Exhibit 99.1
4400 POST OAK PARKWAY SUITE 1900 HOUSTON, TEXAS 77027
PRESS RELEASE FOR IMMEDIATE RELEASE
MIDSTATES PETROLEUM REPORTS FOURTH QUARTER AND FULL YEAR 2012
FINANCIAL AND OPERATING RESULTS
HOUSTON— March 5, 2013 — Midstates Petroleum Company, Inc. (NYSE: MPO) (“Midstates” or the “Company”) announced today its financial and operating results for the three months and full year ended December 31, 2012. Midstates’ fourth quarter results were driven by a 91% sequential quarter increase in production, primarily resulting from the successful integration of the Eagle Energy Production, LLC (“Eagle”) property acquisition which closed October 1, 2012.
Highlights include:
· Average daily production rose 91% to 15,592 net barrels of oil equivalent (“Boe”) per day from 8,182 net Boe per day in the third quarter of 2012; production from Mid-Continent operations (which includes Midstates’ Oklahoma and Kansas properties) averaged 7,207 Boe per day while production from Gulf Coast operations (which includes Midstates’ Louisiana properties) averaged 8,385 Boe per day.
· Adjusted EBITDA totaled $48.6 million, up 49% from $32.7 million in the third quarter of 2012. See “Non-GAAP Financial Measures” in the tables below for a definition of Adjusted EBITDA and a reconciliation to net income (loss) and net cash provided by operating activities.
· Adjusted Net Income (which excludes unrealized gains/losses on derivatives and transaction costs associated with the Eagle property acquisition and the related income tax effect) was $5.5 million compared with $1.7 million in the third quarter of 2012. See “Non-GAAP Financial Measures” in the tables below for a definition of Adjusted Net Income and a reconciliation to net income (loss).
· 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 transaction costs associated with the Eagle property acquisition) were reduced 24% to $20.26 per Boe from $26.67 per Boe in the third quarter of 2012. See “Non-GAAP Financial Measures” in the tables below for a definition of Cash Operating Expenses and a reconciliation to Operating Expenses.
· 30 gross wells were spud during the fourth quarter of 2012 and 34 were placed into production. At quarter end, 12 were awaiting completion and seven were drilling. Since December 31, 2012, Midstates has spud 14 additional wells.
· In the North Cowards Gully field, the McFatter 8H-1 was drilled to a total measured depth of 16,870 feet, including a 3,350-foot lateral. The well was completed in the first quarter of 2013 with 10 stages of fracture stimulation and had an initial 14-day IP rate of 1,157 Boe per day comprised of 80% liquids. The McFatter 8H-1 is the first follow up well to the previously announced Musser-Davis 8H-1 drilled during the fall of 2012.
· Year-end 2012 proved reserves increased 188% to 75.5 million barrels of oil equivalent (“MMBoe”) from 26.2 MMBoe at year-end 2011. Organic drilling reserve additions (before revisions to previous reserve estimates) totaled 20.9 MMboe at a cost of $21.48 per Boe, while acquisitions added 35.0 MMBoe at a cost of $19.03 per Boe. All-in finding, development and acquisition costs for 2012 were $21.08 per Boe. See
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“Non-GAAP Financial Measures” in the tables below for a definition of all-in finding, development and acquisition costs.
The following previously-disclosed events occurred during the fourth quarter and were effective October 1, 2012:
· Closing of the Eagle property acquisition for $325 million in cash (before customary post-closing adjustments and adjustments for expenses incurred and revenue received by Eagle since June 1, 2012) and 325,000 shares of Midstates’ Series A Mandatorily Convertible Preferred Stock with an initial liquidation preference value of $1,000 per share.
· Amendment of the Company’s revolving credit facility to increase the borrowing base (subject to semiannual redetermination) to $250 million.
· Closing of the private issuance of $600 million in aggregate principal amount of 10.75% senior unsecured notes (the “Notes”) due 2020. A portion of the net proceeds was used to fund the cash portion of the Eagle property acquisition.
John Crum, Midstates’ Chief Executive Officer and President commented, “Our fourth quarter results clearly reflect the strong positive benefits of production from and drilling on the Mississippian Lime properties that were acquired effective October 1, 2012, as well as successful drilling in Louisiana. The newly acquired properties and the Eagle staff are being quickly integrated into Midstates and we are very pleased with the better-than-expected results we are experiencing. Our cash operating expenses on a Boe basis fell 24% reflecting the higher production volumes as well as lower overall costs associated with our newly acquired assets. We are likewise very pleased with our 188% proved reserve growth in 2012 which was driven by the Eagle property acquisition as well as strong organic growth from our successful drilling programs in both Louisiana and Oklahoma.”
Three Months Ended December 31, 2012 Financial Results
Adjusted EBITDA totaled $48.6 million in the fourth quarter of 2012, compared to $47.5 million in the fourth quarter of 2011 and $32.7 million for the third quarter of 2012. See “Non-GAAP Financial Measures” in the tables below for a description of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income (loss) and net cash provided by operating activities.
The Company reported a net loss of $2.4 million, or $0.04 per share, in the fourth quarter of 2012 as compared to a net loss of $39.3 million in the fourth quarter of 2011 and a net loss of $17.8 million in the third quarter of 2012. The net loss for the fourth quarter of 2012 includes unrealized losses on derivatives of $0.9 million as well as 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 gains and losses on derivatives as well as transaction costs associated with the Eagle property acquisition and the related tax impact of each, was $5.5 million in the fourth quarter of 2012 compared with a loss of $16.6 million in the fourth quarter of 2011 and income of $1.7 million in the third quarter of 2012. See “Non-GAAP Financial Measures” in the tables below for a reconciliation of Adjusted Net Income to net income (loss).
