Midstates Petroleum Announces Record Third Quarter 2013 Results

Midstates Petroleum Company, Inc. (NYSE: MPO) today announced its third quarter 2013 financial and operating results.

Third quarter highlights:
  • Average daily production rose 45% to 28,464 net barrels of oil equivalent (“Boe”) per day from 19,634 Boe per day in the second quarter of 2013. Third quarter 2013 included a 751 Boe per day imbalance settlement related to prior period Mississippian Lime production.
  • Cash operating expenses fell significantly to $16.98 per Boe compared to $21.07 per Boe in the second quarter of 2013.
  • Drilling activity reached record levels with 39 wells spud during the quarter and 40 wells brought online. Midstates had 10 rigs active at the end of the quarter.
  • Adjusted EBITDA totaled $101.6 million, a record high, up 90% compared to $53.4 million for the second quarter 2013.
  • Adjusted Net Income totaled a loss of $0.8 million, or $0.01 loss per share, compared with a net loss of $4.2 million, or $0.06 loss per share, in the second quarter of 2013.

John Crum, Chairman, President and CEO, commented, “Our strong growth in production together with an ongoing focus on controlling operating costs yielded record results for the third quarter. Exceeding $100 million in adjusted EBITDA for the first time was a significant milestone for us and is indicative of the growth we can achieve with our expanded asset base. We have more than doubled our production in the Mississippian Lime properties since their acquisition in October 2012 and are experiencing encouraging results in our new Anadarko Basin assets. We believe our ramped-up drilling program will drive further growth for the balance of 2013 and into next year.”

Financial Discussion

(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.)

Adjusted EBITDA totaled $101.6 million in the third quarter of 2013, up significantly from $32.7 million in the third quarter of 2012 and $53.4 million (which was reduced by $11.5 million of acquisition and transaction costs) in the second quarter of 2013.

The GAAP net loss of $23.6 million (before preferred dividends) for the third quarter of 2013 compares to a net loss of $17.8 million for the third quarter of 2012 and net income of $3.3 million in the second quarter of 2013. Adjusted Net Income, which excludes acquisition and transaction costs and unrealized gains and losses on derivatives and the related tax impact, totaled a loss of $0.8 million for the third quarter of 2013, or $0.01 per share.

Production and Prices

Production during the third quarter of 2013 increased to 28,464 Boe per day compared to 8,182 Boe per day during the prior year third quarter, and 19,634 Boe per day in the second quarter of 2013. Third quarter 2013 production from the Company’s Mid-Continent properties (including the Anadarko Basin properties) averaged 22,768 Boe per day while Gulf Coast properties contributed the balance of 5,696 Boe per day. Average daily production for the third quarter of 2013 includes a 751 Boe per day imbalance settlement related to prior period Mississippian Lime natural gas production. The Mississippian Lime properties, including the imbalance of 751 Boe per day, contributed roughly 50%, or 14,364 Boe per day, comprised of 35% oil and 21% natural gas liquids (“NGLs”). The Anadarko Basin properties contributed roughly 30%, or 8,404 Boe per day, comprised of 44% oil and 23% NGLs. For the total Company, oil volumes comprised 44% of total production, NGLs 21%, and natural gas 35%.

In the third quarter of 2013, Midstates' average realized price per barrel of oil, before realized commodity derivatives, was $104.51 ($93.56 with realized derivatives) while its average realized price for NGL sales, before realized derivatives, was $35.13 per barrel ($35.77 with realized derivatives). Natural gas averaged $3.33 per thousand cubic feet, before realized derivatives ($3.72 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, before the impact of derivatives, increased by $97.3 million or 164% to $156.8 million during the third quarter of 2013 as compared to $59.5 million for the third quarter of 2012, and by $53.7 million, or 52%, compared to $103.1 million in the second quarter of 2013. The realized loss on derivatives for the third quarter of 2013 was $9.9 million compared to realized losses of $4.2 million for the third quarter of 2012 and $1.1 million for the second quarter of 2013.

Costs and Expenses

Total Cash Operating Expenses decreased 19% quarter-over-quarter to $16.98 per Boe (excluding the impact of acquisition and transaction costs). This reduction was driven by cost efficiencies and production growth as discussed above. Total Cash Operating Expenses represent Midstates’ true cash cost of operations which excludes asset retirement accretion, share based compensation, depreciation, depletion and amortization expense, and any other non-cash charges.

