Exhibit 99.1

4400 POST OAK PARKWAY SUITE 1900 HOUSTON, TEXAS 77027

PRESS RELEASE FOR IMMEDIATE RELEASE

MIDSTATES PETROLEUM REPORTS FIRST QUARTER 2013

FINANCIAL AND OPERATING RESULTS

HOUSTON— May 6, 2013 — Midstates Petroleum Company, Inc. (NYSE: MPO) (“Midstates” or the “Company”) announced today its financial and operating results for the three months ended March 31, 2013.

Key points include:

· Adjusted EBITDA totaled $56.5 million, up 16% from $48.6 million in the fourth quarter of 2012.

· Adjusted Net Income totaled $1.4 million.

· Average production for the quarter was on track to achieve the top end of guidance of 17,300 barrels of oil equivalent (“Boe”) per day until snowstorms in Oklahoma shut in production, costing the quarter about 1,100 Boe per day. Average daily production for first quarter 2013 rose to 16,208 net Boe per day from 15,592 net Boe per day in the fourth quarter of 2012.

· Cash Operating Expenses were $20.29 per Boe, flat with $20.26 per Boe in the fourth quarter of 2012.

· In early April, Midstates entered into a Purchase and Sale Agreement with Panther Energy, LLC, (“Panther”) to acquire producing properties as well as developed and undeveloped acreage in the Anadarko Basin in Texas and Oklahoma for $620 million in cash. The transaction will be effective April 1, 2013 with closing expected on May 31, 2013, subject to customary closing conditions.

· Midstates now plans to fund the acquisition fully with $700 million of debt and has canceled its plans for an equity offering.

Adjusted EBITDA, Adjusted Net Income and Cash Operating Expenses are non-GAAP financial measures. Each measure is defined and reconciled to the most directly comparable GAAP measure under “Non-GAAP Financial Measures” in the tables below.

John Crum, Midstates’ Chairman, President and CEO commented, “As a result of our continued successful drilling programs in both Oklahoma and Louisiana, we were well on our way to being at or above our production target during the first quarter when we experienced significant but temporary production shut-ins in Oklahoma due to extreme winter weather in February and March. It took a major effort and significant time and cost for our team to get our wells there back on line with impacts on our production into April. Despite the disruption to production, we remain on target to achieve our 2013 production guidance of 24,000 to 26,000 Boe per day in 2013.”

Three Months Ended March 31, 2013 Financial Results

Adjusted EBITDA totaled $56.5 million in the first quarter of 2013, compared to $30.5 million in the first quarter of 2012 and $48.6 million for the fourth quarter of 2012.

The Company reported a net loss of $7.9 million for the first quarter of 2013 as compared to a net loss of $17.5 million for the first quarter of 2012 and a net loss of $2.4 million in the fourth quarter of 2012. The net loss for the first quarter of 2013 includes unrealized losses on derivatives of $15.1 million as well as a non-cash tax benefit of $5.0 million. The fourth quarter 2012 loss included unrealized losses on derivatives of $0.9 million and transaction costs associated with the Eagle Property Acquisition of $12.2 million and a non-cash tax expense of $0.6 million.

Adjusted Net Income, which excludes unrealized losses on derivatives and the related tax impact and is before the impact of Series A Preferred Stock dividends, totaled $1.4 million for the first quarter of 2013.

Production during the first quarter of 2013 increased to 16,208 Boe per day compared to 8,275 Boe per day during the first quarter of 2012, and 15,592 Boe per day in the fourth quarter of 2012. First quarter 2013 production from the Company’s Mid-Continent properties averaged 9,468 Boe per day, or 58% of total production, while Gulf Coast properties contributed the balance of 6,762 Boe per day. Oil volumes comprised 49% of total production, natural gas liquids (“NGLs”) 19%, and natural gas 32% on a Boe basis. In the comparable period of 2012, which included production solely from Midstates’ Gulf Coast properties, oil volumes comprised 54% of production, NGLs 17%, and natural gas 29% on a Boe basis. In the fourth quarter of 2012, oil volumes comprised 51% of production, NGLs 19%, and natural gas 30% on a Boe basis.