Production during the fourth quarter of 2012 increased 65% to 15,592 Boe per day compared to 9,433 Boe per day produced during the fourth quarter of 2011, and 91% compared with 8,182 Boe per day in the third quarter of 2012. Fourth quarter 2012 production from Midstates’ Mid-Continent properties averaged 7,207 Boe per day, or 46% of total production, while Gulf Coast properties contributed the balance of 8,385 Boe per day. Oil volumes comprised 51% of production, NGLs 19%, and natural gas 30% on a Boe basis. In the comparable period of 2011, oil volumes
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comprised 54% of production, NGLs 12%, and natural gas 34%. Prior to the fourth quarter of 2012, all of Midstates’ production was from its Gulf Coast properties.
Midstates’ average realized price per barrel of oil, before realized commodity derivatives, was $98.60 ($93.65 with realized derivatives) in the fourth quarter of 2012 as compared to $115.46 ($105.77 with realized derivatives) for the fourth quarter of 2011, and $104.32 ($96.15 with realized derivatives) in the third quarter of 2012. The Company’s average realized price for NGL sales, before realized commodity derivatives, was $33.84 per barrel ($38.79 with realized derivatives) in the fourth quarter of 2012 as compared to $35.46 in the third quarter of 2012. Natural gas averaged $3.10 per mcf, before realized commodity derivatives ($3.98 with realized derivatives) in the fourth quarter of 2012 compared to $2.97 per mcf in the third quarter of 2012. During the comparable period of 2011, Midstates’ average realized price for NGL sales was $57.08 per barrel and natural gas averaged $3.32 per mcf. The Company did not have hedges in place on its natural gas or NGL production prior to October 1, 2012.
Oil, natural gas and NGL sales revenues increased 35% or $23.2 million to $89.4 million during the fourth quarter of 2012 as compared to $66.2 million for the fourth quarter of 2011, and by 50% or $29.9 million compared to $59.5 million in the third quarter of 2012. The Company’s net mark-to-market derivative positions moved from unrealized losses of $22.7 million and $29.6 million in the fourth quarter of 2011 and the third quarter of 2012, respectively, to an unrealized loss of $0.9 million in the fourth quarter of 2012. The realized position for the fourth quarter of 2012 moved to an insignificant gain compared to a realized loss of $4.6 million for the fourth quarter of 2011, and a realized loss of $4.2 million for the third quarter of 2012.
Three Months Ended December 31, 2012 Costs and Expenses
Lease operating and workover expenses totaled $11.5 million, or $8.05 per Boe, compared with $6.6 million, or $8.72 per Boe, in the third quarter of 2012. These amounts reflect the inclusion of the Eagle properties effective October 1, 2012 which have, on average, lower operating costs than our Gulf Coast properties.
Severance and ad valorem taxes increased $0.3 million to $6.8 million from $6.5 million in the third quarter of 2012. Severance and ad valorem taxes as a percentage of oil, natural gas and NGL sales revenue (before derivatives) declined to 7.6% for the fourth quarter of 2012 as compared to 10.8% for the third quarter of 2012, primarily due to the lower effective Oklahoma severance tax rate on production volumes added from the Eagle property acquisition as well as lower ad valorem taxes in Oklahoma versus those assessed on our Gulf Coast properties.
The Company’s general and administrative expenses (before transaction costs associated with the Eagle property acquisition) were $11.6 million or $8.07 per Boe, compared to $7.9 million or $10.56 per Boe, for the third quarter of 2012. Fourth quarter general and administrative expenses included non-cash share-based compensation expense of $0.9 million or $0.62 per Boe. Transaction costs associated with the Eagle property acquisition totaled approximately $12.2 million, or $8.51 per Boe, and represent advisory, due diligence, legal and other fees that are required to be expensed under US GAAP.
Total cash operating costs (which includes lease operating and workover expenses, severance and ad valorem taxes, and the cash portion of general and administrative expenses, but excludes transaction costs associated with the Eagle property acquisition) decreased 24% to $20.26 per Boe from $26.67 per Boe in the third quarter of 2012. See “Non-GAAP Financial Measures” in the tables below for a definition of Cash Operating Expenses and reconciliation to Operating Expenses.
Depreciation, depletion and amortization expense (“DD&A”) totaled $39.0 million compared with $30.7 million in the third quarter of 2012. The DD&A rate for the fourth quarter of 2012 fell to $27.17 per Boe compared to $40.76
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per Boe in the 2012 third quarter due to the lower relative cost of the proved reserves acquired in the Eagle property acquisition and the impact of the increase in net proved reserves during 2012 associated with Midstates’ successful drilling program in both Louisiana and Oklahoma.
Total interest expense (after amounts capitalized) was $9.4 million for the fourth quarter of 2012 versus $0.9 million in the third quarter of 2012. The Company capitalized $8.0 million in interest to unproved properties during the fourth quarter of 2012. The increase in interest expense was related to the Company’s 10.75% Notes issued on October 1, 2012.
The Company recorded income tax expense during the quarter of $0.6 million, as compared to income tax benefit of $11.6 million in the third quarter of 2012. Excluding the effect of the tax charge related to the Company’s reorganization in connection with its initial public offering, the effective tax rate for the year was 40%. The Company does not expect to have a cash income tax liability for the foreseeable future.
Year-end 2012 Proved Reserves
Midstates grew its year-end 2012 reserves to 75.5 MMBoe, up 188% from 26.2 MMBoe at year-end 2011. Year-end 2012 reserves were comprised of 50% oil, 19% NGLs and 31% natural gas. Of the total reserves, 37% are proved developed. Geographically, 36.8 MMBoe are in Louisiana, a 40% increase over 2011 year-end reserves, and 38.7 MMBoe are in Oklahoma. Midstates operates 94% of its reserves and improved its reserve life at year-end 2012 to 13.3 years using year-end 2012 proved reserves divided by annualized fourth quarter 2012 production rates.