Including those non-cash costs, total unit costs decreased quarter-over-quarter by $5.38 per Boe or 10% led by decreases in general and administrative expense (-38%), severance and other taxes (-16%), lease operating and workover expense (-15%) and depreciation, depletion and amortization expense (-3%). The only increase was in gathering and transportation, a new expense in this quarter of $2.6 million attributable to the commencement of an amended gas transportation, gathering and processing contract in the Mississippian Lime region.

Lease operating and workover expenses decreased $1.51 per Boe to $8.32 per Boe from the second quarter of 2013. The decrease was the result of cost savings from investments beginning early in the year to reduce salt water disposal costs in the Gulf Coast region and in the Mississippian Lime area, the migration from more costly diesel fired electricity generators to natural gas generators in areas where the local electrical grid is unstable or becomes taxed, and the 45% increase in production.

General and administrative expenses decreased $3.24 per Boe to $5.31 or $1.4 million from the second quarter of 2013. Third quarter 2013 and second quarter 2013 general and administrative expenses included non-cash share-based compensation expense of $1.9 million ($0.73 per Boe) and $1.8 million ($0.99 per Boe), respectively.

Interest expense of $26 million (after amounts capitalized) for the third quarter of 2013 compares to $16.6 million in the second quarter of 2013. The increase relates to three months of interest expense attributable to the $700 million of 9.25% senior notes issued on May 31, 2013 as part of the Anadarko Basin property acquisition. The Company capitalized $9.7 million in interest to unproved properties during the third quarter of 2013 as compared to $7.9 million in the second quarter of 2013.

Liquidity and Capital Investment

On September 26, 2013, the Company’s revolving credit facility was amended to increase the borrowing base from $425 million to $500 million as part of the regular semi-annual borrowing base redetermination. On September 30, 2013, liquidity was $219 million, consisting of $194 million of available borrowing capacity under the revolving credit facility and $25 million of cash and cash equivalents.

During the three and nine months ended September 30, 2013, the Company incurred capital expenditures of $172.5 million and $454.7 million, respectively, consisting of (in thousands):
             

For the ThreeMonths EndedSeptember 30,2013

For the NineMonths EndedSeptember 30,2013
Drilling and completion activities $ 142,167 $ 388,744
Acquisition of acreage and seismic data 11,225 27,594
Facilities and other 9,445 13,770
Capitalized interest   9,675   24,590
Total capital expenditures incurred $ 172,512 $ 454,698
 

Excluding capitalized interest, drilling and completion costs incurred in the various areas totaled (in thousands):
             

For the ThreeMonths EndedSeptember 30,2013

For the NineMonths EndedSeptember 30,2013
Gulf Coast $ 23,712 $ 142,028
Mid-Continent:
Mississippian Lime 104,756 246,682
Anadarko   31,714   37,412
$ 160,182 $ 426,122
 

Mississippian Lime Update

During the third quarter, the Company had five rigs drilling in its Mississippian Lime horizontal well program in Woods and Alfalfa Counties, Oklahoma. Midstates completed a total of 29 horizontal wells, and spud a total of 22 gross wells, of which 11 were producing, seven were awaiting completion and four were drilling at September 30, 2013.

Production from the Company’s Mississippian Lime properties grew 39% from the second quarter of 2013, as the Company began to realize the benefits of reduced downtime from its investments to improve the reliability of the electric and salt water disposal infrastructure. The Company continued building on improvements such as pad drilling, rotary steerables and optimizing drilling and completion techniques. Midstates expects to see spikes in production as a large number of wells are drilled off pads and are brought online in groups, but will also see periods with fewer completions, resulting in some quarter to quarter variability in production growth.

Midstates plans to run five rigs in the Mississippian Lime during the fourth quarter and invest approximately $85 million completing wells drilled during the third quarter and drilling 20 to 25 new wells.

Midstates said it remains pleased with its Mississippian Lime production growth and sees continuing improvement in cash flow over the coming quarters. The Company now has 115 wells that have been on production for more than 30 days and have an average 30-day initial production rate of 570 Boe per day.