In the first quarter of 2013, Midstates’ average realized price per barrel of oil, before realized commodity derivatives, was $101.08 ($93.31 with realized derivatives) while its average realized price for NGL sales, before realized derivatives, was $35.04 per barrel ($36.31 with realized derivatives). Natural gas averaged $3.14 per thousand cubic feet, before realized derivatives ($3.21 with realized derivatives). Detailed comparisons of commodity prices by period and region are included in the tables below.

Oil, NGL and natural gas sales revenues increased by $35.9 million to $90.7 million during the first quarter of 2013 as compared to $54.8 million for the first quarter of 2012, and by $1.3 million compared to $89.4 million in the fourth quarter of 2012. The Company’s net mark-to-market derivative positions moved from unrealized losses of $18.2 million and $0.9 million in the first quarter of 2012 and the fourth quarter of 2012, respectively, to an unrealized loss of $15.1 million in the first quarter of 2013. The realized loss on derivatives for the first quarter of 2013 was $5.0 million compared to a realized loss of $6.5 million for the first quarter of 2012, and an insignificant gain for the fourth quarter of 2012.

Three Months Ended March 31, 2013 Costs and Expenses

Lease operating and workover expenses totaled $13.9 million ($9.51 per Boe), an increase of $2.4 million ($1.46 per Boe) compared to the fourth quarter of 2012. The increase in lease operating and workover expenses per Boe was primarily the result of the winter storm in Oklahoma which resulted in the temporary shut-in of production. There were also higher associated expenses incurred to restore production and repair storm-related damage. In addition, a more active workover program in Oklahoma plus short-term higher salt water disposal and chemical costs in Louisiana contributed to the increase.

Severance and ad valorem taxes as a percentage of oil, NGL and natural gas sales revenue (before derivatives) were 6.6% for the first quarter of 2013 as compared to 7.6% for the fourth quarter of 2012. Severance and ad valorem

taxes decreased primarily due to increased production from the Company’s Mid-Continent assets, which are subject to a lower effective severance tax rate as compared to production from the Gulf Coast area.

Depreciation, depletion and amortization expense (“DD&A”) totaled $42.0 million ($28.77 per Boe), an increase of $3.0 million as compared to $39.0 million ($27.17 per Boe) in the fourth quarter of 2012.

The Company’s general and administrative expenses (before costs associated with the Eagle Property Acquisition) were $11.0 million ($7.56 per Boe) compared to $11.6 million ($8.07 per Boe) for the fourth quarter of 2012. The Company did not incur any acquisition and transaction costs during the first quarter of 2013. For the fourth quarter 2012, acquisition and transaction costs related to the Eagle Property Acquisition totaled approximately $12.2 million ($8.51 per Boe) and represented due diligence, legal and other advisory fees that are required to be currently expensed under US GAAP. First quarter 2013 and fourth quarter 2012 general and administrative expenses included non-cash share-based compensation expense of $1.2 million ($0.85 per Boe) and $0.9 million ($0.62 per Boe), respectively.

Total Cash Operating Expenses (which includes lease operating and workover expenses, severance and ad valorem taxes, and the cash portion of general and administrative expenses, but excludes acquisition and transaction costs related to the Eagle Property Acquisition) were flat at $20.29 per Boe as compared to $20.26 per Boe in the fourth quarter of 2012.

Total interest expense (after amounts capitalized) was $10.9 million for the first quarter of 2013 as compared to $9.4 million in the fourth quarter of 2012. The Company capitalized $7.1 million in interest to unproved properties during the first quarter of 2013 as compared to $8.0 million in the fourth quarter of 2012.

The Company recorded an income tax benefit during the quarter of $5.0 million attributable to the loss during the period, as compared to income tax expense of $0.6 million in the fourth quarter of 2012. The Company does not expect to have a cash income tax liability for the foreseeable future.

Liquidity and Capital Investment

On March 31, 2013, Midstates’ liquidity was $139 million, consisting of $88 million of available borrowing capacity under the Company’s revolving credit facility (which consists of a borrowing base of $285 million) and $51 million of cash and cash equivalents.

