanding (1)
Basic and Diluted (Note 11)	65,634			N/A			58,080			N/A

(1) For the nine months ended September 30, 2012, the calculations of loss per share and weighted average shares outstanding are pro forma. See Note 11.

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, except share amounts)

	Common Stock												Total
	Number of Shares		Amount		Capital Contributions			Additional Paid- in-Capital		Retained deficit/ accumulated loss			Stockholders’/ 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		—			213,407		—			213,587
Share-based compensation	916,594		9					1,655		—			1,664
Forfeitures of restricted stock	(17,075	)	—					—		—			—
Net loss	—		—		—			—		(147,688		)	(147,688		)
Balance as of September 30, 2012	66,533,872		$	665	$	—		$	537,082	$	(184,682	)	$	353,065

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

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MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Nine months ended September 30,
	2012			2011

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(147,688	)	$	55,929
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Unrealized (gains) losses on commodity derivative contracts, net	(5,591		)	(34,536		)
Asset retirement accretion	463			205
Depreciation, depletion, and amortization	86,601			62,631
Share-based compensation	1,568			20,128
Deferred income taxes	157,326			—
Amortization of deferred financing costs	583			605
Change in operating assets and liabilities:
Accounts receivable — oil and gas sales	1,193			(3,759		)
Accounts receivable — other	2,954			(5,112		)
Prepayments and other assets	(2,224		)	(221		)
Inventory	(1,323		)	(1,255		)
Accounts payable	(1,211		)	(4,677		)
Accrued liabilities	2,151			12,681
Other	(122		)	649

Net cash provided by operating activities	$	94,680		$	103,268

CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment	(284,875		)	(162,692		)

Net cash used in investing activities	$	(284,875	)	$	(162,692	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings	84,667			109,000
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 $6.4 million	213,587			—
Deferred financing costs	(7,562		)	(863		)
Cash received for units	—			170
Distributions to members	—			(50,572		)
Other	—			(8		)

Net cash provided by financing activities	$	187,525		$	57,727

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(2,670		)	(1,697		)

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

Cash and cash equivalents, end of period	$	4,674		$	10,220

SUPPLEMENTAL INFORMATION:
Non-cash transactions — investments in property and equipment accrued — not paid	$	90,614		$	56,030
Non-cash member’s contribution	$	—		$	2,700
Cash paid for interest, net of capitalized interest of $3.2 million and $2.0 million, respectively	$	3,176		$	735

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. Midstates Petroleum Company, Inc. was incorporated pursuant to the laws of the State of Delaware on October 25, 2011 to become a holding company for Midstates Petroleum Company LLC (“Midstates Sub”), which was previously a wholly-owned subsidiary of Midstates Petroleum Holdings LLC (“Holdings LLC”). Pursuant to the terms of a corporate reorganization that was completed in connection with the closing of Midstates Petroleum Company, Inc.’s initial public offering, 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 $213.6 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 $47.5 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 over-allotment option, First Reserve Midstates Interholding LP and its affiliates owned approximately 41.4% of the Company’s outstanding common stock.

At September 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 significantly different economic or operational environments within 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.

On October 1, 2012, the Company closed on the acquisition of all of Eagle Energy Production, LLC’s producing properties as well as their developed and undeveloped acreage primarily in the Mississippian Lime oil play in Oklahoma and Kansas for $325 million in cash and 325,000 shares of the Company’s newly designated Series A Preferred Stock with an initial liquidation preference value of $1,000 per share (the “Eagle Energy Acquisition”). The Company funded the cash portion of the Eagle Energy Acquisition purchase price with a portion of the net proceeds from the private placement (which also closed on October 1, 2012) of $600 million in aggregate principal amount of 10.75% senior unsecured notes due October 1, 2020. Subsequent to the closing of the Eagle Energy Acquisition, the Company now has oil and gas operations or properties in Louisiana, Oklahoma and Kansas. See Note 13. For the periods presented in this quarterly report, Midstates Petroleum Company, Inc. operated solely in the state of Louisiana.

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

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with the audited consolidated financial statements and notes thereto included in the Company’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 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.

Acquisition and Transition Costs

The Eagle Energy Acquisition qualifies as the acquisition of a business under Accounting Standards Codification Topic 805, Business Combinations (“ASC 805”). Acquisition and transition costs are costs the Company has incurred as a result of the Eagle Energy Acquisition and include finders’ fees; advisory, legal, accounting, valuation and other professional and consulting fees; and general and administrative costs. ASC 805 requires these types of acquisition related costs to be expensed as incurred and as services are received.

Recent Accounting Pronouncements

The Company reviewed recently issued accounting pronouncements that became effective during the nine months ended September 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 discounted cash flow 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 September 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 September 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	$	—	$	18,567	$	—	$	18,567
Commodity derivative deferred premium puts	—		140		—		140
Commodity derivative collars	—		53		—		53
Commodity derivative differential swaps	—		3,563		—		3,563
Total assets	—		22,323		—		22,323

Liabilities:
Commodity derivative oil swaps	$	—	$	19,070	$	—	$	19,070
Commodity derivative deferred premium puts	—		209		—		209
Commodity derivative collars	—		3		—		3
Commodity derivative differential swaps	—		14,682		—		14,682
Total liabilities	$	—	$	33,964	$	—	$	33,964

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

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, collars and options, to manage fluctuations in cash flows resulting from changes in commodity prices. These derivative contracts are placed with major financial institutions that the Company believes are minimal credit risks. The oil 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 September 30, 2012 would have been approximately $1.6 million.

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Commodity Derivative Contracts

As of September 30, 2012, the Company had the following open commodity positions, all of which were related to crude oil:

	Hedged Volume	Weighted-Average Fixed Price

Oil (Bbls):
WTI Swaps — 2012	387,320	$95.75
WTI Swaps — 2013	1,700,874	95.55
WTI Swaps — 2014	809,950	87.33

WTI Collars — 2012	41,400	$85.00 - $127.28

WTI Deferred Premium Puts — 2012 (1)	138,000	$79.01

WTI Basis Differential Swaps — 2012 (2)	490,220	$8.60
WTI Basis Differential Swaps — 2013 (2)	1,602,164	5.89
WTI Basis Differential Swaps — 2014 (2)	501,000	5.35

(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 September 30, 2012 and December 31, 2011, respectively (in thousands):

Type	Balance Sheet Location (1)	September 30, 2012			December 31, 2011
Oil Swaps	Derivative financial instruments — Current Assets	$	14,159		$	—
Oil Swaps	Derivative financial instruments — Non-Current Assets	4,408			—
Oil Swaps	Derivative financial instruments — Current Liabilities	(12,761		)	(13,046		)
Oil Swaps	Derivative financial instruments — Non-Current Liabilities	(6,309		)	(10,116		)
Deferred Premium Puts	Derivative financial instruments — Current Assets	140			1,673
Deferred Premium Puts	Derivative financial instruments — Non-Current Assets	—			—
Deferred Premium Puts	Derivative financial instruments — Current Liabilities	(209		)	(278		)
Deferred Premium Puts	Derivative financial instruments — Non-Current Liabilities	—			(62		)
Collars	Derivative financial instruments — Current Assets	53			397
Collars	Derivative financial instruments — Non-Current Assets	—			—
Collars	Derivative financial instruments — Current Liabilities	(3		)	—
Collars	Derivative financial instruments — Non-Current Liabilities	—			—
Basis Differential Swaps	Derivative financial instruments — Current Assets	3,463			3,612
Basis Differential Swaps	Derivative financial instruments — Non-Current Assets	100			588
Basis Differential Swaps	Derivative financial instruments — Current Liabilities	(13,100		)	—
Basis Differential Swaps	Derivative financial instruments — Non-Current Liabilities	(1,582		)	—
Total		$	(11,641	)	$	(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 September 30, 2012 and December 31, 2011, respectively (in thousands):

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	September 30, 2012		December 31, 2011
Consolidated balance sheet classification:
Current derivative instruments:
Assets	987		4,957
Liabilities	(9,244	)	(12,599	)

Non-current derivative instruments :
Assets	594		588
Liabilities	(3,978	)	(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 September 30,				For the Nine Months Ended September 30,
	2012		2011		2012		2011

Realized net gains (losses)	(4,160	)	(3,958	)	(15,840	)	(12,094	)
Unrealized net gains (losses)	(29,566	)	44,518		5,591		34,536

5. Property and Equipment

Oil and Gas Properties

The Company uses the full-cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as property and equipment. This includes any internal costs that are directly related to exploration and development activities, but does not include any costs related to production, general corporate overhead or similar activities. For the three and nine months ended September 30, 2012, the Company capitalized $0.5 million and $0.9 million of internal costs to property and equipment. Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25%) of the Company’s reserve quantities are sold, in which case a gain or loss is generally recognized in income.

Unevaluated Property

Oil and gas unevaluated properties and properties under development include costs that are not being depleted or amortized. These costs represent investments in unproved properties. The Company excludes these costs until proved reserves are found, until it is determined that the costs are impaired or until major development projects are placed in service, at which time the costs are moved into oil and natural gas properties subject to amortization. All unproved property costs are reviewed at least annually to determine if impairment has occurred. Unevaluated property increased from $76.9 million at December 31, 2011 to $102.2 million at September 30, 2012, primarily due to $18.2 million in seismic acquisition costs incurred on acreage currently under evaluation or option.

Other Property and Equipment

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

Ceiling Test

The Company performs a ceiling test on a quarterly basis. The test establishes a limit (ceiling) on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization (DD&A) and the related deferred income taxes, may not exceed this “ceiling.” The ceiling limitation is equal to the sum of: (i) the present value of estimated future net revenues from the projected production of proved oil and gas reserves, excluding future cash outflows associated with settling ARO’s accrued on the balance sheet, calculated using the average oil and natural gas sales price received by the Company as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved and unevaluated properties excluded from

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

At September 30, 2012 and 2011, capitalized costs did not exceed the ceiling and no impairment to oil and gas properties was required.

6. Asset Retirement Obligations

ARO’s represent the future abandonment costs of tangible assets, such as wells, service assets and other facilities. The fair value of the ARO at inception is capitalized as part of the carrying amount of the related long-lived assets. ARO’s approximated $11.8 million and $7.6 million as of September 30, 2012 and December 31, 2011, respectively.