Anadarko Basin Update

In the Anadarko Basin area, there were three operated rigs at the beginning of the third quarter, with a fourth rig added in July and a fifth rig added in August. The Company completed a total of 10 horizontal wells during the third quarter, nine of which targeted the Cleveland and one targeting the Marmaton formation. A total of 16 gross wells were spud during the period, of which six were producing, five were awaiting completion and five were drilling at September 30, 2013.

Midstates is pleased with the initial Anadarko Basin horizontal program performance and is drilling several different horizons within the area. Since assuming control on May 31, 2013, the Company has drilled 14 Cleveland wells, three Marmaton wells, one Tonkawa well and one Cottage Grove well. Midstates now has 11 Cleveland wells that have been on production for more than 30 days and have an average 30-day initial production rate of 387 Boe per day.

The Company intends to operate five rigs during the fourth quarter in the Anadarko Basin and invest approximately $45 million completing wells and drilling 18 to 20 new wells.

At September 30, 2013, Midstates had 236,861 net acres under lease in the Mid-Continent region, comprised of approximately 88,359 net leased acres in the Mississippian Lime (82,694 in Woods and Alfalfa Counties in Oklahoma and 5,665 acres in Kansas), 13,243 in the Hunton in Lincoln County, Oklahoma, and 135,259 acres in the Anadarko Basin (89,161 acres in Texas and 46,098 acres in Oklahoma).

Gulf Coast Update

Midstates completed the Musser Davis 27 HC-1 well in South Bearhead Creek on September 10, 2013. The 30-day initial production rate of this well was 779 Boe per day (79% oil/7% NGLs). The well is currently producing at restricted rates of 483 Boe per day with a flowing tubing pressure of 1,300 psi. The Wood 10H-1 sidetrack at North Coward’s Gully was drilled in the third quarter and came online in early October. The well is currently producing at restricted rates of about 375 Boe per day with a flowing tubing pressure of 2,300 psi. Midstates said that these wells are being flowed back at restrictive rates below maximum capacity to reduce the potential for well integrity issues as seen in the past.

As previously discussed, the Company is taking a measured approach to the development of its horizontal programs in North Coward’s Gully and South Bearhead Creek. In Pine Prairie and Fleetwood, the Company is continuing to study the results of the recently acquired 3-D data to high grade locations and build inventory for the future.

At September 30, 2013, the Company had approximately 111,050 net acres under lease or option in the Gulf Coast region, comprised of 60,000 net leased acres and 51,050 net optioned acres.

John Crum, Chairman, President and CEO commented, “We drilled and completed a record number of wells during the third quarter and currently have 10 rigs active. As our activity level has increased, our operations team has made great progress in achieving operating efficiencies in our drilling program across our properties. As evidenced by recent results, we continue to be focused on production growth, cost control and extracting value from our diversified asset base.”

Conference Call Information

The Company will host a conference call to discuss third quarter results on Wednesday, November 13 th 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 59342085 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 November 20 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 59342085 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 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 acquisitions; 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; weather-related downtime; 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.

Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

           
Midstates Petroleum Company, Inc.
Consolidated Balance Sheets
(In thousands, except share amounts)

(Unaudited)
 
September 30, 2013 December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 24,953 $ 18,878
Accounts receivable:
Oil and gas sales 88,216 35,618
Joint interest billing 28,985 10,815
Other 2,844 3,866
Commodity derivative contracts 3,783 5,695
Deferred income taxes 16,196 6,027
Other current assets   691     8,573  
Total current assets 165,668 89,472
 
PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of full-cost accounting 2,914,422 1,836,664
Other property and equipment 10,029 5,038
Less accumulated depreciation, depletion, and amortization   (443,852 )   (274,294 )
Net property and equipment 2,480,599 1,567,408
 
OTHER ASSETS:
Commodity derivative contracts 300 1,717
Other noncurrent assets   57,903     25,413  
Total other assets 58,203 27,130
   
TOTAL $ 2,704,470   $ 1,684,010  
 
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable $ 34,686 $ 29,196
Accrued liabilities 198,695 98,649
Commodity derivative contracts   28,463     7,582  
Total current liabilities 261,844 135,427
 
LONG-TERM LIABILITIES:
Asset retirement obligations 23,178 15,245
Commodity derivative contracts 6,730 3,943
Long-term debt 1,606,150 694,000
Deferred income taxes 149,991 156,737
Other long-term liabilities   1,862     1,189  
Total long-term liabilities 1,787,911 871,114
 