During the three months ended March 31, 2013, the Company incurred capital expenditures of $132.8 million, consisting of (in thousands):

	For the Three Months Ended March 31, 2013
Drilling and completion activities	$	116,510
Acquisition of acreage and seismic data	8,236
Facilities and other	995
Capitalized interest	7,054
Total capital expenditures incurred	$	132,795

Excluding capitalized interest, of the $125.7 million spent during the first quarter in 2013, $60.5 million was spent in the Gulf Coast region and $65.2 million was spent in the Mid-Continent region.

Gulf Coast Operations Update

During the three months ended March 31, 2013, Midstates completed a total of seven wells, including five vertical wells at Pine Prairie and two horizontal wells consisting of the McFatter 8H-1 at North Cowards Gully and the AKS 5H-1 at West Gordon. Midstates spud a total of nine gross wells in the region, including three horizontals, during the first quarter of 2013, of which five were producing, three were drilling, and one was awaiting completion.

Gulf Coast horizontal well update since March 31, 2013:

· The Wood 10H-1 well in North Cowards Gully reached a total measured depth of 15,366 feet, with a 3,000 foot lateral targeting the Upper Wilcox “B” Sand. The well has been completed with 10 stages of fracture stimulation and tested at a seven-day average flow rate of 1,250 Boe per day (64% oil). The well cost approximately $9.0 million, an improvement over the previous two wells drilled in the field. This well successfully tested the east side of North Cowards Gully, an area not previously tested with a horizontal well. The Company continues to believe it has the potential for over 20 horizontal drilling locations in the field.

· The Musser Davis 33-28HC-1, spud in February 2013 in South Bearhead Creek and targeting the Lower Wilcox “C” sand, has been drilled to a total depth of 18,156 feet and is currently being completed with 14 stages of fracture stimulation.

· Two additional North Cowards Gully wells have been spud in April 2013, the Musser Davis 8H-2 and the Olympia Minerals 16H-1, both targeting the Upper Wilcox “B” Sand.

At March 31, 2013, Midstates had approximately 141,600 net acres under lease or option in the Gulf Coast region, comprised of approximately 85,900 net leased acres and approximately 55,700 net optioned acres.

For the second quarter of 2013, Midstates currently plans to invest $55 million to $60 million and drill three to four horizontal wells.

Mid-Continent Operations Update

During the first quarter the Company had four rigs active in the Mid-Continent region, all of which were drilling in the Company’s Mississippian Lime horizontal well program in Woods and Alfalfa Counties, Oklahoma. Midstates completed a total of nine wells, all of which were horizontal. Midstates spud a total of 10 gross wells, of which four were producing, five were awaiting completion and one was in process at March 31, 2013. Midstates said that it continues to see results in its Mississippian program that are in line with its expectations at the time of the acquisition.

The Company recently added a fifth rig to the program in Oklahoma and has continued to see drilling improvements. Midstates has seen improvement in its ability to cut cycle time and costs by moving to pad drilling, using point-to-point techniques and optimizing drilling plans.

At March 31, 2013, Midstates had approximately 100,800 net acres under lease in the Mid-Continent region, comprised of approximately 86,000 net leased acres in the Mississippian Lime (80,400 in Woods and Alfalfa Counties in Oklahoma and 5,600 acres in Kansas) and approximately 14,800 in the Hunton in Lincoln County, Oklahoma. The Company acquired approximately 3,300 acres in Oklahoma near its core Mississippian Lime operating area during the first quarter of 2013.

For the second quarter of 2013, Midstates plans to invest $70 million to $80 million in the drilling of 16 to 18 wells.

John Crum, Midstates’ Chairman, President and CEO commented, “Our planned drilling program for 2013 reflects the encouraging results we have achieved across our portfolio. We have added a fifth rig in Oklahoma and continue to achieve improved drilling efficiencies. In Louisiana, we have two follow-up wells drilling in Louisiana in North Cowards Gully and are awaiting results from our first horizontal Wilcox well in South Bearhead Creek. Additionally, when our Panther acquisition closes in late May, we will have three rigs drilling in the Anadarko Basin and expect to invest about $15 million there during the latter part of the second quarter.” Crum continued, “Post-closing, we believe we will have the ideal mix of lower risk to higher potential drilling opportunities that will enable us to build a strong, more stable base of production but still offer significant upside growth. Our focus in 2013 will be executing our planned drilling program across our portfolio of assets as well as the successful integration of the Panther assets and people.”