The liability has been accreted to its present value as of September 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 ARO’s for the nine months ended September 30, 2012 (in thousands):

Asset retirement obligations at January 1, 2012	$	7,627
Liabilities incurred	2,525
Revisions	1,189
Liabilities settled	—
Current period accretion expense	463
Asset retirement obligations at September 30, 2012	$	11,804

7. Long-Term Debt

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

	September 30, 2012		December 31, 2011
Revolving credit facility	$	216,300	$	234,800
Less: current maturities of debt	—		—
Long-term debt	$	216,300	$	234,800

The Company’s credit facility at December 31, 2011 and through June 7, 2012, consisted of a $300 million senior revolving credit facility with a borrowing base, as redetermined in March 2012, of $210 million. Prior to the June 8, 2012 amendment discussed below, 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 revolving credit facility balance.

On June 8, 2012, the Company entered into a Second Amended and Restated Credit Agreement among Midstates Sub, as borrower, the Company, as guarantor, the lenders party thereto and SunTrust Bank, as the new administrative agent, consisting of a $500 million senior revolving credit facility (the “Credit Facility”) with an initial borrowing base of $200 million.

On September 7, 2012, and again on September 26, 2012, the Company entered into amendments to the Credit Facility among the Company, as parent, Midstates Sub, as borrower, SunTrust Bank, N.A., as administrative agent, and the other lenders and parties party thereto (collectively, the “Amendments”). The Amendments provided for, among other things, (a) $35 million of non-conforming borrowing base loans (thereby increasing the borrowing base from $200 million to $235 million), and (b) waiver of the requirement to comply with the minimum current ratio financial covenant for the quarter ending September 30, 2012. Upon the closing of the Eagle Energy Acquisition, the Amendments also provided that the Credit Facility would automatically be amended to (a) accommodate the issuance, incurrence and/or compliance with the terms of the Preferred Stock and the Notes (see Note 13), (b) increase the allowance for the incurrence of certain unsecured indebtedness to allow for the issuance of $600 million of senior unsecured notes without a corresponding reduction in the borrowing base, (c) provide for an initial borrowing base of $250 million and (d) extend the maturity of the Credit Facility to October 1, 2017 (the “Amended Credit Facility”). These terms became effective with the closing of the Eagle Energy Acquisition on October 1, 2012, and availability of non-conforming borrowing base loans ended as of that date. See Note 13.

Borrowings under the terms of the Amended Credit Facility will continue to bear interest at the same rates applicable to the Credit Facility prior to the September 7, 2012 and September 26, 2012 Amendments. Similarly, commitment fees are at the same rates applicable to the Credit Agreement prior to the Amendments.

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Borrowings under the Amended Credit Facility 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 September 30, 2012 and December 31, 2011, the weighted-average interest rate was 3.0% and 3.2%, respectively.

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

The borrowing base under the Amended Credit Facility 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. The next scheduled borrowing base redetermination date is March 2013.

Under the terms of the Amended 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 Amended 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 September 30, 2012, in the absence of the waiver discussed above, the Company would not have been in compliance with the minimum current ratio covenant as set forth in the Amended Credit Facility. The Company’s current ratio at September 30, 2012 was 0.53 to 1.0. At September 30, 2012, the Company’s ratio of debt to EBITDA was 1.48.

In June 2012, in connection with the Credit Facility, the Company incurred legal fees and fees payable to the lending banks of approximately $2.0 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 October 1, 2017. In addition, the Company incurred legal fees and fees payable to the lending banks of approximately $4.3 million in connection with the September 7, 2012 and September 26, 2012 Amendments, which will have similar accounting treatment.

On October 1, 2012, the Company repaid $182.9 million of the outstanding Credit Facility balance with a portion of the net proceeds from the Company’s Notes offering. See Note 13.

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

8. 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, the Company 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 September 30, 2012, the Preferred Units are no longer outstanding. The Company recorded $2.1 million related to interest expense associated with these Preferred Units for the nine months ended September 30, 2012.

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9. 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 the Company’s initial public offering, a corporate reorganization occurred and each common unit of Holdings LLC was converted into approximately 185.5 common shares of the Company and as a result, the Company issued 47,634,353 shares of its common stock.

After the corporate reorganization and the completion of its initial public offering discussed above, the Company 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 the Company’s common shares are entitled to one vote for each share held of record on all matters submitted to a vote of stockholders and to receive ratably in proportion to the shares of common stock held by them any dividends declared from time to time by the board of directors. The common shares have no preferences or rights of conversion, exchange, pre-exemption or other subscription rights. At September 30, 2012, the Company had 66,533,872 shares of its common stock issued and outstanding.

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

In connection with the Eagle Energy Acquisition, on September 28, 2012, the Company filed a Certificate of Designations with the Secretary of State of the State of Delaware to designate 325,000 shares of Series A Mandatorily Convertible Preferred Stock (the “Series A Preferred Stock”). On October 1, the Company issued 325,000 shares of Series A Preferred Stock in connection with the closing of the Eagle Energy Acquisition (see Note 13). The shares of Series A Preferred Stock have an initial liquidation value of $1,000 per share. The Series A Preferred Stock are convertible into shares of the Company’s common stock on or after October 1, 2013. At 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. If not previously converted, 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 based upon the volume weighted average price of the Company’s common stock during the 15 trading days immediately prior to the mandatory conversion date, but in no instance will the price be greater than $13.50 per share or less than $11.00 per share. Dividends on the Series A Preferred Stock will accrue at a rate of 8.0% per annum, payable semiannually, at the Company’s sole option, in cash or through an increase in the liquidation preference. The issuance of the Series A Preferred Stock to Eagle pursuant to the Eagle Purchase Agreement was approved by the Company’s stockholders holding a majority of the outstanding shares of the Company’s common stock.

At September 30, 2012, no preferred shares or Series A Preferred Stock were issued or outstanding.

Share-Based Compensation, pre Initial Public Offering

During the nine months ended September 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 the Company’s common stock. The Company recognized 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.

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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. 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.

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 the Company’s common stock. As a result, there are no outstanding restricted shares in Petroleum Inc. as of September 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 Holdings LLC were converted into 18,762 and 185.5 shares respectively, of the Company’s common stock. As a result, at September 30, 2012, there are no Petroleum, Inc. shares or Holdings LLC units outstanding.

Incentive Units.

At September 30, 2012, 1,656 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.

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Share-based Compensation, Post-Initial Public Offering

2012 Long Term Incentive Plan.

On April 20, 2012, the Company established the 2012 Long Term Incentive Plan (the “2012 LTIP”) and filed a Form S-8 with the SEC, registering 6,563,435 shares 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, through September 30, 2012 the Company has 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 September 30, 2012, the Company assumed no annual forfeiture rate because of the Company’s minimal turnover for this type of award.

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

	Shares		Weighted Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2011	—
Granted	916,594		$	13.16
Vested	—		$	—
Forfeited	(17,075	)	$	13.21
Non-vested shares outstanding at September 30, 2012	899,519		$	13.16

Unrecognized expense as of September 30, 2012 for all outstanding restricted stock awards was $10.2 million and will be recognized over a weighted average period of 2.6 years. Outstanding restricted stock awards had zero intrinsic value at September 30, 2012.

At September 30, 2012, 5,663,916 shares remain available for issuance under the terms of the 2012 LTIP.

The following table summarizes share-based compensation costs (after amounts capitalized to oil and gas properties)recognized as expense by the Company for the periods presented (in thousands):

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2012		2011		2012		2011
Restricted and unrestricted Petroleum Inc. shares and Holdings LLC units	$	—	$	12,179	$	—	$	20,128
Incentive units	—		—		—		—
2012 LTIP restricted shares	886		—		1,568		—
Total share-based compensation expense	$	886	$	12,179	$	1,568	$	20,128

For the three and nine months ended September 30, 2012, the Company capitalized $0.1 million of qualifying share-based compensation costs to oil and gas properties.

10. Income Taxes

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

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primarily to different cost recovery methodology utilized for book and tax purposes for the Company’s oil and natural gas properties. In the quarter ended June 30, 2012, the Company recorded a one-time charge to income tax expense of $149.5 million to recognize this deferred tax liability related to the Company’s change in tax status caused by the initial public offering.

Consistent with the applicable guidance, the Company revises its estimate of its annual income tax rate each quarter, and reflects this change in estimate on year-to-date activity in each quarter. For the quarter ended September 30, 2012, the Company revised its estimated effective annual tax rate for 2012 to 81.3%, exclusive of the one-time charge to income for the change in tax status discussed above. This revision is primarily attributable to a change in expected pre-tax income for the 2012 fiscal year resulting from unrealized losses attributable to hedging activity. The Company’s effective tax rate for the post-reorganization period differs from the federal statutory rate of 35% due to: (i) the inability to use pre-initial public offering losses to offset post-initial public offering 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 September 30, 2012, the Company has not recorded a reserve for any uncertain tax positions. No income tax payments are expected in the upcoming four quarterly reporting periods.

11. 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 basic and diluted net loss for the three and nine months (pro forma) ended September 30, 2012. For the purposes of the nine months pro forma weighted average shares outstanding calculation, there is assumed to be 47,634,353 shares outstanding at January 1, 2012, representing the pro forma common shares outstanding under the previous corporate structure, until the date of the initial public offering, upon which that number increased to 65,634,353 shares to account for the initial public offering of 18,000,000 shares. For the 2011 comparable period, the calculation is not applicable as the Company was not a public company until April 25, 2012.

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	For the Three Months Ended September 30,
	2012							2011
	Income			Shares	Per Share			Income	Shares	Per Share
	(in thousands, except per share amounts)
Net Loss	$	(17,803	)
Loss Allocable to Nonvested Restricted Stock (1)	—
Basic Net Loss Attributable to Common Stock	$	(17,803	)	65,634	$	(0.27	)	N/A	N/A	N/A

Effect of Dilutive Securities:
N/A (2)	—			—
Diluted Net Loss Attributable to Common Stock	$	(17,803	)	65,634	$	(0.27	)	N/A	N/A	N/A

	For the Nine Months Ended September 30,
	2012							2011
	Income			Shares	Per Share			Income	Shares	Per Share
	(in thousands, except per share amounts)
Net Loss	$	(147,688	)
Loss Allocable to Nonvested Restricted Stock (1)	—
Basic Net Loss Attributable to Common Stock	$	(147,688	)	58,080	$	(2.54	)	N/A	N/A	N/A

Effect of Dilutive Securities:
N/A (2)	—			—
Diluted Net Loss Attributable to Common Stock	$	(147,688	)	58,080	$	(2.54	)	N/A	N/A	N/A

(1) Due to the basic net loss attributable to common shareholders for the three and nine months ended September 30, 2012, the Company excluded 910,239 and 513,838 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 September 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 September 30, 2012 was 65,634,353 and 899,519, respectively.