COMMITMENTS AND CONTINGENCIES
 
STOCKHOLDERS' EQUITY

Preferred stock, $0.01 par value, 49,675,000 shares authorized; no shares issued or outstanding
- -

Series A mandatorily convertible preferred stock, $0.01 par value, $351,520 and $325,000 liquidation value, at September 30, 2013 and December 31, 2012, respectively; 8% cumulative dividends; 325,000 shares issued and outstanding
3 3

Common stock, $0.01 par value, 300,000,000 shares authorized; 68,686,256 shares issued and 68,579,198 outstanding at September 30, 2013 and 66,619,711 shares issued and outstanding at December 31, 2012
686 666
Treasury stock (605 ) -
Additional paid-in-capital 869,939 863,891
Retained deficit   (215,308 )   (187,091 )
Total stockholders' equity 654,715 677,469
   
TOTAL $ 2,704,470   $ 1,684,010  
 
           
Midstates Petroleum Company, Inc.
Consolidated Statements of Operations
(In thousands, except per share amounts)
(Unaudited)
 
For the Three Months

Ended September 30,
For the Nine Months

Ended September 30,
2013     2012 2013     2012
REVENUES:
Oil sales $ 119,049 $ 53,143 $ 268,903 $ 146,281
Natural gas liquid sales 18,939 4,134 39,656 14,307
Natural gas sales 18,775 2,257 42,034 8,086
Losses on commodity derivative contracts — net (45,296 ) (33,726 ) (42,999 ) (10,249 )
Other   38     124     941     331  
 
Total revenues 111,505 25,932 308,535 158,756
 
EXPENSES:
Lease operating and workover 21,784 6,569 53,230 18,957
Gathering and transportation 2,583 - 2,583 -
Severance and other taxes 8,080 6,450 20,614 18,098
Asset retirement accretion 421 165 988 463
Depreciation, depletion, and amortization 74,789 30,692 169,595 86,601
General and administrative 13,911 7,948 40,209 18,966
Acquisition and transaction costs 194 2,675 11,686 2,675
Other   614     -     614     -  
 
Total expenses   122,376     54,499     299,519     145,760  
 
OPERATING INCOME (LOSS) (10,871 ) (28,567 ) 9,016 12,996
 
OTHER INCOME (EXPENSE)
Interest income 7 80 17 229
Interest expense — net of amounts capitalized   (25,950 )   (908 )   (53,438 )   (3,587 )
 
Total other income (expense)   (25,943 )   (828 )   (53,421 )   (3,358 )
 
INCOME (LOSS) BEFORE TAXES (36,814 ) (29,395 ) (44,405 ) 9,638
 
Income tax benefit (expense)   13,208     11,592     16,188     (157,326 )
 
NET LOSS $ (23,606 ) $ (17,803 ) $ (28,217 ) $ (147,688 )
 
Preferred stock dividend (2,569 ) - (9,254 ) -
Participating securities - Series A Preferred Stock - - - -
Participating securities - Non-vested Restricted Stock - - - -
 

NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS
$ (26,175 ) $ (17,803 ) $ (37,471 ) $ (147,688 )
 
Basic and diluted net loss per share attributable to common shareholders $ (0.40 ) $ (0.27 ) $ (0.57 ) $ (2.54 )
Basic and diluted weighted average number of common shares outstanding   65,821     65,634     65,740     58,080  
 

(1)

Includes $9.9 million and $4.2 million of realized losses on commodity derivatives for the three months ended September 30, 2013 and 2012, respectively. Includes $16.0 million and $15.8 million of realized losses on commodity derivatives for the nine months ended September 30, 2013 and 2012, respectively.
 
           
Midstates Petroleum Company, Inc.
Statement of Stockholders’ Equity
(In thousands, except share amounts)
(Unaudited)
 
Series A

Preferred Stock
Common Stock Treasury Stock Additional

Paid-in-Capital
Retained Deficit

Total

Stockholders'

Equity
Balance as of December 31, 2012 $ 3 $ 666 $ - $ 863,891 $ (187,091 ) $ 677,469
Share-based compensation - 20 - 6,048 - 6,068
Acquisition of treasury stock - - (605 ) - - (605 )
Net loss   -   -   -     -   (28,217 )   (28,217 )
Balance as of September 30, 2013 $ 3 $ 686 $ (605 ) $ 869,939 $ (215,308 ) $ 654,715  
 