During 2012, extensions, discoveries and other additions added 20.9 MMBoe, reflecting organic reserve replacement of 572% of 2012 production. The Eagle property acquisition added 35.0 MMBoe of proved reserves. At year-end 2012, Oklahoma reserves totaled 38.7 MMBoe comprised of 38% oil, 22% NGLs, and 40% natural gas. All-in, including acquisitions, drill-bit additions and revisions, the Company replaced 1,446% of total 2012 production. Midstates’ reserves were fully engineered by its third-party reserve engineers, Netherland Sewell and Associates.
| | Oil | | NGL | | Gas | | | |
Total Proved Reserves | | (MMBbl) | | (MMBbl) | | (Bcf) | | MMBoe | |
| | | | | | | | | |
Balance, December 31, 2011 | | 15.7 | | 4.0 | | 38.7 | | 26.2 | |
Extensions and discoveries | | 12.3 | | 3.2 | | 32.6 | | 20.9 | |
Purchase of reserves in place | | 13.0 | | 7.8 | | 85.3 | | 35.0 | |
Revisions of previous estimate | | (1.4 | ) | (0.2 | ) | (8.5 | ) | (3.0 | ) |
Production | | (2.1 | ) | (0.6 | ) | (5.7 | ) | (3.6 | ) |
Balance, December 31, 2012 | | 37.5 | | 14.2 | | 142.4 | | 75.5 | |
| | | | | | | | | |
Proved developed, December 31, 2012 | | 13.2 | | 5.4 | | 54.8 | | 27.8 | |
Proved undeveloped, December 31, 2012 | | 24.3 | | 8.8 | | 87.6 | | 47.7 | |
Costs Incurred in Oil and Gas Acquisition, Exploration and Development Activities
In 2012, the Company incurred total acquisition, exploration and development costs of $1,115.5 million. Acquisition costs, including assumed asset retirement obligations, totaled $665.7 million, or $19.03 per Boe of proved reserves acquired, while the cost of adding new reserves from organic drilling activities totaled $449.8
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million, or $21.48 per Boe. All-in finding, development and acquisition costs for 2012, including the effect of revisions to previous reserve estimates, were $21.08 per Boe.
| | For the Twelve
Months Ended
December 31, 2012 | |
| | (in millions) | |
Property acquisition costs | | | |
Unproved properties | | $ | 245.0 | |
Proved properties (1) | | 420.7 | |
Exploration and development costs | | 449.8 | |
Total | | $ | 1,115.5 | |
(1) Includes $2.7 million of asset retirement obligations assumed on October 1, 2012 as part of the Eagle property acquisition.
Liquidity and Capital Investment
On December 31, 2012, Midstates’ liquidity was $175 million, consisting of $156 million of available borrowing capacity under the Company’s revolving credit facility (which at that date, consisted of a borrowing base of $250 million) and $19 million of cash and cash equivalents.
On October 1, 2012, the Company closed a private issuance of $600 million in aggregate principal amount of 10.75% Senior 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 property acquisition, to repay $182.9 million in outstanding borrowings under the Company’s revolving credit facility and for general corporate purposes. Also on October 1, 2012, in connection with the Eagle property acquisition and pursuant to the previously executed amendments to the Company’s revolving credit facility, the initial borrowing base under the Company’s revolving credit facility was increased to $250 million (subject to redetermination in March 2013) and the maturity date was extended to October 1, 2017.
Excluding the Eagle acquisition, during the three and twelve months ended December 31, 2012, the Company incurred capital expenditures of $134.2 million and $449.0 million, respectively, consisting primarily of (in millions):
| | For the Three
Months Ended
December 31, 2012 | | For the Twelve
Months Ended
December 31,
2012 | |
Drilling and completion activities | | $ | 110.9 | | $ | 361.0 | |
Acquisition of acreage and seismic data | | 13.1 | | 55.3 | |
Facilities and other | | 2.2 | | 21.5 | |
Capitalized interest | | 8.0 | | 11.2 | |
Total capital expenditures incurred (1) | | $ | 134.2 | | $ | 449.0 | |
(1) Does not include asset retirement obligations incurred or assumed during the period; however does include certain capital expenditures not considered to be related to oil and gas operations.
Of the $134.2 million incurred for the three months ended December 31, 2012, $86.3 million was invested in our Gulf Coast properties, $39.9 million was invested in our Mid-Continent properties, and $8.0 million represented capitalized interest.
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Gulf Coast Operations Update
During the three months ended December 31, 2012, Midstates continued its successful development at Pine Prairie and drilled or sidetracked 14 vertical wells, including eight wells in its shallow program and six wells in its Wilcox program. The Company plans to drill five to six vertical wells at Pine Prairie during the first quarter.
In the North Cowards Gully field, the McFatter 8H-1 was drilled to a total measured depth of 16,870 feet including a 3,350-foot lateral. The well was completed in the first quarter of 2013 with 10 stages of fracture stimulation and had an initial 14-day IP rate of 1,157 Boe per day comprised of 80% liquids. The McFatter 8H-1 is the first follow up well to the previously announced Musser-Davis 8H-1 drilled during the fall of 2012. Results from the first two wells in North Cowards Gully are encouraging to the continued development of the field as well as the use of horizontal drilling. Midstates plans to spud the next horizontal well in the field, the Woods 10H-1, before the end of the first quarter of 2013.
Since the beginning of the first quarter of 2013, Midstates has spud its first Wilcox horizontal well at South Bearhead Creek, the Musser Davis 33/28HC-1. The Musser Davis 33/28HC-1 is currently drilling and is expected to be completed in the second quarter of 2013. In the West Gordon field, the AKS 5H-1 horizontal reentry and sidetrack recently reached a total measured depth of 16,800 feet and is expected to be completed before the end of the quarter. Midstates plans to invest approximately $55 to $60 million in the Gulf Coast region in Louisiana during the first quarter of 2013.
At December 31, 2012, Midstates had approximately 151,800 net acres under lease or option, comprised of approximately 96,800 net leased acres and approximately 55,000 net optioned acres. The Company is currently evaluating the 200 square mile Fleetwood 3D seismic survey and plans to drill its first well based on this data later this year.