12. Commitments and Contingencies

Contractual Obligations

At September 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	$	3,284	3,284		—		—		—		—
Non-cancellable office lease commitments (1)	$	8,107	305		1,418		1,439		1,459		3,486
Seismic contracts	$	3,174	2,674		500		—		—		—
Other	$	668	668		—		—		—		—

Net minimum commitments	$	15,233	$	6,931	$	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 two floors will terminate and rental obligations for the new floor will begin upon substantial completion of the build out work (which is projected to be late in the fourth quarter of 2012) and when the Company takes possession of the new premises.

Commitments related to ARO’s are not included in the above table; see Note 6 for discussion of those commitments.

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

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(“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 Third Circuit Court of Appeal upheld the district’s court decision that Wells Fargo is protected by the Public Records Doctrine. The Third Circuit 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, 2012 decision, and the Third Circuit Court of Appeal denied that application on August 15, 2012. The Company filed a petition for a writ of certiorari with the Louisiana Supreme Court to seek a review and reversal of the Third Circuit Court of Appeal’s decision on September 14, 2012 and the Plaintiff filed its response to our petition on October 9, 2012.

A final adverse court decision that the Company is subject to the JOA and that the JOA applies to leases acquired after July 16, 1972 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.

13. Subsequent Events

Eagle Energy Acquisition

On August 11, 2012, the Company entered into an Asset Purchase Agreement (the “Eagle Purchase 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 Energy Acquisition”). On October 1, 2012, Midstates Sub completed the Eagle Energy Acquisition for an aggregate purchase price consisting of (a) $325.0 million in cash and (b) 325,000 shares of Series A Preferred Stock, subject to adjustments for expenses incurred and revenue received by Eagle since June 1, 2012, and other customary post-closing purchase price adjustments. The cash portion of the purchase price was funded with proceeds from the sale by the Company of the Notes. The Eagle Acquisition was effective as of June 1, 2012.

In connection with the closing of the Eagle Energy Acquisition, the Company, Eagle, FRMI and certain of our other stockholders entered into a Registration Rights Agreement (the “Eagle Registration Rights Agreement”), pursuant to which the Company has agreed to register the sale of shares of our common stock held by these stockholders under certain circumstances.

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These registration rights are subject to certain conditions and limitations, including the right of underwriters to limit the number of shares to be included in a registration and our right to delay or withdraw a registration statement under certain circumstances. The obligations to register shares under the Eagle Registration Rights Agreement will terminate when no registrable shares (as defined in the Eagle Registration Rights Agreement) remain outstanding.

The disclosures related to the pro forma information for the historical comparable periods are not provided because the purchase price allocation, which determines the initial accounting, is not complete, with respect to the valuation of (i) oil and gas properties acquired, (ii) asset retirement obligations assumed, and (iii) the Series A Preferred Stock given as consideration.

Offering of Senior Notes

On October 1, 2012, the Company issued $600 million in aggregate principal amount of 10.75% senior notes due 2020 (the “Notes”) in a private placement conducted pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended (the “Securities Act”). The estimated proceeds from the offering of $582 million (net of the initial purchasers’ discount and related offering expenses) were used to fund the cash portion of, and expenses related to, the Eagle Energy Acquisition, to pay the expenses related to the amendments to the Company’s revolving credit facility, to repay $182.9 million in outstanding borrowings under the Company’s Credit Facility, and for general corporate purposes.

At any time prior to October 1, 2015, the Company may, under certain circumstances, redeem up to 35% of the aggregate principal amount of the Notes with the net proceeds of a public or private equity offering at a redemption price of 110.75% of the principal amount of the Notes, plus any accrued and unpaid interest up to the redemption date.

In addition, at any time before October 1, 2016, the Company may redeem all or a part of the Notes at a redemption price equal to 100% of the principal amount of Notes redeemed plus the Applicable Premium (as defined in the Indenture) at the redemption date, plus any accrued and unpaid interest and Additional Interest (as defined in the Indenture), if any, up to, the redemption date.

On or after October 1, 2016, the Company may redeem all or a part of the Notes at varying redemption prices (expressed as percentages of principal amount) set forth in the Indenture plus accrued and unpaid interest and Additional Interest (as defined in the Indenture), if any, on the Notes redeemed, up to, the redemption date.

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

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

In connection with the private placement of the Notes, on October 1, 2012, the Company entered into a Registration Rights Agreement (the “Notes Registration Rights Agreement”) obligating the Company to use reasonable best efforts to file an exchange registration statement with the Securities and Exchange Commission (the “Commission”) so that holders of the Notes can offer to exchange the Notes issued in the Notes offering for registered notes having substantially the same terms as the Notes and evidencing the same indebtedness as the Notes. Under certain circumstances, in lieu of a registered exchange offer, the Company must use reasonable best efforts to file a shelf registration statement for the resale of the Notes. If the Issuers fail to satisfy these obligations on a timely basis, the annual interest borne by the Notes will be increased by up to 1.0% per annum until the exchange offer is completed or the shelf registration statement is declared effective.

Revolving Credit Facility

With the closing of the Eagle Energy Acquisition, certain amendments set forth in the Assignment and First Amendment (the “First Amendment”) to the Second Amended and Restated Credit Agreement (the “Credit Facility”) among the Company, as parent, Midstates Sub, as borrower, SunTrust Bank, N.A., as administrative agent, and the other lenders and parties party became effective. These amendments, among other things, (a) accommodate the issuance, incurrence and/or compliance with the terms of the Preferred Stock and the Notes, (b) increase the allowance for the incurrence of certain unsecured indebtedness to allow for the issuance of senior

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notes described above without a corresponding reduction in the borrowing base, (c) provide for an initial borrowing base of $250 million, and (d) extend the maturity of the Credit Facility to October 1, 2017.

Restricted Stock Awards

On October 3, 2012, we granted 94,600 restricted shares under the LTIP to certain employees, with an average grant date fair value based upon the closing price on the date of the grant of $8.73 per MPCI common share, for a total value of approximately $0.8 million. In October, there was a forfeiture of 23,076 restricted shares, which had an average grant date fair value of $13.00, for a total value of approximately $0.3 million; the Company has previously recorded approximately $0.1 million of share based compensation expense related to these shares.

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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 reports on Form 10-Q for the quarterly periods ended March 31, 2012 and June 30, 2012.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in or incorporated by reference into this report are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, and the plans, beliefs, expectations, intentions and objectives of management are forward-looking statements. When used in this quarterly report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” and similar expressions are intended to identify forward looking statements, although not all forward looking statements contain such identifying words. In particular, the factors discussed in this report on Form 10-Q, our quarterly reports on Form 10-Q for the quarterly periods ended March 31, 2012 and June 30, 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:

· our business strategy;

· estimated future net reserves and present value thereof;

· technology;

· cash flows and liquidity;

· financial strategy, budget, projections and operating results;

· oil and natural gas realized prices;

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

· availability of drilling and production equipment;

· availability of oilfield labor;

· 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;

· infrastructure for salt water disposal;

· 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; 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

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for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this quarterly report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.

Overview

We are an independent exploration and production company focused on the development of oil-prone resources in the Upper Gulf Coast Tertiary trend onshore in central Louisiana and, with the October 1, 2012 closing of the Eagle Energy Acquisition, in the Mississippian Lime trend in northwestern Oklahoma and southern Kansas. In Louisiana, our current acreage positions and evaluation efforts are concentrated in the Wilcox interval of the Upper Gulf Coast Tertiary trend, while the majority of our acreage in the Mississippian Lime trend is concentrated in the core of the play in Woods and Alfalfa Counties in northwestern Oklahoma. 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 a 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 (“Midstates Sub”), a wholly-owned subsidiary of Midstates Petroleum Holdings LLC. Pursuant to the terms of a corporate reorganization that was completed immediately prior to the closing of our initial public offering on April 25, 2012, all of the interests in Midstates Petroleum Holdings LLC were exchanged for our newly issued common shares, and as a result, Midstates Petroleum Company LLC became our wholly-owned subsidiary and Midstates Petroleum Holdings LLC ceased to exist as a separate entity.

With the completion of our initial public offering, we became a publicly traded company. Our common stock is listed on the NYSE under the ticker symbol “MPO.” The terms “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, we entered into an Asset Purchase Agreement (the “Eagle Purchase Agreement”) with Eagle Energy Production, LLC (“Eagle”), pursuant to which we 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 Energy Acquisition”). On October 1, 2012, we completed the Eagle Energy Acquisition for an aggregate purchase price consisting of (a) $325.0 million in cash and (b) 325,000 shares of our Series A Preferred Stock with an initial liquidation value of $1,000 per share (the “Series A Preferred Stock”), subject to customary post-closing purchase price adjustments. The cash portion of the purchase price was funded with a portion of the proceeds from our sale of $600 million in aggregate principal amount of 10.75% senior unsecured notes (the “Notes”) maturing on October 1, 2020. See “— Liquidity and Capital Resources —Significant Sources of Capital — Senior Notes Offering” for more information.

With the closing of the Eagle Energy Acquisition, we acquired approximately 82,000 net acres prospective in the Mississippian Lime trend, with 76,000 net acres in Woods and Alfalfa Counties in Northwestern Oklahoma, and 6,000 net acres in Kansas, in which we now own an average working interest of approximately 53%. We currently intend to continue developing these oil and liquids rich properties using horizontal wells. We also acquired approximately 15,000 net acres in the Hunton formation in Lincoln County, Oklahoma, which is primarily a natural gas play. At June 30, 2012, the properties acquired in the Eagle Energy Acquisition had estimated net proved reserves of approximately 33.3 MMBOE, 59% of which were comprised of oil and NGLs.

The oil and gas production and the financial results for the assets acquired in the Eagle Energy Acquisition will be included in our results beginning October 1, 2012.

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Operations Update

We spud 53 gross wells and four sidetracks during the nine months ended September 30, 2012 in Louisiana. Of these 57 wells (including the four sidetracks), 41 were producing, eight were awaiting completion, four were undergoing further evaluation after disappointing initial results and four were drilling at quarter end. Since September 30, 2012 through November 5, 2012, we spud eight additional wells in Louisiana. During the third quarter, 20 wells, including one horizontal well, were spud. In addition, two horizontal sidetracks were spud.

As of September 30, 2012, our properties in Louisiana consisted of approximately 139 gross active producing wells, 96% of which we operate and in which we held an average working interest of 98%.