     
Midstates Petroleum Company, Inc.
Consolidated Statement of Cash Flows
(In thousands)
(Unaudited)
 

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,
2013   2012 2013   2012
 
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss $ (23,606 ) $ (17,803 ) $ (28,217 ) $ (147,688 )
Adjustments to reconcile net loss to net cash provided by operating activities:
Unrealized (gains) losses on commodity derivative contracts, net 35,369 29,566 26,997 (5,591 )
Asset retirement accretion 421 165 988 463
Depreciation, depletion, and amortization 74,789 30,692 169,595 86,601
Share-based compensation, net of amounts capitalized to oil and gas properties 1,907 886 4,921 1,568
Deferred income taxes (13,208 ) (11,592 ) (16,188 ) 157,326
Amortization of deferred financing costs 1,892 207 4,156 583
Change in operating assets and liabilities:
Accounts receivable — oil and gas sales (26,566 ) (3,822 ) (52,598 ) 1,193
Accounts receivable — JIB and other (5,805 ) 82 (13,544 ) 2,954
Other current and noncurrent assets (475 ) (56 ) (2,622 ) (3,547 )
Accounts payable 1,519 1,866 (3,027 ) (1,211 )
Accrued liabilities 60,949 4,522 89,666 2,151
Other   (85 )   4     (186 )   (122 )
 
Net cash provided by operating activities $ 107,101 $ 34,717 $ 179,941 $ 94,680
 
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment $ (177,937 ) $ (100,630 ) $ (437,521 ) $ (284,875 )
Investment in acquired property   -     -     (621,748 )   -  
 
Net cash used in investing activities $ (177,937 ) $ (100,630 ) $ (1,059,269 ) $ (284,875 )
 
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings $ 85,000 $ 64,600 $ 946,450 $ 84,667
Repayment of long-term borrowings - - (34,300 ) (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 - (252 ) - 213,587
Deferred financing costs (1,496 ) (5,450 ) (26,142 ) (7,562 )
Repurchase of common stock   -     -     (605 )   -  
 
Net cash provided by financing activities $ 83,504 $ 58,898 $ 885,403 $ 187,525
 
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS 12,668 (7,015 ) 6,075 (2,670 )
 
Cash and cash equivalents, beginning of period   12,285     11,689     18,878     7,344  
 
Cash and cash equivalents, end of period $ 24,953   $ 4,674   $ 24,953   $ 4,674  
 
         
Midstates Petroleum Company, Inc.
Selected Financial and Operating Statistics
(Unaudited)
 
For the

Three Months Ended

September 30,
For the

Nine Months Ended

September 30,

For the

Three Months Ended

June 30,
2013   2012 2013   2012   2013
PRODUCTION DATA - Gulf Coast:
Oil (Boe/day) 3,611 5,537 4,064 4,969 4,075
Natural gas liquids (Boe/day) 973 1,267 1,013 1,248 1,089
Natural gas (Mcf/day) 6,677 8,261 7,469 11,419 8,257
Oil equivalents (MBoe) 524 753 1,726 2,225 595
Average daily production (Boe/day) 5,696 8,182 6,322 8,120 6,540
 
PRODUCTION DATA - Mid-Continent (Mississippian):
Oil (Boe/day) 5,081 - 3,975 - 3,404
Natural gas liquids (Boe/day) 2,959 - 2,283 - 1,776
Natural gas (Mcf/day) 37,943 - 31,074 - 31,476
Oil equivalents (MBoe) 1,322 - 3,122 - 949
Average daily production (Boe/day) 14,364 - 11,437 - 10,426
 
PRODUCTION DATA - Mid-Continent (Anadarko):
Oil (Boe/day) 3,690 - 1,666 - 1,268
Natural gas liquids (Boe/day) 1,928 - 834 - 555
Natural gas (Mcf/day) 16,716 - 7,325 - 5,075
Oil equivalents (MBoe) 773 - 1,016 - 243
Average daily production (Boe/day) 8,404 - 3,721 - 2,668
 