Conference Call Information

The Company will host a conference call to discuss first quarter results on Tuesday, May 7 at 10:00 am Eastern time. Participants may join the conference call by dialing (877) 645-4610 (for U.S. and Canada) or (707) 595-2723 (International). The conference access code is 58651786 for all participants. To listen via live web cast, please visit the Investor Relations section of the Company’s website, www.midstatespetroleum.com.

An audio replay of the conference call will be available approximately two hours after the conclusion of the call. The audio replay will remain available for seven days until May 14 and can be accessed by dialing (855) 859-2056 (for U.S. and Canada) or (404) 537-3406 (International). The conference call replay access code is 58651786 for all participants. The replay will also be available in the Investor Relations section of the Company’s website approximately two hours after the conclusion of the call and remain available for approximately 90 calendar days.

Forward-Looking Statements

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements that are not statements of historical fact, including statements regarding the Company’s strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management, and the closing, financing and benefits of the acquisition are forward-looking statements. Without limiting the generality of the foregoing, these statements are based on certain assumptions made by the Company based on management’s experience, expectations and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Although the Company believes that its plans, intentions and expectations reflected in or suggested by the forward-looking statements made in this press release are reasonable, the Company gives no assurance that these plans, intentions or expectations will be achieved when anticipated or at all. Moreover, such statements are subject to a number of factors, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These factors include, but are not limited to, the inability of the Company to close the acquisition; costs and difficulties related to the integration of the acquired businesses and operations with Midstates’ business and operations; unexpected costs, charges or expenses resulting from the acquisition; litigation relating to the acquisition; variations in the market demand for, and prices of, oil and natural gas; uncertainties about the Company’s estimated quantities of oil and natural gas reserves; the adequacy of the Company’s capital resources and liquidity including, but not limited to, access to additional borrowing capacity under its revolving credit facility; general economic and business conditions; failure to realize expected value creation from property acquisitions; uncertainties about the Company’s ability to replace reserves and economically develop its current reserves; risks related to the concentration of the Company’s operations. drilling results; and potential financial losses or earnings reductions from the Company’s commodity derivative positions.

Midstates Petroleum Company, Inc.

Consolidated Balance Sheets

(In thousands, except share amounts)

(Unaudited)

	March 31, 2013			December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	50,625		$	18,878
Accounts receivable:
Oil and gas sales	44,620			35,618
Severance tax refund	15,070			10,815
Other	2,407			3,866
Commodity derivative contracts	1,935			5,695
Deferred income taxes	11,517			6,027
Other current assets	9,109			8,573
Total current assets	135,283			89,472

PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of full-cost accounting	1,968,902			1,836,664
Other property and equipment	5,601			5,038
Less accumulated depreciation, depletion, and amortization	(316,270		)	(274,294		)
Net property and equipment	1,658,233			1,567,408

OTHER ASSETS:
Commodity derivative contracts	1,171			1,717
Other noncurrent assets	24,797			25,413
Total other assets	25,968			27,130

TOTAL	$	1,819,484		$	1,684,010

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	6,206		$	29,196
Accrued liabilities	149,368			98,649
Commodity derivative contracts	13,244			7,582
Total current liabilities	168,818			135,427

LONG-TERM LIABILITIES:
Asset retirement obligations	15,706			15,245
Commodity derivative contracts	9,095			3,943
Long-term debt	796,450			694,000
Deferred income taxes	191,142			190,625
Other long-term liabilities	1,148			1,189
Total long-term liabilities	1,013,541			905,002

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS’ EQUITY
Preferred stock, $0.01 par value, 49,675,000 shares authorized, no shares issued or outstanding, respectively	—			—
Series A mandatorily convertible preferred stock, $0.01 par value, $1,040 and $1,000 liquidation value, respectively; 8% cumulative dividends; 325,000 shares issued and outstanding	3			3
Common stock, $0.01 par value, 300,000,000 shares authorized; 68,363,508 and 66,619,711 shares issued and outstanding, respectively	683			666
Additional paid-in-capital	831,479			830,003
Retained deficit/accumulated loss	(195,040		)	(187,091		)
Total stockholders’ equity	637,125			643,581

TOTAL	$	1,819,484		$	1,684,010

Midstates Petroleum Company, Inc.