During the three and nine months ended September 30, 2012, our average daily production was 8,182 Boe/d and 8,120 Boe/d, respectively. Our average daily production for the three months ended September 30, 2012 grew by 4% as compared to the three months ended June 30, 2012, and 11% as compared to the same period of 2011. Our oil and NGL production for the three months ended September 30, 2012 increased by approximately 13% and 18%, respectively, partially offset by a 28% decline in natural gas production when compared to the prior 2012 quarter. Our natural gas production declined in the third quarter of 2012 due to a number of factors, including natural well decline, a lower gas oil ratio attributable to wells recently brought into production, and increased processing for NGL recovery.

With the completion of the Eagle Energy Acquisition, we currently have four rigs drilling in the Mississippian Lime trend and we have completed six wells and spud an additional five wells during the period from the acquisition date of October 1, 2012 through November 5, 2012, and five wells are in the process of completion. As of November 5, 2012, our Mississippian Lime and Hunton properties consist of approximately 122 gross active producing wells, of which we operate approximately 90% and in which we held an average working interest of 70%.

As a result of the Eagle Energy Acquisition on October 1, 2012, we expect to increase our 2012 capital expenditures from $365 million to approximately $440 million, which consists of:

· $355 million for drilling and completion capital;

· $58 million for acquisition of acreage and seismic data; and

· $27 million in unallocated funds which are available for facilities and other capital expenditures.

Through September 30, 2012, approximately $314.8 million of our 2012 capital expenditure budget had been incurred, all of which related to our Louisiana properties. We anticipate that capital expenditures for the remainder of 2012 will be approximately $75 million in our Louisiana properties and approximately $50 million in our Mississippian Lime properties that were acquired as of October 1, 2012.

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

Pine Prairie

We spud 38 gross wells during the nine months ended September 30, 2012 in Pine Prairie. Of these 38 wells, 26 were producing, seven were awaiting completion, three were drilling, and two were mechanical dry holes at September 30, 2012. We drilled 19 vertical wells during the third quarter of 2012, nine of which targeted the Wilcox interval and ten targeted the shallower Miocene and Frio intervals. We expect to drill 12 vertical wells and one vertical sidetrack in Pine Prairie during the remainder of 2012. The program is expected to consist of five Wilcox wells, one Wilcox sidetrack and seven shallower Miocene/Frio wells.

During the three months ended September 30, 2012, average production from these properties was 4,842 net Boe/d, an increase of 173 net Boe/d compared to the three months ended June 30, 2012.

South Bearhead Creek

We spud six gross wells, including one horizontal well, and one vertical sidetrack during the nine months ended September 30, 2012 in South Bearhead Creek. Of these seven wells, six were producing, and one was not producing due to a lease issue at September 30, 2012. During the third quarter we did not spud any wells in South Bearhead Creek. We expect to drill one horizontal sidetrack in the South Bearhead Creek area in the fourth quarter of 2012.

During the three months ended September 30, 2012, average production from these properties was 2,499 net Boe/d, an increase of 233 net Boe/d compared to the three months ended June 30, 2012.

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West Gordon

We spud five gross wells and two horizontal sidetracks during the nine months ended September 30, 2012 in West Gordon. Of these seven wells, five are producing, one is awaiting completion, and one was drilling at September 30, 2012. One of the two horizontal sidetracks spud during the third quarter encountered mechanical issues during the completion phase, and we currently plan to sidetrack the well in the fourth quarter. The second sidetrack is currently under evaluation.

During the three months ended September 30, 2012, average production from these properties was 585 net Boe/d, a decrease of 89 net Boe/d compared to the three months ended June 30, 2012, with the decrease principally due to natural decline.

North Cowards Gully

In the North Cowards Gully area, we drilled one horizontal well during the third quarter of 2012 and in the nine months ended September 30, 2012. This well is currently producing, and we expect to drill one additional horizontal well and one vertical sidetrack in the North Cowards Gully area in the fourth quarter of 2012.

During the three months ended September 30, 2012, average production from these properties was 92 net Boe/d, an increase of 25 net Boe/d compared to the three months ended June 30, 2012.

Louisiana Expansion Areas

We spud three gross wells and one horizontal sidetrack during the nine months ended September 30, 2012 in our expansion areas. Of these four wells, three were producing and one was not producing due to poor results. We did not spud any wells in our expansion areas during the third quarter of 2012 and do not plan on any activity in the fourth quarter of 2012.

Mississippian Lime and Hunton Formation

We expect to operate four rigs and spud 12 horizontal wells in the Oklahoma portion of the Mississippian Lime trend during the remainder of 2012.

Capital Expenditures

During the three and nine months ended September 30, 2012, we incurred capital expenditures of $108.2 million and $314.8 million, respectively, all of which was incurred on our Louisiana properties, and which consisted primarily of (in thousands):

	For the Three Months Ended September 30, 2012		For the Nine Months Ended September 30, 2012
Drilling and completion activities	$	91,945	$	250,092
Acquisition of acreage and seismic data	9,724		42,248
Facilities and other	6,555		22,430
Total capital expenditures incurred	$	108,224	$	314,770

Through September 30, 2012, we also increased our acreage in the Louisiana trend to approximately 159,855 total net acres, comprised of approximately 104,755 net leased acres and approximately 55,100 net optioned acres, an increase of 47% in total net acres since December 31, 2011.

On October 1, 2012, with the closing of the Eagle Energy acquisition, we acquired approximately 82,000 net acres prospective in the Mississippian Lime trend, with approximately 76,000 net acres in Woods and Alfalfa Counties in Northwestern Oklahoma, and approximately 6,000 net acres in Kansas, and approximately 15,000 net acres in the Hunton formation in Lincoln County, Oklahoma.

Amended and Restated Credit Agreement

On September 7, 2012, and again on September 26, 2012, we entered into amendments to our Credit Facility among the Company, as parent, Midstates Sub, as borrower, SunTrust Bank, N.A., as administrative agent, and the other lenders and parties party thereto (collectively the “Amendments”). The Amendments provided for, among other things, (a) $35 million of non-conforming borrowing base loans (thereby increasing the borrowing base from $200 million to $235 million), and (b) waiver of the requirement to comply with the minimum current ratio financial covenant for the quarter ending September 30, 2012. Upon the closing of the Eagle Energy Acquisition, the Amendments also provided that the Credit Facility would automatically be amended to (a) accommodate the issuance, incurrence and/or compliance with the terms of the Preferred Stock and the Notes (See “Item 1. — Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements — Note 13. Subsequent Events.”), (b) increase the allowance for the incurrence of certain unsecured indebtedness to allow for the issuance of $600 million of senior unsecured notes without a corresponding reduction in the borrowing base, (c) provide for an initial borrowing base of $250 million and (d) extend the maturity of

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the Credit Facility to October 1, 2017 (the “Amended Credit Facility”). These terms became effective with the closing of the Eagle Energy Acquisition on October 1, 2012, and availability of non-conforming borrowing base loans ended as of that date.

Offering of Senior Notes

On October 1, 2012, we closed on the issuance of $600 million in aggregate principal amount of 10.75% senior notes due October 1, 2020 (the “Notes”) in a private placement conducted pursuant to Rule 144A and Regulation S under the Securities Act. The estimated net proceeds from the offering of $582 million (net of the initial purchasers’ discount and related offering expenses) were used to fund the cash portion of, and expenses related to, the Eagle Energy Acquisition, to pay the expenses related to the amendments to our revolving credit facility, to repay $182.9 million in outstanding borrowings under our Credit Facility, and for general corporate purposes. See “— Liquidity and Capital Resources —Significant Sources of Capital — Offering of Senior Notes” 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 34 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.

Results of Operations

Revenues

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

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	For the Three Months Ended September 30,								For the Nine Months Ended September 30,
	2012				2011				2012				2011
	(in thousands)
REVENUES:
Oil sales	$	53,143		89%	$	41,241		80%	$	146,281		87%	$	122,817		83%
Natural gas sales	2,257			4%	5,779			11%	8,086			5%	14,813			10%
Natural gas liquid sales	4,134			7%	4,732			9%	14,307			8%	9,949			7%
Total oil, natural gas, and natural gas liquids sales	59,534			100%	51,752			100%	168,674			100%	147,579			100%

Realized gains (losses) on commodity derivative contracts, net	(4,160		)	12%	(3,958		)	-10%	(15,840		)	155%	(12,094		)	-54%
Unrealized gains (losses) on commodity derivative contracts, net	(29,566		)	88%	44,518			110%	5,591			-55%	34,536			154%
Gains (Losses) on commodity derivative contracts — net	(33,726		)	100%	40,560			100%	(10,249		)	100%	22,442			100%

Other	124				146				331				260

Total revenues	$	25,932			$	92,458			$	158,756			$	170,281

Production

	For the Three Months Ended September 30,			For the Nine Months Ended September 30,
	2012	2011	% Change	2012	2011	% Change
PRODUCTION DATA:
Oil (MBbls)	509	383	33%	1,362	1,136	20%
Natural gas (MMcf)	760	1,230	-38%	3,129	3,154	-1%
Natural gas liquids (MBbls)	117	90	29%	342	207	65%
Oil equivalents (MBoe)	753	679	11%	2,225	1,869	19%

Oil (Boe/day)	5,537	4,168	33%	4,969	4,163	19%
Natural gas (Mcf/day)	8,261	13,373	-38%	11,419	11,553	-1%
Natural gas liquids (Boe/day)	1,267	983	29%	1,248	759	64%
Average daily production (Boe/d)	8,182	7,379	11%	8,120	6,847	19%

Prices

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2012		2011		% Change	2012		2011		% Change
AVERAGE SALES PRICES:
Oil, without realized derivatives (per Bbl)	$	104.32	$	107.56	-3%	$	107.43	$	108.08	-1%
Oil, with realized derivatives (per Bbl)	$	96.15	$	97.24	-1%	$	95.80	$	97.43	-2%
Natural gas (per Mcf)	$	2.97	$	4.70	-37%	$	2.58	$	4.70	-45%
Natural gas liquids (per Bbl)	$	35.46	$	52.35	-32%	$	41.84	$	48.02	-13%

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

Oil, natural gas and natural gas liquids revenues. Our oil, natural gas and natural gas liquids (“NGL”) sales revenues increased by $7.7 million, or 15% to $59.5 million during the third quarter of 2012 as compared to $51.8 million for the third 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 $7.7 million revenue variance, sales volume increases contributed $12.6 million, partially offset by unfavorable price variances of $4.9 million. Average daily production sold increased by 803 Boe per day, or 11%, to 8,182 Boe per day during the third quarter of 2012 as compared to 7,379 Boe per day during the third 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 sales prices, without realized derivatives, decreased by $3.24 per barrel or 3% to $104.32 per barrel for the third quarter of 2012 as compared to $107.56 per barrel for the third quarter of 2011. Average natural gas and NGL sales prices decreased by $1.73 per mcf and $16.89 per barrel, to $2.97 per mcf and $35.46 per barrel, respectively, for the three months ended September 30, 2012, as compared to $4.70 per mcf and $52.35 per barrel, respectively, for the same period of 2011.