PRODUCTION DATA - Combined:
Oil (Boe/day) 12,382 5,537 9,705 4,969 8,747
Natural gas liquids (Boe/day) 5,860 1,267 4,130 1,248 3,419
Natural gas (Mcf/day) 61,336 8,261 45,867 11,419 44,808
Oil equivalents (MBoe) 2,619 753 5,864 2,225 1,787
Average daily production (Boe/day) 28,464 8,182 21,480 8,120 19,634
 
AVERAGE SALES PRICES:
Oil, without realized derivatives (per Bbl) $ 104.51 $ 104.32 $ 101.49 $ 107.43 $ 97.54
Oil, with realized derivatives (per Bbl) $ 93.56 $ 96.15 $ 93.88 $ 95.80 $ 94.86
Natural gas liquids, without realized derivatives (per Bbl) $ 35.13 $ 35.46 $ 35.17 $ 41.84 $ 35.34
Natural gas liquids, with realized derivatives (per Bbl) $ 35.77 (2 ) $ 36.36 (2 ) $ 37.41
Natural gas, without realized derivatives (per Mcf) $ 3.33 $ 2.97 $ 3.36 $ 2.58 $ 3.55
Natural gas, with realized derivatives (per Mcf) $ 3.72 (2 ) $ 3.58 (2 ) $ 3.65
 
COSTS AND EXPENSES (PER BOE OF PRODUCTION)
Lease operating and workover $ 8.32 $ 8.72 $ 9.08 $ 8.52 $ 9.83
Gathering and transportation $ 0.99 $ - $ 0.44 $ - $ -
Severance and other taxes $ 3.09 $ 8.57 $ 3.52 $ 8.13 $ 3.68
Asset retirement accretion $ 0.16 $ 0.22 $ 0.17 $ 0.21 $ 0.18
Depreciation, depletion, and amortization $ 28.56 $ 40.76 $ 28.92 $ 38.92 $ 29.56
General and administrative (1) $ 5.31 $ 10.56 $ 6.86 $ 8.52 $ 8.55
Acquisition and transaction costs $ 0.07 $ 3.55 $ 1.99 $ 1.20 $ 6.43
Other $ 0.23 $ - $ 0.10 $ - $ -
 

(1)

Includes $0.73, $1.18, $0.84 and $0.70 per Boe for share-based compensation for the three months ended September 30, 2013, the three months ended September 30, 2012, the nine months ended September 30, 2013 and the nine months ended September 30, 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 September 30, 2013
(including any new hedges entered into through November 12, 2013)
(Unaudited)
 

Fourth

Quarter

2013
2014 2015
 
 
Oil (Bbls):
WTI Swaps
Hedged Volume 1,086,120 4,344,450 1,820,000
Hedged Volume (BPD) 11,806 11,903 4,986
Weighted Average Fixed Price (per Bbl) $ 94.32 $ 88.76 $ 86.55
 
WTI Collars
Hedged Volume 50,751 164,400
Hedged Volume (BPD) 552 450
Weighted Average Floor ($/BBL) $ 85.27 $ 88.49
Weighted Average Ceiling ($/BBL) $ 100.70 $ 97.94
 
WTI to LLS Basis Differential Swaps (1)
Hedged Volume 330,760 501,000
Hedged Volume (BPD) 3,595 1,373
Weighted Average Differential (per Bbl) $ 5.80 $ 5.35
 
Gas (Mmbtus):
Natural Gas Swaps (2)
Hedged Volume (MMBTU) 3,680,000 9,125,000
Hedged Volume (MMBTU/D) 40,000 25,000
Weighted Average Fixed Price (MMBTU) $ 4.09 $ 4.23
 
Natural Gas Collars
Hedged Volume (MMBTU) 558,249 1,685,004
Hedged Volume (MMBTU/D) 6,068 4,616
Weighted Average Floor ($/MMBTU) $ 3.68 $ 3.99
Weighted Average Ceiling ($/MMBTU) $ 4.91 $ 5.09
 
NGL's (Bbls):
NGL Swaps
Hedged Volume 64,500 151,500
Hedged Volume (BPD) 701 415
Weighted Average Fixed Price (per Bbl) $ 63.42 $ 62.16
 

(1)

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

(2)

Includes 1,240,000 Mmbtus in natural gas swaps that priced during the period, but had not cash settled by September 30, 2013.
 