Consolidated Statements of Operations

(In thousands, except per share amounts)

(Unaudited)

	For the Three Months Ended March 31,
	2013			2012

REVENUES:
Oil sales	$	72,218		$	45,082
Natural gas sales	8,795			3,450
Natural gas liquid sales	9,719			6,272
Losses on commodity derivative contracts — net (1)	(20,124		)	(24,665		)
Other	414			105

Total revenues	71,022			30,244

EXPENSES:
Lease operating and workover	13,871			6,467
Severance and other taxes	5,955			5,376
Asset retirement accretion	254			134
Depreciation, depletion, and amortization	41,976			28,027
General and administrative	11,026			6,064

Total expenses	73,082			46,068

OPERATING INCOME	(2,060		)	(15,824		)

OTHER INCOME (EXPENSE)
Interest income	5			7
Interest expense — net of amounts capitalized	(10,867		)	(1,690		)

Total other income (expense)	(10,862		)	(1,683		)

INCOME BEFORE TAXES	(12,922		)	(17,507		)

Income tax benefit	4,973			—

NET LOSS	$	(7,949	)	$	(17,507	)

Preferred stock dividend	(4,117		)	—

NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(12,066	)	$	(17,507	)


Basic and diluted net loss per share attributable to common shareholders	$	(0.18	)	N/A

Weighted average number of common shares outstanding	65,634			—

(1) Includes $5.0 million and $6.5 million of realized losses on commodity derivatives for the three months ended March 31, 2013 and 2012, respectively.

Midstates Petroleum Company, Inc.

Statement of Stockholders’ Equity

(In thousands, except share amounts)

(Unaudited)

	Common Stock			Preferred Stock
	Number of Shares	Amount		Number of Shares		Amount		Additional Paid- in-Capital		Retained Deficit/ Accumulated Loss			Total Stockholders’ Equity
Balance as of December 31, 2012	66,619,711	$	666	$	325,000	$	3	$	830,003	$	(187,091	)	$	643,581
Share-based compensation	1,743,797	17		—		—		1,476		—			1,493
Net loss	—	—		—		—		—		(7,949		)	(7,949		)
Balance as of March 31, 2013	68,363,508	$	683	325,000		$	3	$	831,479	$	(195,040	)	$	637,125

Midstates Petroleum Company, Inc.

Consolidated Statement of Cash Flows

(In thousands)

(Unaudited)

	For the Three Months Ended March 31,
	2013			2012

CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(7,949	)	$	(17,507	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Unrealized losses on commodity derivative contracts, net	15,120			18,166
Asset retirement accretion	254			134
Depreciation, depletion, and amortization	41,976			28,027
Share-based compensation	1,244			—
Deferred income taxes	(4,973		)	—
Accrued interest on mandatorily redeemable convertible preferred units	—			762
Amortization of deferred financing costs	984			216
Change in operating assets and liabilities:
Accounts receivable — oil and gas sales	(9,002		)	2,877
Accounts receivable — JIB and other	(2,796		)	2,747
Other current assets	(536		)	(2,413		)
Accounts payable	(925		)	161
Accrued liabilities	28,847			1,186
Other	(41		)	(40		)

Net cash provided by operating activities	$	62,203		$	34,316

CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment	(132,538		)	(72,466		)

Net cash used in investing activities	$	(132,538	)	$	(72,466	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings	102,450			—
Proceeds from issuance of mandatorily redeemable convertible preferred units	—			40,000
Deferred financing costs	(368		)	—

Net cash provided by financing activities	102,082			40,000

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	31,747			1,850

Cash and cash equivalents, beginning of period	18,878			10,455

Cash and cash equivalents, end of period	50,625			12,305

Midstates Petroleum Company, Inc.