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Gains/losses on commodity derivative contracts - net. Net gains (losses) on our mark-to-market (“MTM”) derivative positions decreased $74.3 million, or 183%, to a net loss of $33.7 million for the three months ended September 30, 2012 compared to a net gain of $40.6 million for the three months ended September 30, 2011. Our derivative positions moved from an unrealized gain of $44.5 million in the third quarter of 2011 to an unrealized loss of $29.6 million in the third quarter of 2012. The change in our unrealized losses for the 2012 period was primarily attributable to an increase in volumes covered by derivative instruments and a general increase in current and future expected oil prices during the 2012 period as compared to our average hedging price. The value of our derivative positions moves inversely to the price of oil. The realized loss on derivatives for the three months ended September 30, 2012 was $4.2 million compared to a realized loss of $4.0 million for the three months ended September 30, 2011. Realized oil sales prices, with realized derivatives, averaged $96.15 per barrel for the third quarter of 2012 compared to $97.24 per barrel for the same period in 2011.

Nine Months Ended September 30, 2012 as Compared to the Nine Months Ended September 30, 2011

Oil, natural gas and natural gas liquids revenues. Our oil, natural gas and NGL sales revenues increased by $21.1 million, or 14%, to $168.7 million during the first nine months of 2012 as compared to $147.6 million for the first nine 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 $21.1 million revenue variance, sales volume increases contributed $30.7 million of the total, partially offset by unfavorable price variances of $9.6 million. Average daily production sold increased by 1,273 Boe per day, or 19%, to 8,120 Boe per day during the first nine months of 2012 as compared to 6,847 Boe per day during the first nine 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, decreased by $0.65 per barrel, or 1%, to $107.43 per barrel for the first nine months of 2012 as compared to $108.08 per barrel for the first nine months of 2011. Average natural gas and NGL sales prices decreased by $2.12 per mcf and $6.18 per barrel, to $2.58 per mcf and $41.84 per barrel, respectively, for the first nine months of 2012, as compared to $4.70 per mcf and $48.02 per barrel, respectively, for the first nine months of 2011.

Gains/losses on commodity derivative contracts - net. Net gains (losses) on our MTM derivative positions decreased $32.6 million, or 146%, to a net loss of $10.2 million for the nine months ended September 30, 2012 compared to a net gain of $22.4 million for the nine months ended September 30, 2011. Our derivative positions moved from an unrealized gain of $34.5 million in the nine months ended September 30, 2011 to an unrealized gain of $5.6 million in the nine months ended September 30, 2012. The decrease in our unrealized gain for the 2012 period is primarily attributable to increases in volumes covered by derivative instruments and a general increase in current and future expected oil prices as compared to our average hedging price. The value of our hedging instruments moves inversely to the price of oil. The realized loss on derivatives for the nine months ended September 30, 2012 was $15.8 million compared to a realized loss of $12.1 million in the nine months ended September 30, 2011. Realized oil sales prices, with realized derivatives, averaged $95.80 per barrel for the first nine months of 2012 compared to $97.43 per barrel for the same period in 2012.

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 September 30,										For the Nine Months Ended September 30,
	2012		2011			2012		2011			2012		2011		2012		2011
	(in thousands)					(per Boe)					(in thousands)				(per Boe)
EXPENSES:
Lease operating and workover	$	6,569	$	3,861		$	8.72	$	5.69		$	18,957	$	10,136	$	8.52	$	5.42
Severance and other taxes	6,450		(443		)	$	8.57	$	(0.65	)	18,098		9,052		$	8.13	$	4.84
Asset retirement accretion	165		119			$	0.22	$	0.18		463		205		$	0.21	$	0.11
Depreciation, depletion, and amortization	30,692		22,747			$	40.76	$	33.50		86,601		62,631		$	38.92	$	33.51
General and administrative	7,948		17,064			$	10.56	$	25.13		18,966		31,608		$	8.52	$	16.91
Acquisition and transition costs	2,675		—			$	3.55	$	—		2,675		—		$	1.20	$	—
Total expenses	$	54,499	$	43,348		$	72.38	$	63.85		$	145,760	$	113,632	$	65.50	$	60.79

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

Lease operating and workover expenses. Lease operating and workover expenses increased $2.7 million, or 69%, to $6.6 million for the third quarter of 2012 compared to $3.9 million for the third quarter of 2011. Lease operating expenses increased $2.6 million, or

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81%, to $5.8 million for the third quarter of 2012 as compared to $3.2 million for the third quarter of 2011. This increase was due to higher surface maintenance costs of $0.8 million, increased saltwater disposal costs of $0.4 million and an increase in costs associated with higher producing well count of $1.4 million. We recently completed saltwater disposal wells in the Pine Prairie, South Bearhead Creek and West Gordon areas which we believe will reduce our saltwater disposal costs in the future. Workover expenses increased $0.1 million, or 14%, to $0.8 million for the third quarter of 2012 as compared to $0.7 million for the third quarter of 2011. We completed four workovers in the third quarter of 2012, which was a decrease of two projects over the six workovers completed in the third quarter of 2011. Lease operating and workover expenses increased to $8.72 per Boe for the quarter ended September 30, 2012 from $5.69 per Boe for the quarter ended September 30, 2011, an increase of 53%, which was primarily attributable to the factors discussed above.

Severance and other taxes. Severance and other taxes were $6.5 million for the third quarter of 2012 compared to a credit balance of $0.4 million for the third quarter of 2011. Severance taxes increased $6.3 million to $5.7 million for the third quarter of 2012 as compared to a credit balance of $0.6 million for the third quarter of 2011. This increase was attributable to a severance tax refund of $5.4 million in the third quarter of 2011 and higher oil, natural gas and NGL sales revenue during the third quarter of 2012. Excluding the refund, severance taxes for the third quarter of 2011 were $4.8 million, or 9.3% of oil, natural gas and NGL sales revenue as compared to 9.5% for the third quarter of 2012. Ad valorem taxes increased $0.6 million, or 300%, to $0.8 million for the third quarter of 2012 as compared to $0.2 million for the third quarter of 2011, corresponding to a related increase in producing wells.

Depreciation, depletion and amortization (DD&A). DD&A expense increased $8.0 million, or 35%, to $30.7 million for the third quarter of 2012 compared to $22.7 million for the third quarter of 2011. The DD&A rate for third quarter of 2012 was $40.76 per Boe compared to $33.50 per Boe for the third 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 that we were unable to assign significant additional proved reserves to. 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 $9.2 million, or 54%, to $7.9 million for the third quarter of 2012 compared to $17.1 million for the third quarter of 2011. The overall decrease is driven by a reduction in share-based compensation expense of $11.3 million. In the third quarter of 2012, we recorded $0.9 million in share-based compensation expense related to outstanding restricted stock awards compared to $12.2 million recorded in the third quarter of 2011 related to our share-based compensation plans in effect during that period. This decrease in share-based compensation is offset by an increase in professional fees of $1.0 million, primarily related to consulting, accounting and compliance matters, and an increase in employee related costs of $0.6 million related to an increase in headcount from 51 full time employees at September 30, 2011 to 88 full time employees at September 30, 2012.

Acquisition and transition costs. Our acquisition and transition costs increased by $2.7 million for the third quarter of 2012 compared to no acquisition and transition costs for the third quarter of 2011. These costs represent our expenses through September 30, 2012 related to the Eagle Energy Acquisition and are primarily attributable to due diligence, legal and other advisory fees that are required to be expensed under US GAAP.

Nine Months Ended September 30, 2012 as Compared to the Nine Months Ended September 30, 2011

Lease operating and workover expenses. Lease operating and workover expenses increased $8.9 million, or 88%, to $19.0 million for the nine months ended September 30, 2012 compared to $10.1 million for the nine months ended September 30, 2011. Lease operating expenses increased $7.9 million, or 88%, to $16.7 million for the nine months ended September 30, 2012 as compared to $8.8 million for the nine months ended September 30, 2011. This increase was due to increased surface maintenance costs of $2.0 million, environmental costs of $0.5 million, saltwater disposal costs of $1.7 million and an increase in costs associated with higher producing well count of $3.4 million. We recently completed saltwater disposal wells in the Pine Prairie, South Bearhead Creek and West Gordon areas which we believe will reduce our saltwater disposal costs in the future. Workover expenses increased $1.0 million, or 77%, to $2.3 million for the nine months ended September 30, 2012 as compared to $1.3 million for the nine months ended September 30, 2011. We completed 23 workovers in the first nine months of 2012, which was an increase of eight projects over the 15 workovers completed in the first nine months of 2011. Lease operating and workover expenses increased to $8.52 per Boe for the nine months ended September 30, 2012 from $5.42 per Boe for the nine months ended September 30, 2011, an increase of 57%, which was primarily attributable to the factors discussed above.

Severance and other taxes. Severance and other taxes increased $9.0 million, 99%, to $18.1 million for the nine months ended September 30, 2012 compared to $9.1 million for the nine months ended 2011. Severance taxes increased $7.2 million, or 86%, to $15.6 million for the nine months ended September 30, 2012 as compared to $8.4 million for the nine months ended September 30, 2011. This increase was attributable to a severance tax refund of $5.4 million in the 2011 third quarter and higher oil, natural gas and NGL sales revenue during the nine months of 2012. Excluding the refund, severance taxes for the nine months of 2011 were $13.8 million, or 9.4% as a percentage of oil, natural gas and NGL sales revenue, as compared to 9.2% for the nine months ended September

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30, 2012. Ad valorem taxes increased $1.8 million, or 257%, to $2.5 million for the nine months ended September 30, 2012 as compared to $0.7 million for the nine months ended September 30, 2011, corresponding to a related increase in producing wells.