Mid-Continent Operations Update
The Company had four rigs active in its Mississippian Lime horizontal program in Oklahoma, spud 13 operated wells and placed a total of 14 operated wells into production. At December 31, 2012, four wells were drilling and nine were awaiting completion or connection to pipelines.
Since assuming control of the Eagle properties on October 1, 2012, Midstates has brought 19 wells into production. On average, the wells have approximately 4,000 foot laterals and 10 frac stages. Seventeen of these wells have been on production for approximately thirty days and have average 30-day IP rates of 638 Boe per day with approximately 65% liquids.
During the first quarter of 2013, Midstates plans to invest approximately $65 to $70 million in its Mid-Continent region, which includes the drilling of 13-15 horizontal wells and infrastructure projects. The Company will continue to operate four rigs in the area in the first quarter.
At December 31, 2012, Midstates had approximately 98,000 net acres under lease in the Mid-Continent region, comprised of approximately 83,000 net leased acres in the Mississippian Lime (77,400 in Woods and Alfalfa Counties in Oklahoma and 5,600 acres in Kansas) and approximately 15,000 in the Hunton in Lincoln County, Oklahoma. The Company is participating in a 3-D seismic shoot in northwest Oklahoma that will cover approximately 300 square miles.
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John Crum, Midstates’ Chairman, President and CEO commented, “The Eagle property acquisition was an important step in growing Midstates. This key new focus area in the Mississippian Lime provided us with an expanded geographical footprint, added significantly to our scope and scale, and gave us the opportunity to further employ our strong operating and technical expertise. Just as importantly, it provides the ability to optimize capital allocation across a diversified portfolio.” Crum continued, “We are very encouraged by the positive results from our Oklahoma drilling program since we assumed control of the properties on October 1, 2012. These results outperformed the type curve we utilized when we analyzed the acquisition last summer. Our technical teams continue to pursue ways to improve our drilling and completion efficiencies, lower costs, and decrease cycle times. In Louisiana, we are also pleased with the successes in our drilling programs in Pine Prairie and are likewise encouraged by the results achieved in our first two horizontal successes at North Cowards Gully. Our highly-motivated team is committed to building on last year’s successes and growing shareholder value.”
Conference Call Information
The Company will host a conference call to discuss fourth quarter and full year 2012 results on Wednesday, March 6, 2013 at 10:00 a.m. Eastern Time (9:00 a.m. Central 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 15741569 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 Wednesday, March 13, 2013 at 11:59 p.m. Eastern Time (10:59 p.m. Central Time) 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 15741569 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.
About Midstates Petroleum Company, Inc.
Midstates Petroleum Company, Inc. is an independent exploration and production company focused on the application of modern drilling and completion techniques to oil-prone resources in previously discovered yet underdeveloped hydrocarbon trends. Founded in 1993, the Company’s operations are currently focused on oilfields in the Upper Gulf Coast Tertiary trend onshore in central Louisiana and the Mississippian Lime trend in northwestern Oklahoma and southern Kansas. Midstates is headquartered in Houston, Texas.
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, goals, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management, and the benefits of the Eagle acquisition are forward-looking statements. When used in this release, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” “guidance,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. 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
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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. The Company discloses important factors that could cause our actual results to differ materially from its expectations in the “Risk Factors” section of the Company’s Form 10-Q for the three months ended September 30, 2012 and other filings with the SEC. These factors include, but are not limited to, the inability of the Company to integrate the Eagle acquisition and realize anticipated benefits therefrom; risks or liabilities assumed as a result of the Eagle acquisition; increases in our indebtedness; our ability to meet financial and operating guidance, to achieve our production targets, successfully manage our capital expenditures and to complete and to test and produce the wells and prospects identified in this release; 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 infrastructure for salt water disposal; 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 onshore in central Louisiana and northwestern Oklahoma; the outcome of the Clovelly litigation with respect to certain of the Company’s Pine Prairie properties; 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 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.
*********
Contact:
Midstates Petroleum Company, Inc.
Al Petrie, Investor Relations, (713) 595-9427
Al.Petrie@midstatespetroleum.com
or
Garrett Galloway, 713-595-9323
Garrett.Galloway@midstatespetroleum.com
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Midstates Petroleum Company, Inc.
Consolidated Balance Sheets
(In thousands, except share amounts)
(Unaudited)
| | December 31, 2012 | | December 31, 2011 | |
ASSETS | | | | | |
CURRENT ASSETS: | | | | | |
Cash and cash equivalents | | $ | 18,878 | | $ | 7,344 | |
Accounts receivable: | | | | | |
Oil and gas sales | | 35,618 | | 23,792 | |
Joint interest billing | | 10,815 | | — | |
Severance tax refund | | 703 | | 3,413 | |
Other | | 3,163 | | 249 | |
Prepayments | | 220 | | 2,642 | |
Inventory | | 8,353 | | 5,713 | |
Commodity derivative contracts | | 5,695 | | 4,957 | |
Total current assets | | 83,445 | | 48,110 | |
| | | | | |
PROPERTY AND EQUIPMENT: | | | | | |
Oil and gas properties, on the basis of full-cost accounting: | | | | | |
Proved properties | | 1,522,723 | | 644,393 | |
Unevaluated properties | | 313,941 | | 76,857 | |
Other property and equipment | | 5,038 | | 1,672 | |
Less accumulated depreciation, depletion, and amortization | | (274,294 | ) | (148,843 | ) |
Net property and equipment | | 1,567,408 | | 574,079 | |
| | | | | |
OTHER ASSETS: | | | | | |
Commodity derivative contracts | | 1,717 | | 588 | |
Other noncurrent assets | | 25,413 | | 1,879 | |
Total other assets | | 27,130 | | 2,467 | |
| | | | | |
TOTAL | | $ | 1,677,983 | | $ | 624,656 | |
| | | | | |
LIABILITIES AND EQUITY | | | | | |
CURRENT LIABILITIES: | | | | | |
Accounts payable | | $ | 29,196 | | $ | 35,731 | |
Accrued liabilities | | 98,649 | | 37,524 | |
Commodity derivative contracts | | 7,582 | | 12,599 | |
Total current liabilities | | 135,427 | | 85,854 | |
| | | | | |
LONG-TERM LIABILITIES: | | | | | |
Asset retirement obligations | | 15,245 | | 7,627 | |
Commodity derivative contracts | | 3,943 | | 10,178 | |
Long-term debt | | 694,000 | | 234,800 | |
Deferred income taxes | | 184,598 | | — | |
Other long-term liabilities | | 1,189 | | 695 | |
Total long-term liabilities | | 898,975 | | 253,300 | |
| | | | | |
COMMITMENTS AND CONTINGENCIES | | | | | |
| | | | | |
STOCKHOLDERS’/MEMBERS’ EQUITY | | | | | |
Capital contributions | | — | | 322,496 | |
Preferred stock, $0.01 par value, 49,675,000 shares authorized; no shares issued or outstanding | | — | | — | |
Series A mandatorily convertible preferred stock, $1,000 liquidation value; 8% cumulative dividends; 325,000 shares issued and outstanding | | 3 | | — | |
Common stock, $0.01 par value, 300,000,000 shares authorized; 66,619,711 shares issued and outstanding | | 666 | | — | |
Additional paid-in-capital | | 830,003 | | — | |
Retained deficit/accumulated loss | | (187,091 | ) | (36,994 | ) |
Total stockholders’/members’ equity | | 643,581 | | 285,502 | |
| | | | | |
TOTAL | | $ | 1,677,983 | | $ | 624,656 | |
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Midstates Petroleum Company, Inc.