Selected Financial and Operating Statistics

(Unaudited)

	For the Three Months Ended March 31,					For the Three Months Ended December 31,
	2013		2012			2012
PRODUCTION DATA - Gulf Coast:
Oil (Boe/day)	4,517		4,455			5,737
Natural gas liquids (Boe/day)	977		1,400			1,170
Natural gas (Mcf/day)	7,480		14,523			8,869
Oil equivalents (MBoe)	607		753			771
Average daily production (Boe/day)	6,740		8,275			8,385

PRODUCTION DATA - Mid-Continent:
Oil (Boe/day)	3,422		—			2,216
Natural gas liquids (Boe/day)	2,105		—			1,820
Natural gas (Mcf/day)	23,646		—			19,021
Oil equivalents (MBoe)	852		—			663
Average daily production (Boe/day)	9,468		—			7,207

PRODUCTION DATA - Combined:
Oil (Boe/day)	7,939		4,455			7,954
Natural gas liquids (Boe/day)	3,082		1,400			2,990
Natural gas (Mcf/day)	31,126		14,523			27,890
Oil equivalents (MBoe)	1,459		753			1,434
Average daily production (Boe/day)	16,208		8,275			15,592

AVERAGE SALES PRICES:
Oil, without realized derivatives (per Bbl)	$	101.08	$	111.21		$	98.60
Oil, with realized derivatives (per Bbl)	$	93.31	$	95.18		$	93.65
Natural gas liquids, without realized derivatives (per Bbl)	$	35.04	$	49.23		$	33.84
Natural gas liquids, with realized derivatives (per Bbl)	$	36.31			(2)	$	38.79
Natural gas, without realized derivatives (per Mcf)	$	3.14	$	2.61		$	3.10
Natural gas, with realized derivatives (per Mcf)	$	3.21			(2)	$	3.98

COSTS AND EXPENSES (PER BOE OF PRODUCTION)
Lease operating and workover	$	9.51	$	8.59		$	8.05
Severance and other taxes	$	4.08	$	7.14		$	4.76
Asset retirement accretion	$	0.17	$	0.18		$	0.18
Depreciation, depletion, and amortization	$	28.77	$	37.22		$	27.17
General and administrative (1)	$	7.56	$	8.05		$	8.07
Acquisition and transaction costs	$	—	$	—		$	8.51

(1) Includes $0.85 per Boe for share-based compensation for the three months ended March 31, 2013. There was no share-based compensation recognized for the three months ended March 31, 2012.

(2) The Company did not have hedges in place on its natural gas or NGL production until October 1, 2012.

Midstates Petroleum Company, Inc.

Summary of Commodity Derivative Contracts as of May 6, 2013

(Unaudited)

	Second Quarter 2013		Third Quarter 2013		Fourth Quarter 2013		2014

Oil (Bbls):
WTI Swaps
Hedged Volume	483,460		672,094		672,120		2,425,950
Hedged Volume (BPD)	5,313		7,305		7,306		6,646
Weighted Average Fixed Price (per Bbl)	$	94.70	$	95.01	$	95.65	$	88.98

WTI Collars
Hedged Volume	50,751		50,751		50,751		164,400
Hedged Volume (BPD)	558		552		552		450
Weighted Average Floor ($/Bbl)	$	85.27	$	85.27	$	85.27	$	88.49
Weighted Average Ceiling ($/Bbl)	$	100.70	$	100.70	$	100.70	$	97.94

WTI to LLS Basis Differential Swaps (1)
Hedged Volume	438,970		413,034		330,760		501,000
Hedged Volume (BPD)	4,824		4,490		3,595		1,373
Weighted Average Differential (per Bbl)	$	5.93	$	5.76	$	5.80	$	5.35

Natural Gas Collars
Hedged Volume (MMBTU)	558,249		558,249		558,249		1,685,004
Hedged Volume (MMBTU/D)	6,135		6,068		6,068		4,616
Weighted Average Floor ($/MMBTU)	$	3.68	$	3.68	$	3.68	$	3.99
Weighted Average Ceiling ($/MMBTU)	$	4.91	$	4.91	$	4.91	$	5.09

NGL’s (Bbls):
NGL Swaps
Hedged Volume	64,500		64,500		64,500		151,500
Hedged Volume (BPD)	709		701		701		415
Weighted Average Fixed Price (per Bbl)	$	63.42	$	63.42	$	63.42	$	62.16

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

NON-GAAP FINANCIAL MEASURES

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDA as earnings before interest income, interest expense, income taxes, depreciation, depletion and amortization, property impairments, unrealized commodity derivative gains and losses and non-cash stock-based compensation expense. Adjusted EBITDA is not a measure of net income or cash flows as determined by United States generally accepted accounting principles, or GAAP.