Depreciation, depletion and amortization (DD&A). DD&A expense increased $24.0 million, or 38%, to $86.6 million for the nine months ended September 30, 2012 compared to $62.6 million for the nine months ended September 30, 2011. The DD&A rate for nine months ended September 30, 2012 was $38.92 per Boe compared to $33.51 per Boe for the nine months ended September 30, 2011. The increase in the DD&A rate per Boe versus the comparable 2011 period is primarily attributable 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 general and administrative expenses (“G&A”) decreased by $12.6 million, or 40%, to $19.0 million for the nine months ended September 30, 2012 compared to $31.6 million for the nine months ended September 30, 2011. The overall decrease is driven by a reduction in share-based compensation expense of $18.6 million. In the first nine months of 2012, we recorded $1.6 million in share-based compensation expense related to outstanding restricted stock awards compared to $20.1 million recorded in the same period of 2011 related to our share-based compensation plans in effect during that period. This decrease in share-based compensation is partially offset by an increase in professional fees of $1.9 million, primarily related to consulting, accounting and compliance matters, and an increase in employee related costs of $2.8 million related to an increase in headcount from 51 full time employees at September 30, 2011 to 88 full time employees at September 30, 2012.

Acquisition and transition costs. Our acquisition and transition costs increased by $2.7 million for the nine months ended September 30, 2012 compared to no acquisition and transition costs for the nine months ended September 30, 2011. These costs represent our expenses through September 30, 2012 related to the Eagle Energy Acquisition and are primarily attributable to due diligence, legal and other advisory fees that are required to be expensed under US GAAP.

Other Income (Expenses)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2012			2011			2012			2011
	(in thousands)						(in thousands)
OTHER INCOME (EXPENSE)
Interest income	$	80		$	3		$	229		$	15

Interest expense	(1,734		)	(1,261		)	(6,798		)	(2,721		)
Capitalized Interest	826			660			3,211			1,986
Interest expense — net of amounts capitalized	$	(908	)	$	(601	)	$	(3,587	)	$	(735	)

Total other income (expense)	$	(828	)	$	(598	)	$	(3,358	)	$	(720	)

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

Interest expense. Interest expense for the three months ended September 30, 2012 and September 30, 2011 was $1.7 million and $1.3 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 $185.3 million during the 2012 period, versus $156.0 million for the 2011 period, and related to $1.5 million of the total interest expense of $1.7 million. The remainder of the interest expense for the three months ended September 30, 2012, is attributable to amortization of deferred financing costs of $0.2 million. Of total interest expense, $0.8 million and $0.7 million was capitalized, resulting in $0.9 million and $0.6 million in interest expense for the three months ended September 30, 2012 and September 30, 2011, respectively.

Nine Months Ended September 30, 2012 as Compared to the Nine Months Ended September 30, 2011

Interest expense. Interest expense for the nine months ended September 30, 2012 and September 30, 2011 was $6.8 million and $2.7 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 $194.6 million during the 2012 period, versus $124.0 million for the 2011 period, and related to $4.4 million of the total interest expense of $6.8 million. The remainder of the interest expense for the nine months ended September 30, 2012, $2.4 million, related to interest expense of $2.1 million associated with our Preferred Units which were redeemed in April 2012, and amortization of deferred financing costs of $0.3 million. Of total

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interest expense, $3.2 million and $2.0 million was capitalized, resulting in $3.6 million and $0.7 million in interest expense for the nine months ended September 30, 2012 and September 30, 2011, respectively.

Provision for Income Taxes

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

Income tax benefit was $11.6 million for the three months ended September 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. In the three months ended September 30, 2012, the Company revised its estimated effective annual tax rate for 2012 to 81.3% (exclusive of the one-time charge to income for the change in tax status recorded in the three months ended June 30, 2012). Change in expected pre-tax income resulting from unrealized losses attributable to hedging activity was the primary factor causing this revision in estimate. As required by the applicable guidance, the effect of this revision in the estimated annual effective tax rate (to 81.3%) was recorded in the period of the revised estimate. The resulting income tax benefit for the three months ended September 30, 2012 represents an effective tax benefit rate (including state income taxes) of 39.4%.

Nine Months Ended September 30, 2012 as Compared to the Nine Months Ended September 30, 2011

Income tax expense was $157.3 million for the nine months ended September 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 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 date. As a result, during the nine months ended September 30, 2012, we recorded a tax charge of $149.5 million associated with the Reorganization.

During the nine months ended September 30, 2012, we also recorded $7.8 million of income tax expense. This represents an application of our estimated effective tax rate (including state income taxes) for the nine months ended September 30, 2012 of 81.3% (as described above) to our income earned from the Reorganization date through the period end.

Liquidity and Capital Resources

At September 30, 2012, our liquidity was $23.2 million, consisting of $18.5 million of available borrowing capacity under our revolving credit facility (which at that date, consisted of a borrowing base of $235 million) and $4.7 million of cash and cash equivalents.

Recent Developments Impacting our Liquidity

On October 1, 2012, we completed the private issuance of $600 million in aggregate principal amount of Notes. The Notes mature on October 1, 2020 and were issued at 100% of face value. The net proceeds from the Notes offering of $582 million (net of the initial purchasers’ discount and related offering expenses) were used to fund the cash portion of, and expenses related to, the Eagle Energy Acquisition, to pay the expenses related to the amendments of our revolving credit facility, to repay $182.9 million in outstanding borrowings under our revolving credit facility, and for general corporate purposes. See “—Significant Sources of Capital — Senior Notes Offering” below for more information.

Also on October 1, 2012, as a result of the consummation of the Eagle Energy Acquisition, certain previously executed amendments to our revolving credit facility became effective. As a result, the borrowing base under our revolving credit facility was increased to $250 million (subject to semi-annual redetermination beginning in March 2013) and the maturity date was extended to October 1, 2017. At October 1, 2012, after completion of the transactions detailed above and the payment of certain expenses directly related to the closing of the Eagle Energy acquisition, we had approximately $216 million of borrowing availability under the revolving credit facility and $38 million of cash and cash equivalents. See “—Significant Sources of Capital — Reserve-based Credit Facility” for more information.

We expect that this capital structure, together with future cash flows from operations, will give us sufficient liquidity to fund our development program through the end of 2013.

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Significant Sources of Capital

Reserve-based Credit Facility.

On June 8, 2012, we entered into a Second Amended and Restated Credit Agreement among Midstates Sub, as borrower, the Company, as guarantor, the lenders party thereto and SunTrust Bank, as the new administrative agent, consisting of a $500 million senior revolving credit facility (the “Credit Facility”) with an initial borrowing base of $200 million.

On September 7, 2012, and again on September 26, 2012, we entered into the Amendments to the Credit Facility among the Company, as parent, Midstates Sub, as borrower, SunTrust Bank, N.A., as administrative agent, and the other lenders and parties party thereto. The Amendments provided for, among other things, (a) $35 million of non-conforming borrowing base loans (thereby increasing the borrowing base from $200 million to $235 million), and (b) waiver of the requirement to comply with the minimum current ratio financial covenant for the quarter ending September 30, 2012. Upon the closing of the Eagle Energy Acquisition, the Amendments also provided that the Credit Facility would automatically be amended to (a) accommodate the issuance, incurrence and/or compliance with the terms of the Preferred Stock and the Notes, (b) increase the allowance for the incurrence of certain unsecured indebtedness to allow for the issuance of $600 million of senior unsecured notes without a corresponding reduction in the borrowing base, (c) provide for an initial borrowing base of $250 million and (d) extend the maturity of the Credit Facility to October 1, 2017. These terms became effective with the closing of the Eagle Energy Acquisition on October 1, 2012, and availability of non-conforming borrowing base loans ended as of that date.

Borrowings under the terms of the Amended Credit Facility will continue to bear interest at the same rates applicable to the Credit Agreement prior to the Amendments. Similarly, commitment fees are at the same rates applicable to the Credit Facility prior to the Amendments.

Borrowings under the Amended Credit Facility are 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 September 30, 2012 and December 31, 2011, the weighted-average interest rate was 3.0% and 3.2%, respectively.

The borrowing base under the Amended Credit Facility 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 us or the administrative agent, acting on behalf of lenders holding at least two —thirds of the outstanding loans and other obligations. The next scheduled borrowing base redetermination date is March 2013.

Under the terms of the Amended Credit Facility, we are 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. We are permitted to make such repayment in six equal successive monthly payments commencing 30 days following the administrative agent’s notice regarding such borrowing base reduction.

The Amended 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 our ability to make any dividends, distributions or redemptions. As of September 30, 2012, in the absence of the waiver discussed above, we would not have been in compliance with the minimum current ratio covenant as set forth in the Amended Credit Facility. Our current ratio at September 30, 2012 was 0.53 to 1.0. At September 30, 2012, our ratio of debt to EBITDA was 1.48.

In June 2012, in connection with the Credit Facility, we incurred legal fees and fees payable to the lending banks of approximately $2.0 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 October 1, 2017. In addition, we incurred legal fees and fees payable to the lending banks of approximately $4.3 million in connection with the Amendments, which will have similar accounting treatment.

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

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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 September 30, 2012. We recorded $2.1 million related to interest expense associated with these Preferred Units for the nine months ended September 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, were $220.0 million (or $213.6 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.

Senior Notes Offering.

On October 1, 2012, we issued $600 million in aggregate principal amount of 10.75% senior notes due 2020 (the “Notes”) in a private placement conducted pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended (the “Securities Act”). The estimated net proceeds from the offering of $582 million (net of the initial purchasers’ discount and related offering expenses) were used to fund the cash portion of, and expenses related to, the Eagle Energy Acquisition, to pay the expenses related to the amendments to our revolving credit facility, to repay $182.9 million in outstanding borrowings under our Credit Facility, and for general corporate purposes.

At any time prior to October 1, 2015, we may, under certain circumstances, redeem up to 35% of the aggregate principal amount of the Notes with the net proceeds of a public or private equity offering at a redemption price of 110.75% of the principal amount of the Notes, plus any accrued and unpaid interest up to the redemption date.

In addition, at any time before October 1, 2016, we may redeem all or a part of the Notes at a redemption price equal to 100% of the principal amount of Notes redeemed plus the Applicable Premium (as defined in the Indenture) at the redemption date, plus any accrued and unpaid interest and Additional Interest (as defined in the Indenture), if any, up to the redemption date.

On or after October 1, 2016, we may redeem all or a part of the Notes at varying redemption prices (expressed as percentages of principal amount) set forth in the Indenture plus accrued and unpaid interest and Additional Interest (as defined in the Indenture), if any, on the Notes redeemed, up to the redemption date.