Consolidated Statements of Operations
(In thousands, except per share amounts)
(Unaudited)
| | For the Three Months
Ended December 31, 2012 | | For the Twelve Months
Ended December 31, | |
| | 2012 | | 2011 | | 2012 | | 2011 | |
| | | | | | | | | |
REVENUES: | | | | | | | | | |
Oil sales | | $ | 72,149 | | $ | 54,646 | | $ | 218,430 | | $ | 177,464 | |
Natural gas sales | | 7,944 | | 5,851 | | 16,030 | | 20,665 | |
Natural gas liquid sales | | 9,310 | | 5,735 | | 23,617 | | 15,683 | |
Gains (Losses) on commodity derivative contracts — net (1) | | (910 | ) | (27,285 | ) | (11,158 | ) | (4,844 | ) |
Other | | 422 | | 205 | | 754 | | 465 | |
| | | | | | | | | |
Total revenues | | 88,915 | | 39,152 | | 247,673 | | 209,433 | |
| | | | | | | | | |
EXPENSES: | | | | | | | | | |
Lease operating and workover | | 11,543 | | 5,981 | | 30,500 | | 16,117 | |
Severance and other taxes | | 6,823 | | 4,588 | | 24,921 | | 13,640 | |
Asset retirement accretion | | 260 | | 129 | | 723 | | 334 | |
General and administrative | | 11,573 | | 37,307 | | 30,541 | | 68,915 | |
Acquisition and transaction costs | | 12,209 | | — | | 14,884 | | — | |
Depreciation, depletion, and amortization | | 38,960 | | 29,068 | | 125,561 | | 91,699 | |
| | | | | | | | | |
Total expenses | | 81,368 | | 77,073 | | 227,130 | | 190,705 | |
| | | | | | | | | |
OPERATING INCOME (LOSS) | | 7,547 | | (37,921 | ) | 20,543 | | 18,728 | |
| | | | | | | | | |
OTHER INCOME (EXPENSE) | | | | | | | | | |
Interest income | | 15 | | 8 | | 245 | | 23 | |
Interest expense — net of amounts capitalized | | (9,411 | ) | (1,359 | ) | (12,999 | ) | (2,094 | ) |
| | | | | | | | | |
Total other income (expense) | | (9,396 | ) | (1,351 | ) | (12,754 | ) | (2,071 | ) |
| | | | | | | | | |
INCOME (LOSS) BEFORE TAXES | | (1,849 | ) | (39,272 | ) | 7,789 | | 16,657 | |
| | | | | | | | | |
Income tax expense (benefit) | | 561 | | — | | 157,886 | | — | |
| | | | | | | | | |
NET INCOME (LOSS) | | $ | (2,410 | ) | $ | (39,272 | ) | $ | (150,097 | ) | $ | 16,657 | |
| | | | | | | | | |
Loss per share (2) | | | | | | | | | |
Basic and Diluted | | $ | (0.04 | ) | N/A | | $ | (2.50 | ) | N/A | |
| | | | | | | | | |
Weighted average shares outstanding (2) | | | | | | | | | |
Basic and Diluted | | 65,634 | | N/A | | 59,979 | | N/A | |
(1) Includes an insignificant realized gain on commodity derivatives for the three months ended December 31, 2012. Includes $4.6 million, $15.8 million and $16.7 million of realized losses on commodity derivatives for the three months ended December 31, 2011, the twelve months ended December 31, 2012 and the twelve months ended December 31, 2011.
(2) For the twelve months ended December 31, 2012, the calculations of loss per share and weighted average shares outstanding are pro forma.
10
Midstates Petroleum Company, Inc.