The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively.

Midstates Petroleum Company, Inc.

Adjusted EBITDA

(In thousands)

(Unaudited)

	For the Three Months Ended March 31,						For the Three Months Ended December 31,
	2013			2012			2012
Adjusted EBITDA reconciliation to net loss:
Net loss:	$	(7,949	)	$	(17,507	)	$	(2,410	)
Depreciation, depletion and amortization	41,976			28,027			38,960
Change in unrealized loss on commodity derivative contracts	15,120			18,166			924
Income taxes	(4,973		)	—			561
Interest income	(5		)	(7		)	(15		)
Interest expense - net of amounts capitalized	10,867			1,690			9,411
Asset retirement obligation accretion	254			134			260
Share-based compensation	1,244			—			891

Adjusted EBITDA	$	56,534		$	30,503		$	48,582

Adjusted EBITDA reconciliation to net cash provided by operating activities:
Net cash provided by operating activities	62,203			34,316			42,569
Changes in working capital	(15,547		)	(4,518		)	(2,436		)
Interest income	(5		)	(7		)	(15		)
Interest expense - net of amounts capitalized and accrued but not paid	10,867			928			9,411
Amortization of deferred financing costs	(984		)	(216		)	(947		)

Adjusted EBITDA	$	56,534		$	30,503		$	48,582

NON-GAAP FINANCIAL MEASURES

The following table provides information that the Company believes may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to exclude certain non-cash items. Adjusted net income is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP.

The following table provides a reconciliation of net income (GAAP) to adjusted net income (non-GAAP) (unaudited and in thousands).

	For the Three Months Ended March 31,						For the Three Months Ended December 31,
	2013			2012			2012

Net loss - GAAP	$	(7,949	)	$	(17,507	)	$	(2,410	)
Adjustments for certain non-cash items:
Unrealized mark-to-market loss on commodity derivative contracts	15,120			18,166			924
Deferred tax charge - IPO, corporate reorganization	—			—			—
Acquisition and transaction costs	—			—			12,209

Tax impact (1)	(5,818		)	—			(5,261		)

Adjusted net income - non-GAAP	$	1,353		$	659		$	5,462

(1) The tax impact is computed utilizing the Company’s effective federal and state income tax rates. The income tax rates for the three months ended March 31, 2013 was approximately 38.5%. Prior to April 25, 2012, the Company was not a tax paying entity.

NON-GAAP FINANCIAL MEASURES

The following table provides information that the Company believes may be useful to investors who follow the practice of some industry analysts who adjust operating expenses to exclude certain non-cash items. Cash Operating Expenses is not a measure of operating expenses as determined by United States generally accepted accounting principles, or GAAP.

The following table provides a reconciliation of Operating Expenses (GAAP) to Cash Operating Expenses (non-GAAP) (unaudited and in thousands).

	For the Three Months Ended March 31,						For the Three Months Ended December 31,
	2013			2012			2012

Operating Expenses - GAAP	$	73,082		$	46,068		$	81,368
Adjustments for certain non-cash items:
Asset retirement accretion	(254		)	(134		)	(260		)
Share-based compensation	(1,244		)	—			(891		)
Depreciation, depletion, and amortization	(41,976		)	(28,027		)	(38,960		)

Cash Operating Expenses - Non-GAAP (1)	$	29,608		$	17,907		$	41,257
Cash Operating Expenses - Non-GAAP, per Boe (1)	$	20.29		$	23.78		$	28.77

(1) During the three months ended December 31, 2012, cash operating expenses include acquisition and transaction costs of $12.2 million ($8.51 per Boe), attributable to costs incurred during the period related to the Eagle Property Acquisition.