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

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

In connection with the private placement of the Notes, on October 1, 2012, we entered into a Registration Rights Agreement (the “Notes Registration Rights Agreement”) obligating us to use reasonable best efforts to file an exchange registration statement with the Securities and Exchange Commission (the “Commission”) so that holders of the Notes can offer to exchange the Notes issued in the Notes offering for registered notes having substantially the same terms as the Notes and evidencing the same indebtedness as the

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Notes. Under certain circumstances, in lieu of a registered exchange offer, we must use reasonable best efforts to file a shelf registration statement for the resale of the Notes. If we fail to satisfy these obligations on a timely basis, the annual interest borne by the Notes will be increased by up to 1.0% per annum until the exchange offer is completed or the shelf registration statement is declared effective.

Series A Preferred Stock.

On October 1, 2012 we issued 325,000 shares of our Series A Preferred Stock as part of the purchase price paid to complete the Eagle Energy Acquisition (see “Item 1. —Financial Statements —Notes to Unaudited Condensed Consolidated Financial Statements — Note 13. Subsequent Events). The shares of Series A Preferred Stock have an initial liquidation value of $1,000 per share and are convertible into shares of our common stock on or after October 1, 2013. At 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 our common stock calculated by dividing the then-current liquidation preference by the conversion price of $13.50 per share. If not previously converted, the Series A Preferred Stock will be subject to mandatory conversion into shares of our common stock on September 30, 2015 at a conversion price based upon the volume weighted average price of our common stock during the 15 trading days immediately prior to the mandatory conversion date, but in no instance will the price be greater than $13.50 per share or less than $11.00 per share. Dividends on the Series A Preferred Stock will accrue at a rate of 8.0% per annum, payable semiannually, at our sole option, in cash or through an increase in the liquidation preference. The issuance of the Series A Preferred Stock to Eagle pursuant to the Eagle Purchase Agreement was approved by our stockholders holding a majority of the outstanding shares of our common stock.

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 Nine Months Ended September 30,
	2012			2011
Net cash provided by operating activities	$	94,680		$	103,268
Net cash used in investing activities	(284,875		)	(162,692		)
Net cash provided by financing activities	187,525			57,727

Net change in cash	$	(2,670	)	$	(1,697	)

Our operating cash flows are sensitive to a number of variables, the most significant of which is the volatility of oil and gas prices. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of these commodities. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “Item 3. — Quantitative and Qualitative Disclosures About Market Risk” beginning on page 34.

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 $94.7 million and $103.3 million for the nine months ended September 30, 2012 and September 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 partially offset by an increase in production, and unfavorable 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 $284.9 million and $162.7 million during the nine months ended September 30, 2012 and September 30, 2011, respectively, as a result of our capital expenditures for drilling, development and acquisition costs. The

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increase in net cash used in investing activities during first nine months of 2012 compared to first nine months of 2011 is attributable to continued expansion of our drilling programs, and acreage position, as well as growth of our business.

Cash flows provided by financing activities

Net cash provided by financing activities was $187.5 million and $57.7 million for the nine months ended September 30, 2012 and September 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 September 30, 2012 and September 30, 2011 were $216.3 million and $198.6 million, respectively. During the 2012 period, we completed our initial public offering which resulted in net proceeds of $213.6 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.

Capital Expenditures

Through September 30, 2012, approximately $314.8 million of our 2012 capital expenditure budget had been incurred, all of which related to our Louisiana properties. The ultimate amount of capital we will expend may fluctuate materially based upon market conditions and the success of our drilling results.

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

Other Items

Contractual Obligations

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

	Payments due by Period (1)
	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Revolving credit facility	$	216,300	—		—		—		216,300
Drilling contracts (2)(4)	$	3,284	3,284		—		—		—
Operating leases (2)	$	8,107	305		2,857		2,939		2,006
Seismic contracts (2)(5)	$	3,174	2,674		500		—		—
Asset retirement obligations (3)	$	11,804	—		—		—		11,804
Other (2)	$	668	668		—		—		—
Total contractual obligations	$	243,337	$	6,931	$	3,357	$	2,939	$	230,110

(1) Less than 1 year represents amounts for the remainder of 2012 (October 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 Item 1. — Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements — Note 12. Commitments and Contingencies for a description of operating lease, drilling contract, seismic contract and other contractual obligations.

(3) Amounts represent our estimate of future asset retirement obligations on a discounted basis. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Item 1. — Financial Statements — Notes to Unaudited Condensed Consolidated Financial Statements — Note 6. Asset Retirement Obligations.

(4) We entered into agreements after September 30, 2012 which will require minimum payments of approximately $2.2 million and approximately $4.7 million in 2012 and 2013, respectively, for certain drilling contracts. As of October 1, 2012, with the closing of the Eagle Energy Acquisition we assumed obligations which will require minimum payments of approximately $2.0 million for the remainder of 2012 for certain drilling contracts.

(5) We entered into agreements after September 30, 2012 which will require minimum payments of $0.6 million and $5.8 million in 2012 and 2013, respectively, for certain seismic contracts.

Off-Balance Sheet Arrangements

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

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Recent Accounting Pronouncements

The Company reviewed recently issued accounting pronouncements that became effective during the three months ended September 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 September 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 September 30, 2012:

	Hedged Volume	Weighted-Average Fixed Price

Oil (Bbls):
WTI Swaps — 2012	387,320	$95.75
WTI Swaps — 2013	1,700,874	95.55
WTI Swaps — 2014	809,950	87.33

WTI Collars — 2012	41,400	$85.00 - $127.28

WTI Deferred Premium Puts — 2012 (1)	138,000	$79.01

WTI Basis Differential Swaps — 2012 (2)	490,220	$8.60
WTI Basis Differential Swaps — 2013 (2)	1,602,164	5.89
WTI Basis Differential Swaps — 2014 (2)	501,000	5.35

	Nine Months Ended September 30, 2012
	(in thousands)
Derivative fair value at period end - liability (included in the balance sheet)	$	(11,641	)

Realized net (loss) gain (included in the statement of operations)	$	(15,840	)

Unrealized net (loss) gain (included in the statement of operations)	$	5,591

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At September 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.

On October 1, 2012, we assumed all of Eagle Energy’s hedge positions with the closing of the acquisition. The following is a summary of those commodity derivative contracts as of November 5, 2012:

	Hedged Volume	Weighted-Average Fixed Price

Oil (Bbls):
WTI Swaps – 2012	79,904	$96.07
WTI Swaps – 2013	237,600	96.10
WTI Swaps – 2014	156,000	93.00

WTI Collars – 2012	94,500	$90.29 - $106.08
WTI Collars – 2013	203,004	$85.27 - $100.70
WTI Collars – 2014	164,400	$88.49 - $97.94

Natural Gas (Mmbtu):
Natural Gas Swaps – 2012	524,400	$6.06

Collars – 2012	372,000	$2.83 - $3.44
Collars – 2013	2,232,996	$3.68 - $4.91
Collars – 2014	1,685,004	$3.99 - $5.09

NGL (Bbls):
NGL Swaps – 2012	97,800	$68.46
NGL Swaps – 2013	258,000	$63.42
NGL Swaps – 2014	151,500	$62.16

Interest Rate Risk. At September 30, 2012, we had indebtedness outstanding under our credit facility of $216.3 million, which bore interest at floating rates. The average annual interest rate incurred on this indebtedness for the three months ended September 30, 2012 and September 30, 2011 was approximately 3.3% and 3.1%, respectively. The average annual interest rate incurred on this indebtedness for the nine months ended September 30, 2012 and September 30, 2011 was approximately 3.0% and 2.9%, respectively. A 1.0% increase in each of the average LIBOR and federal funds rate for the three months ended September 30, 2012 and three months ended September 30, 2011 would have resulted in an estimated $0.5 million and $0.4 million, respectively, increase in interest expense, of which a portion may be capitalized. A 1.0% increase in each of the average LIBOR and federal funds rate for the nine months ended September 30, 2012 and nine months ended September 30, 2011 would have resulted in an estimated $1.5 million and $0.9 million, respectively, increase in interest expense, of which a portion may be capitalized.

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

Item 4. — Controls and Procedures

Evaluation of Disclosure Controls and Procedures

During the period covered by this report, our management carried out an evaluation, 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 September 30, 2012 are effective.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended September 30, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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.

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For a discussion of our potential risks and uncertainties, see the information in our prospectus dated April 19, 2012 and filed with the SEC pursuant to Rule 424(b) on April 20, 2012, in our quarterly report on Form 10-Q for the quarter ended March 31, 2012, and in our quarterly report on Form 10-Q for the quarter ended June 30, 2012.

Except for the risk factors set forth below, there have been no material changes in our risk factors from those described in the above filings with the SEC.

We may not be able to generate sufficient cash flows to service all of our indebtedness and may be forced to take other actions in order to satisfy our obligations under our indebtedness, which may not be successful.

Our ability to make scheduled payments on, or to refinance, our debt obligations will depend on our financial and operating performance, which is subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We cannot assure you that our business will generate sufficient cash flows from operating activities or that future sources of capital will be available to us in an amount sufficient to permit us to service our indebtedness or to fund our other liquidity needs. If we are unable to generate sufficient cash flows to satisfy our debt obligations, we may have to undertake alternative financing plans, such as refinancing or restructuring our debt, selling assets, reducing or delaying capital investments or seeking to raise additional capital. We cannot assure you that any refinancing would be possible, that any assets could be sold or, if sold, of the timing of the sales and the amount of proceeds that may be realized from those sales, or that additional financing could be obtained on acceptable terms, if at all. The agreements governing our outstanding indebtedness restrict our ability to dispose of assets and our use of any of the proceeds. Our inability to generate sufficient cash flows to satisfy our debt obligations, or to refinance our indebtedness on commercially reasonable terms, would materially and adversely affect our financial condition and results of operations.

In addition, if we cannot make scheduled payments on our debt, we will be in default and, as a result:

· our debt holders could declare all outstanding principal and interest to be due and payable;

· the lenders under our revolving credit facility could terminate their commitments to lend us money and foreclose against the assets securing their borrowings; and

· we could be forced into bankruptcy or liquidation.