Statement of Stockholders’/Members’ Equity
(In thousands, except share amounts)
(Unaudited)
| | Preferred
Stock | | Common
Stock | | Capital
Contributions | | Additional
Paid-in-
Capital | | Retained
deficit/
accumulated
loss | | Total
Stockholders’/
Members’
Equity | |
Balance as of December 31, 2011 | | $ | — | | $ | — | | $ | 322,496 | | $ | — | | $ | (36,994 | ) | $ | 285,502 | |
Issuance of common stock | | — | | 476 | | (476 | ) | — | | — | | — | |
Reclassification of members’ contributions | | — | | — | | (322,020 | ) | 322,020 | | — | | — | |
Proceeds from the sale of common stock | | — | | 180 | | — | | 213,389 | | — | | 213,569 | |
Issuance of preferred stock as consideration in Eagle property acquisition | | 3 | | — | | — | | 291,953 | | — | | 291,956 | |
Share-based compensation | | — | | 10 | | — | | 2,641 | | — | | 2,651 | |
Forfeitures of restricted stock | | — | | — | | — | | — | | — | | — | |
Net loss | | — | | — | | — | | — | | (150,097 | ) | (150,097 | ) |
Balance as of December 31, 2012 | | $ | 3 | | $ | 666 | | $ | — | | $ | 830,003 | | $ | (187,091 | ) | $ | 643,581 | |
11
Midstates Petroleum Company, Inc.
Consolidated Statement of Cash Flows
(In thousands)
(Unaudited)
| | For the Three
Months Ended
December 31, | | For the Twelve
Months Ended
December 31, | |
| | 2012 | | 2011 | | 2012 | | 2011 | |
| | | | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | |
Net income (loss) | | $ | (2,410 | ) | $ | (39,272 | ) | $ | (150,097 | ) | $ | 16,657 | |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | | | | | |
Unrealized (gains) losses on commodity derivative contracts, net | | 924 | | 22,647 | | (4,667 | ) | (11,889 | ) |
Asset retirement accretion | | 260 | | 129 | | 723 | | 334 | |
Depreciation, depletion, and amortization | | 38,960 | | 29,068 | | 125,561 | | 91,699 | |
Share-based compensation | | 891 | | 33,616 | | 2,459 | | 53,744 | |
Deferred income taxes | | 561 | | — | | 157,886 | | — | |
Amortization of deferred financing costs | | 947 | | 245 | | 1,530 | | 850 | |
Change in operating assets and liabilities: | | | | | | | | | |
Accounts receivable — oil and gas sales | | (13,019 | ) | (5,892 | ) | (11,826 | ) | (9,651 | ) |
Accounts receivable — JIB and other | | (13,973 | ) | 1,987 | | (11,019 | ) | (3,125 | ) |
Prepayments and other assets | | 4,646 | | (2,038 | ) | 2,422 | | (2,259 | ) |
Inventory | | (1,317 | ) | (3,285 | ) | (2,640 | ) | (4,540 | ) |
Accounts payable | | 565 | | 7,736 | | (646 | ) | 3,059 | |
Accrued liabilities | | 25,780 | | (6,704 | ) | 27,931 | | 5,977 | |
Other | | (246 | ) | 45 | | (368 | ) | 694 | |
| | | | | | | | | |
Net cash provided by operating activities | | $ | 42,569 | | $ | 38,282 | | $ | 137,249 | | $ | 141,550 | |
| | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | |
Investment in property and equipment | | (137,457 | ) | (79,927 | ) | (422,332 | ) | (242,619 | ) |
Investment in acquired property | | (351,276 | ) | — | | (351,276 | ) | — | |
| | | | | | | | | |
Net cash used in investing activities | | $ | (488,733 | ) | $ | (79,927 | ) | $ | (773,608 | ) | $ | (242,619 | ) |
| | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | |
Proceeds from long-term borrowings | | 660,000 | | 36,200 | | 744,667 | | 145,200 | |
Repayment of long-term borrowings | | (182,300 | ) | — | | (285,467 | ) | — | |
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 | | (18 | ) | — | | 213,569 | | — | |
Deferred financing costs | | (17,314 | ) | — | | (24,876 | ) | (863 | ) |
Cash received for units | | — | | 2,700 | | — | | 2,870 | |
Distributions to members | | — | | — | | — | | (50,572 | ) |
Other | | — | | (131 | ) | — | | (139 | ) |
| | | | | | | | | |
Net cash provided by financing activities | | $ | 460,368 | | $ | 38,769 | | $ | 647,893 | | $ | 96,496 | |
| | | | | | | | | |
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | | 14,204 | | (2,876 | ) | 11,534 | | (4,573 | ) |
| | | | | | | | | |
Cash and cash equivalents, beginning of period | | 4,674 | | 10,220 | | 7,344 | | 11,917 | |
| | | | | | | | | |
Cash and cash equivalents, end of period | | $ | 18,878 | | $ | 7,344 | | $ | 18,878 | | $ | 7,344 | |
12
Midstates Petroleum Company, Inc.