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 September 30,
For the Nine Months

Ended September 30,

For the Three MonthsEnded June 30,
2013   2012 2013   2012     2013
Adjusted EBITDA reconciliation to net income (loss):
Net income (loss) $ (23,606 ) $ (17,803 ) $ (28,217 ) $ (147,688 ) $ 3,338
Depreciation, depletion and amortization 74,789 30,692 169,595 86,601 52,830
(Gains)/losses on commodity derivative contracts - net 45,296 33,726 42,999 10,249 (22,421 )
Realized losses on derivative contracts - net (9,927 ) (4,160 ) (16,002 ) (15,840 ) (1,071 )
Income tax expense (benefit) (13,208 ) (11,592 ) (16,188 ) 157,326 1,993
Interest income (7 ) (80 ) (17 ) (229 ) (5 )
Interest expense, net of amounts capitalized 25,950 908 53,438 3,587 16,621
Asset retirement obligation accretion 421 165 988 463 313
Share-based compensation, net of amounts capitalized   1,908     886     4,921     1,568     1,770  
 
Adjusted EBITDA $ 101,616 $ 32,742 $ 211,517 $ 96,037 $ 53,368
 
Adjusted EBITDA reconciliation to net cash provided by operating activities:
Net cash provided by operating activities 107,101 34,717 179,941 94,680 10,637
Changes in working capital (29,536 ) (2,596 ) (17,689 ) (1,418 ) 27,395
Interest income (7 ) (80 ) (17 ) (229 ) (5 )
Interest expense, net of amounts capitalized and accrued but not paid 25,950 908 53,438 3,587 16,621
Amortization of deferred financing costs   (1,892 )   (207 )   (4,156 )   (583 )   (1,280 )
 
Adjusted EBITDA $ 101,616 $ 32,742 $ 211,517 $ 96,037 $ 53,368
 

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 September 30,
For the Nine Months

Ended September 30,

For the Three MonthsEnded June 30,
2013   2012 2013   2012     2013
 
Net income (loss) - GAAP $ (23,606 ) $ (17,803 ) $ (28,217 ) $ (147,688 ) $ 3,338
Adjustments for certain non-cash items:

Unrealized mark-to-market (gains) losses on commodity derivative contracts
35,369 29,566 26,997 (5,591 ) (23,492 )
Deferred tax charge - IPO, corporate reorganization - - - 149,489 -
Acquisition and transaction costs 194 2,675 11,686 2,675 11,492
 
Tax impact (1)   (12,759 )   (12,702 )   (14,102 )   2,372     4,486  
         
Adjusted net income (loss) - non-GAAP $ (802 ) $ 1,736   $ (3,636 ) $ 1,257   $ (4,176 )
 

(1)

The tax impact is computed utilizing the Company’s effective federal and state income tax rates. The income tax rates for the three and nine months ended September 30, 2013 was approximately 35.9% and 36.5%, respectively. 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 September 30,
For the Nine Months

Ended September 30,

For the Three MonthsEnded June 30,
2013     2012 2013     2012     2013
 
Operating Expenses - GAAP $ 122,376 $ 54,499 $ 299,519 $ 145,760 $ 104,061
Adjustments for certain non-cash items:
Asset retirement accretion (421 ) (165 ) (988 ) (463 ) (313 )
Share-based compensation, net of amounts capitalized (1,908 ) (886 ) (4,921 ) (1,568 ) (1,770 )
Depreciation, depletion, and amortization (74,789 ) (30,692 ) (169,595 ) (86,601 ) (52,830 )
Other   (614 )   -     (614 )   -     -  
 
Cash Operating Expenses - Non-GAAP (1) $ 44,644 $ 22,756 $ 123,401 $ 57,128 $ 49,148
Cash Operating Expenses - Non-GAAP, per Boe (1) $ 17.05 $ 30.22 $ 21.04 $ 25.68 $ 27.50
 

(1)

Cash operating expenses include lease operating and workover, gathering and transportation, severance and other taxes, cash portion of general and administrative expenses, and acquisition and transaction costs. During the three and nine months ended September 30, 2013, cash operating expenses include acquisition and transaction costs of $0.2 million ($0.07 per Boe) and $11.7 million ($1.99 per Boe), respectively, attributable to costs incurred during the periods related to the Anadarko Basin Acquisition. During the three months ended June 30, 2013, cash operating expenses included acquisition and transaction costs of $11.5 million ($6.43 per Boe) attributable to the Anadarko Basin Acquisition.

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