Despite our current level of indebtedness, we may incur substantially more debt in the future, which could further exacerbate the risks described above. Furthermore, we are permitted to incur additional debt, under the terms of the credit agreements governing our credit facility, subject to borrowing base availability, and the indenture governing the notes, subject to certain limitations, which in each case could intensify the related risks that we and our subsidiary now face.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

We will be subject to interest rate risk in connection with borrowings under the credit facility, which will bear interest at variable rates. Interest rate changes will not affect the market value of any debt incurred under such facility, but could affect the amount of our interest payments, and accordingly, our future earnings and cash flows, assuming other factors are held constant. We currently do not have any interest rate hedging arrangements with respect to the credit facility. In the future, we may enter into interest rate swaps that involve the exchange of floating for fixed rate interest payments in order to reduce interest rate volatility; however, any swaps we enter into may not fully mitigate our interest rate risk. A significant increase in prevailing interest rates, which results in a substantial increase in the interest rates applicable to our interest expense could have a material adverse effect on our financial condition and results of operations.

Restrictive covenants may adversely affect our operations.

The agreements governing our outstanding indebtedness contain a number of restrictive covenants that impose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in our long-term best interest, including our ability, among other things, to:

· incur or assume additional debt or provide guarantees in respect of obligations of other persons;

· issue redeemable stock and preferred stock;

· pay dividends or distributions or redeem or repurchase capital stock;

· prepay, redeem or repurchase certain debt;

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· make loans and investments;

· create or incur liens;

· restrict distributions from our subsidiaries;

· sell assets and capital stock of our subsidiaries;

· consolidate or merge with or into another entity, or sell all or substantially all of our assets; and

· enter into new lines of business.

A breach of the covenants under the agreements governing our outstanding indebtedness could result in an event of default under the applicable indebtedness. An event of default may allow the creditors to accelerate the related debt and may result in an acceleration of any other debt to which a cross-acceleration or cross-default provision applies. In addition, an event of default under our credit facility would permit the lenders under the facility to terminate all commitments to extend further credit. If we were unable to repay those amounts, the lenders under our revolving credit facility could proceed against the collateral granted to them to secure that debt.

Our level of indebtedness may increase and reduce our financial flexibility.

As of November 5, 2012, we have a borrowing base of $250.0 million, $216.0 of which was available for borrowing under our revolving credit facility (before giving effect to $0.2 million of outstanding letters of credit, which reduce availability). In the future, we may incur significant indebtedness in order to make future acquisitions or to develop our properties.

Our level of indebtedness could affect our operations in several ways, including the following:

· a significant portion of our cash flows could be used to service our indebtedness;

· a high level of debt would increase our vulnerability to general adverse economic and industry conditions;

· the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

· a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, such competitors may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;

· our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

· a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then outstanding bank borrowings; and

· a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that may affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

In addition, our bank borrowing base is subject to periodic redeterminations on a semi-annual basis, effective September 1 and March 1, beginning March 1, 2013, and up to one additional time per six-month period following each scheduled borrowing base redetermination, as may be requested by either us or the administrative agent under our revolving credit facility. In the future we could be forced to repay a portion of our then outstanding bank borrowings due to future redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are unable to arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

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Derivatives regulation included in current financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices.

The United States Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act in 2010. This comprehensive financial reform legislation changes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the Commodity Futures Trading Commission, or CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation The CFTC recently promulgated regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. Position limits for spot month limits are expected to become effective on October 12, 2012 while non-spot month limits for energy-related commodities are not expected to be effective until mid- to late-2013. The CFTC also has

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proposed regulations to establish minimum capital and margin requirements, as well as clearing and trade-execution requirements in connection with certain derivative activities, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the Dodd-Frank Act. In addition, the CFTC’s regulations adopted pursuant to the Dodd-Frank Act impose certain recordkeeping and transactional reporting requirements that may be burdensome and costly to us and to the counterparties to our commodity derivative contracts.

The new legislation and any new regulations could significantly increase the cost of some commodity derivative contracts (including through requirements to post collateral or provide other credit support, which could adversely affect our available liquidity), materially alter the terms of some commodity derivative contracts, reduce the availability of some derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing commodity derivative contracts and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the new legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. If the new legislation and regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our business, financial condition and results of operations.

We are currently controlled by First Reserve and First Reserve and Riverstone collectively hold a majority of the voting power of our common stock and certain actions by us will require the consent of First Reserve or Riverstone. Their interests as equity holders may conflict with the interests of our other equity holders and the holders of our notes.

First Reserve currently owns an economic interest in us through FR Midstates Interholding LP (“FRMI”), which owns approximately 41% of our shares of common stock and is controlled by First Reserve. Eagle Energy, which is controlled by Riverstone Holdings, LLC (“Riverstone”), holds preferred stock such that, on a pro forma basis following conversion of the Preferred Stock at a conversion price of $13.50, FRMI and Riverstone (together with Eagle Energy management) will own 30% and 27% of our shares of common stock, respectively.

While they hold these interests, these entities will have significant influence over our operations and will have representatives on our board of directors. The interests of FRMI and Riverstone may not in all cases be aligned with the interests of the noteholders or our other equity holders.

In addition, we, FRMI and certain of our other stockholders have entered into a stockholders’ agreement that permits FRMI to designate certain of our director nominees and prohibits us from engaging in certain transactions without the written consent of FRMI. The stockholders’ agreement provides that the following actions by us require the consent of FRMI:

· incurrence of debt that would result in a total net indebtedness to EBITDA ratio in excess of 2.50:1;

· authorization, creation or issuance of any equity securities (other than pursuant to compensation plans approved by the compensation committee or in connection with certain permitted acquisitions);

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· redemption, acquisition or other purchase of any securities of the Company (other than certain repurchases from employees and directors);

· amendment, repeal or alteration of our amended and restated certificate of incorporation or amended and restated bylaws;

· any acquisition or disposition (where the amount of consideration exceeds $100 million in a single transaction or $200 million in any series of transactions during a calendar year);

· consummation of a “change in control” transaction;

· adoption, approval or issuance of any “poison pill” or similar rights plan; and

· entry into any plan of liquidation, dissolution or winding-up of the Company.

These actions by us require the consent of FRMI until the earlier of (i) receipt by our board of directors of FRMI’s written election to waive its rights, (ii) the date FRMI ceases to hold at least 35% of our outstanding common stock, (iii) the third anniversary of the closing of our initial public offering or (iv) the date on which there are no directors nominated by FRMI serving as members of our board of directors.

The terms of the preferred stock permit Riverstone to designate one of our director nominees, who must be an employee of Riverstone or one of its affiliates, and prohibit us from engaging in certain transactions without the consent of Riverstone, including the following actions:

· the creation or issuance of any class of capital stock senior to or on parity with the Preferred Stock;

· the redemption, acquisition or purchase by us of any of our equity securities, other than a repurchase from an employee or director in connection with such person’s termination or as provided in the agreement pursuant to which such equity securities were issued;

· any change to our certificate of incorporation or bylaws that adversely affects the rights, preferences, privileges or voting rights of the holders of the Preferred Stock;

· acquisitions or dispositions for which the amount of consideration exceeds 20% of our market capitalization in any single transaction or 40% of our market capitalization for any series of transactions during a calendar year;

· entering into certain transactions with affiliates, other than transactions that do not exceed, in the aggregate, $10 million in any calendar year;

· certain corporate transactions unless the holders of the Preferred Stock would receive consideration consisting solely of cash and/or marketable securities with an aggregate fair market value equal to or greater than the liquidation preference on such shares of Preferred Stock; and

· any increase or decrease in the size of our board of directors.

As a result of FRMI’s and Riverstone’s equity ownership or voting power, director nominees and consent rights, our ability to engage in financing transactions or other significant transactions, such as a merger, acquisition, disposition or liquidation, may be limited. In connection with such transactions, conflicts of interest could arise between us and FRMI or Riverstone, and any conflict of interest may be resolved in a manner that does not favor us.

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

On October 1, 2012, we completed the Eagle Energy Acquisition. Pursuant to the Eagle Purchase Agreement, we acquired certain interests in producing oil and natural gas assets, unevaluated leasehold acreage in Oklahoma and Kansas and the related hedging instruments in exchange for the Eagle Purchase Price. We paid for the cash portion of the purchase price using a portion of the net proceeds from the sale of the Notes. We issued the Preferred Stock to Eagle in a private issuance exempt from registration under Section 4(2) of the Securities Act and Rule 506 of Regulation D. See the Form 8-K that was filed with the SEC on October 2, 2012.

Item 3. Defaults upon Senior Securities

None.

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Item 4. Mine Safety Disclosures

None.

Item 5. Other Information

None.

Item 6. Exhibits.

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

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SIGNATURES

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

	MIDSTATES PETROLEUM COMPANY, INC.

Dated: November 9, 2012	/s/ John A. Crum
	John A. Crum
	Chief Executive Officer and President

Dated: November 9, 2012	/s/ Thomas L. Mitchell
	Thomas L. Mitchell
	Executive Vice President and Chief Financial Officer

Dated: November 9, 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)
2.2		Asset Purchase Agreement, dated as of August 11, 2012, among Midstates Petroleum Company LLC, Midstates Petroleum Company, Inc. and Eagle Energy Production, LLC (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on August 13, 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)
3.3		Certificate of Designations of Series A Mandatorily Convertible Preferred Stock of Midstates Petroleum Company, Inc. (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on October 2, 2012, and incorporated herein by reference)
4.1		Specimen 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)
4.2		Indenture, dated October 1, 2012, by and among Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC and Wells Fargo Bank, National Association, as trustee, governing the 10.75% Senior Notes due 2020 (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on October 2, 2012, and incorporated herein by reference)
4.3		Registration Rights Agreement, dated October 1, 2012, by and among Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers named therein, relating to the 10.75% Senior Notes due 2020 (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on October 2, 2012, and incorporated herein by reference)
4.4		Registration Rights Agreement, dated October 1, 2012, by and among Midstates Petroleum Company, Inc., Eagle Energy Production, LLC, FR Midstates Interholding, LP and certain other of the Company’s stockholders (filed as Exhibit 4.3 to the Company’s Current Report on Form 8-K filed on October 2, 2012, and incorporated herein by reference)
10.1		Assignment and First Amendment to the Second Amended and Restated Credit Agreement, dated as of September 7, 2012, among Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC, SunTrust Bank as administrative agent, and the other lenders and parties party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 12, 2012, and incorporated herein by reference)
10.2		Amendment to First Amendment to the Second Amended and Restated Credit Agreement, dated as of September 26, 2012, among Midstates Petroleum Company, Inc., Midstates Petroleum Company LLC, SunTrust Bank, as administrative agent, and the other lenders and parties party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 27, 2012, 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