Selected Financial and Operating Statistics
(Unaudited)
| | For the
Three Months
Ended
December 31, | | For the
Twelve Months
Ended
December 31, | | For the Three
Months Ended
September 30, | |
| | 2012 | | 2011 | | 2012 | | 2011 | | 2012 | |
PRODUCTION DATA — Gulf Coast | | | | | | | | | | | |
Oil (Boe/day) | | 5,737 | | 5,144 | | 5,162 | | 4,410 | | 5,537 | |
Natural gas (Mcf/day) | | 8,869 | | 19,180 | | 10,778 | | 13,475 | | 8,261 | |
Natural gas liquids (Boe/day) | | 1,170 | | 1,092 | | 1,228 | | 843 | | 1,267 | |
Oil equivalents (MBoe) | | 771 | | 868 | | 2,996 | | 2,737 | | 753 | |
Average daily production (Boe/day) | | 8,385 | | 9,433 | | 8,187 | | 7,499 | | 8,182 | |
| | | | | | | | | | | |
PRODUCTION DATA — Mid-Continent (3) | | | | | | | | | | | |
Oil (Boe/day) | | 2,216 | | — | | 557 | | — | | — | |
Natural gas (Mcf/day) | | 19,021 | | — | | 4,781 | | — | | — | |
Natural gas liquids (Boe/day) | | 1,820 | | — | | 458 | | — | | — | |
Oil equivalents (MBoe) | | 663 | | — | | 663 | | — | | — | |
Average daily production (Boe/day) | | 7,207 | | — | | 1,812 | | — | | — | |
| | | | | | | | | | | |
PRODUCTION DATA — Combined | | | | | | | | | | | |
Oil (Boe/day) | | 7,954 | | 5,144 | | 5,719 | | 4,410 | | 5,537 | |
Natural gas (Mcf/day) | | 27,890 | | 19,180 | | 15,559 | | 13,475 | | 8,261 | |
Natural gas liquids (Boe/day) | | 2,990 | | 1,092 | | 1,686 | | 843 | | 1,267 | |
Oil equivalents (MBoe) | | 1,434 | | 868 | | 3,659 | | 2,737 | | 753 | |
Average daily production (Boe/day) | | 15,592 | | 9,433 | | 9,999 | | 7,499 | | 8,182 | |
| | | | | | | | | | | |
AVERAGE SALES PRICES: | | | | | | | | | | | |
Oil, without realized derivatives (per Bbl) | | $ | 98.60 | | $ | 115.46 | | $ | 104.35 | | $ | 110.25 | | $ | 104.32 | |
Oil, with realized derivatives (per Bbl) | | $ | 93.65 | | $ | 105.77 | | $ | 95.05 | | $ | 99.85 | | $ | 96.15 | |
Natural gas, without realized derivatives (per Mcf) | | $ | 3.10 | | $ | 3.32 | | $ | 2.81 | | $ | 4.20 | | $ | 2.97 | |
Natural gas, with realized derivatives (per Mcf) | | $ | 3.98 | | (2 | ) | $ | 3.21 | | (2 | ) | (2 | ) |
Natural gas liquids, without realized derivatives (per Bbl) | | $ | 33.84 | | $ | 57.08 | | $ | 38.27 | | $ | 50.98 | | $ | 35.46 | |
Natural gas liquids, with realized derivatives (per Bbl) | | $ | 38.79 | | (2 | ) | $ | 40.48 | | (2 | ) | (2 | ) |
| | | | | | | | | | | |
COSTS AND EXPENSES (PER BOE OF PRODUCTION) | | | | | | | | | | | |
Lease operating and workover | | $ | 8.05 | | $ | 6.89 | | $ | 8.34 | | $ | 5.89 | | $ | 8.72 | |
Severance and other taxes | | $ | 4.76 | | $ | 5.28 | | $ | 6.81 | | $ | 4.98 | | $ | 8.57 | |
Asset retirement accretion | | $ | 0.18 | | $ | 0.15 | | $ | 0.20 | | $ | 0.12 | | $ | 0.22 | |
Depreciation, depletion, and amortization | | $ | 27.17 | | $ | 33.49 | | $ | 34.32 | | $ | 33.50 | | $ | 40.76 | |
General and administrative (1) | | $ | 8.07 | | $ | 42.98 | | $ | 8.35 | | $ | 25.18 | | $ | 10.56 | |
Acquisition and transition costs | | $ | 8.51 | | $ | — | | $ | 4.07 | | $ | — | | $ | 3.55 | |
(1) Includes $0.62, $38.73, $0.67 and $19.64 per Boe for share-based compensation for the three months ended December 31, 2012 and 2011, and the twelve months ended December 31, 2012 and 2011, respectively.
(2) The Company did not have hedges in place on its natural gas or NGL production prior to October 1, 2012.
(3) Mid-Continent average daily production for the year ended December 31, 2012 represents the annual impact of production for the three months ended December 31, 2012 of the Mid-Continent assets Midstates acquired effective October 1, 2012.
13
Midstates Petroleum Company, Inc.
Summary of Commodity Derivative Contracts as of March 5, 2013
(Unaudited)
GULF COAST
| | 2013 | | 2014 | |
| | | | | |
Oil (Bbls): | | | | | |
WTI Swaps - LA | | | | | |
Hedged Volume | | 1,700,874 | | 809,950 | |
Hedged Volume (BPD) | | 4,660 | | 2,219 | |
Weighted Average Fixed Price (per Bbl) | | $ | 95.55 | | $ | 87.33 | |
| | | | | |
WTI to LLS Basis Differential Swaps (1) | | | | | |
Hedged Volume | | 1,602,164 | | 501,000 | |
Hedged Volume (BPD) | | 4,389 | | 1,373 | |
Weighted Average Differential (per Bbl) | | $ | 5.89 | | $ | 5.35 | |
MID-CONTINENT
| | 2013 | | 2014 | |
| | | | | |
Oil (Bbls): | | | | | |
WTI Swaps - OKLA | | | | | |
Hedged Volume | | 237,600 | | 156,000 | |
Hedged Volume (BPD) | | 651 | | 427 | |
Weighted Average Fixed Price (per Bbl) | | $ | 96.10 | | $ | 93.00 | |
| | | | | |
WTI Collars - OKLA | | | | | |
Hedged Volume | | 203,004 | | 164,400 | |
Hedged Volume (BPD) | | 556 | | 450 | |
Weighted Average Floor ($/BBL) | | $ | 85.27 | | $ | 88.49 | |
Weighted Average Ceiling ($/BBL) | | $ | 100.70 | | $ | 97.94 | |
| | | | | |
Natural Gas Collars - OKLA | | | | | |
Hedged Volume (MMBTU) | | 2,232,996 | | 1,685,004 | |
Hedged Volume (MMBTU/D) | | 6,118 | | 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 | | 258,000 | | 151,500 | |
Hedged Volume (BPD) | | 707 | | 415 | |
Weighted Average Fixed Price (per Bbl) | | $ | 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 West Texas Intermediate (“NYMEX WTI”) pricing.
14
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 December 31, | | For the Twelve Months
Ended December 31, | | For the Three
Months Ended
September 30, | |
| | 2012 | | 2011 | | 2012 | | 2011 | | 2012 | |
Adjusted EBITDA reconciliation to net income (loss): | | | | | | | | | | | |
Net income (loss): | | $ | (2,410 | ) | $ | (39,272 | ) | $ | (150,097 | ) | $ | 16,657 | | $ | (17,803 | ) |
Depreciation, depletion and amortization | | 38,960 | | 29,068 | | 125,561 | | 91,699 | | 30,692 | |
Change in unrealized (gain) loss on commodity derivative contracts | | 924 | | 22,647 | | (4,667 | ) | (11,889 | ) | 29,566 | |
Income taxes | | 561 | | — | | 157,886 | | — | | (11,592 | ) |
Interest income | | (15 | ) | (8 | ) | (245 | ) | (23 | ) | (80 | ) |
Interest expense - net of amounts capitalized | | 9,411 | | 1,359 | | 12,999 | | 2,094 | | 908 | |
Asset retirement obligation accretion | | 260 | | 129 | | 723 | | 334 | | 165 | |
Share-based compensation | | 891 | | 33,616 | | 2,459 | | 53,744 | | 886 | |
| | | | | | | | | | | |
Adjusted EBITDA (1) | | $ | 48,582 | | $ | 47,539 | | $ | 144,619 | | $ | 152,616 | | $ | 32,742 | |
| | | | | | | | | | | |
Adjusted EBITDA reconciliation to net cash provided by operating activities: | | | | | | | | | | | |
Net cash provided by operating activities | | 42,569 | | 38,282 | | 137,249 | | 141,550 | | 34,717 | |
Changes in working capital | | (2,436 | ) | 8,151 | | (3,854 | ) | 9,845 | | (2,596 | ) |
Interest income | | (15 | ) | (8 | ) | (245 | ) | (23 | ) | (80 | ) |
Interest expense - net of amounts capitalized and accrued but not paid | | 9,411 | | 1,359 | | 12,999 | | 2,094 | | 908 | |
Amortization of deferred financing costs | | (947 | ) | (245 | ) | (1,530 | ) | (850 | ) | (207 | ) |
| | | | | | | | | | | |
Adjusted EBITDA (1) | | $ | 48,582 | | $ | 47,539 | | $ | 144,619 | | $ | 152,616 | | $ | 32,742 | |
(1) For the three and twelve months ended December 31, 2012, and the three months ended September 30, 2012, the Company incurred transaction costs of $12.2 million, $14.9 million and $2.7 million, respectively. Adjusted EBITDA excluding these transaction costs for the three and twelve months ended December 31, 2012 and the three months ended September 30, 2012 would have been $60.8 million, $159.5 million and $35.4 million, respectively.
15
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 and transaction costs . 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 December 31, | | For the Twelve Months
Ended December 31, | | For the Three
Months Ended
September 30, | |
| | 2012 | | 2011 | | 2012 | | 2011 | | 2012 | |
| | | | | | | | | | | |
Net income - GAAP | | (2,410 | ) | (39,272 | ) | (150,097 | ) | 16,657 | | (17,803 | ) |
Adjustments for certain non-cash items: | | | | | | | | | | | |
Unrealized mark-to-market (gain)/loss on commodity derivative contracts | | 924 | | 22,647 | | (4,667 | ) | (11,889 | ) | 29,566 | |
Deferred tax charge - IPO, corporate reorganization | | | | | | 149,489 | | | | | |
Acquisition and transaction costs | | 12,209 | | — | | 14,884 | | — | | 2,675 | |
| | | | | | | | | | | |
Tax impact (1) | | (5,261 | ) | — | | (4,093 | ) | — | | (12,703 | ) |
| | | | | | | | | | | |
Adjusted net income - non-GAAP | | $ | 5,462 | | $ | (16,625 | ) | $ | 5,516 | | $ | 4,768 | | $ | 1,735 | |
| | | | | | | | | | | | | | | | |
(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 twelve months ended December 31, 2012 was approximately 40%. Prior to April 25, 2012, the Company was not a tax paying entity.
16
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 December 31, | | For the Twelve Months
Ended December 31, | | For the Three
Months Ended
September 30, | |
| | 2012 | | 2011 | | 2012 | | 2011 | | 2012 | |
| | | | | | | | | | | |
Operating Expenses - GAAP | | $ | 81,368 | | $ | 77,073 | | $ | 227,130 | | $ | 190,705 | | $ | 54,499 | |
Adjustments for certain non-cash items: | | | | | | | | | | | |
Asset retirement accretion | | (260 | ) | (129 | ) | (723 | ) | (334 | ) | (165 | ) |
Share-based compensation | | (891 | ) | (33,616 | ) | (2,459 | ) | (53,744 | ) | (886 | ) |
Depreciation, depletion, and amortization | | (38,960 | ) | (29,068 | ) | (125,561 | ) | (91,699 | ) | (30,692 | ) |
| | | | | | | | | | | |
Cash Operating Expenses - Non-GAAP (1) | | $ | 41,257 | | $ | 14,260 | | $ | 98,387 | | $ | 44,928 | | $ | 22,756 | |
Cash Operating Expenses - Non-GAAP, per Boe (1) | | $ | 28.77 | | $ | 16.43 | | $ | 26.89 | | $ | 16.42 | | $ | 30.22 | |
(1) For the three and twelve months ended December 31, 2012, and the three months ended September 30, 2012, cash operating expenses include transaction costs of $12.2 million ($8.51 per Boe), $14.9 million ($4.07 per Boe), and $2.7 million ($3.55 per Boe), respectively, attributable to costs incurred during the period related to the Eagle property acquisition. Cash operating expenses excluding transaction costs were $20.26 per Boe and $22.82 per Boe, respectively for the three and twelve months ended December 31. 2012 and $26.67 per Boe for the three months ended September 30, 2012.
Non-GAAP Definitions
All-In Finding and Development Costs (“F&D”)
Midstates believes that the analysis of F&D cost is a useful tool in helping to evaluate capital productivity. The Company calculates F&D cost by dividing development and exploration capital expenditures and the cost of acquired reserves by the sum of reserve extensions and discoveries, purchases of reserves in place, and total revisions for the year.
17
