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| 8-K - 8-K - Laredo Petroleum, Inc. | a8-kx1q15erpr.htm |
EXHIBIT 99.1
15 West 6th Street, Suite 900 · Tulsa, Oklahoma 74119 · (918) 513-4570 · Fax: (918) 513-4571
www.laredopetro.com
LAREDO PETROLEUM ANNOUNCES 2015 FIRST-QUARTER
FINANCIAL AND OPERATING RESULTS
TULSA, OK - May 7, 2015 - Laredo Petroleum, Inc. (NYSE: LPI) (“Laredo” or “the Company”) today announced its 2015 first-quarter results, reporting a net loss attributable to common stockholders of $0.5 million, or $0.00 per diluted share. Adjusted Net Income, a non-GAAP financial measure, for the first quarter of 2015 was $4.4 million, or $0.03 per diluted share. Adjusted EBITDA, a non-GAAP financial measure, for the first quarter of 2015 was $118.6 million.
2015 First-Quarter Highlights
• | Produced a Company record 47,487 barrels of oil equivalent (“BOE”) per day, up approximately 47% from the comparable first quarter of 2014 |
• | Reduced unit cash costs approximately 30% to $14.07 per BOE, from the first-quarter 2014 rate of $20.06 per BOE, on a three-stream basis |
• | Reduced estimated capital costs for horizontal wells drilled on a single-well pad to a range of $6.3 million to $6.9 million per well |
• | Commenced full-operations on the Medallion Wolfcamp Connector and Reagan Extension pipelines, 49%-owned by Laredo Midstream Services, LLC (“LMS”) |
• | Continued construction of the Midkiff Lateral and Santa Rita Lateral extensions of the Medallion pipeline, enabling third-party volumes to be transported to Colorado City, Texas |
Please see supplemental financial information at the end of this news release for reconciliations of non-GAAP financial measures.
“During the first quarter, Laredo continued to benefit from its contiguous acreage base in a premier oil producing basin,” commented Randy A. Foutch, Laredo Chairman and Chief Executive Officer. “The operational benefits of our production corridors, built on contiguous, high working interest leasehold, facilitated the delivery of our oil production to sales points, which proved extremely beneficial during the quarter’s adverse weather events and also mitigated the impact of reduced trucking on hazardous roadways. Gas lift, rig fuel and water distribution facilities are contributing to anticipated reductions in drilling and operating costs, enabling the Company to operate more efficiently and potentially generate
returns comparable to those previously achieved at higher oil prices. Additionally, during the second quarter of 2015, our water system is expected to deliver approximately 3 million barrels of water in a 30-day period to enable the simultaneous completion of 12 horizontal wells.”
“We have acquired high-quality 3D seismic on approximately 95% of our acreage, collected extensive petrophysical data across our leasehold and integrated this data into our reservoir characterization process known as the Earth Model. Focusing our operations in a concentrated acreage block facilitated data acquisition and makes processing the data in the Earth Model extremely efficient and effective. As we assess conditions to determine the most advantageous time to accelerate drilling, the cost and efficiency advantages of drilling multi-well pads along our production corridors and the potential to use the Earth Model for landing and steering horizontal wells are both expected to enhance returns in a challenging commodity price environment.”
Operational Update
In the first quarter of 2015, Laredo produced a Company record 47,487 BOE per day, up from three-stream production of 32,358 BOE per day in the first quarter of 2014. During the first quarter of 2015, the Company completed 11 horizontal wells in the Company’s four initially targeted zones, with an average working interest of approximately 99%. Two horizontal wells were completed in the Upper Wolfcamp, two in the Middle Wolfcamp, three in the Lower Wolfcamp and four in the Cline. Additionally, 21 vertical wells were completed with an average working interest of approximately 88%.
Completions in the first quarter of 2015 and those planned for the second quarter of 2015 reflect substantial multi-well pad drilling activity commenced in the later part of 2014. The Company has begun concurrent completion activities on 12 horizontal wells on the JE Cox-Blanco production corridor and expects to complete a total of 20 horizontal wells in the second quarter with an average working interest of approximately 71%. The operational adjustments made by Laredo to align activity levels with current commodity prices will result in reduced completion activity in the second half of 2015 and it is expected that the Company’s capital expenditures will be less than projected cash flow during the second half of 2015.
Laredo is continuing to focus on reducing costs and maximizing operational efficiencies. The Company has reduced capital cost expectations to a range of $6.3 million to $6.9 million for horizontal wells drilled on single-well pads and to a range of $5.9 million to $6.5 million for horizontal wells drilled on multi-well pads. These reductions reflect the Company’s ability to gain efficiencies by utilizing production
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corridor infrastructure, extensive efforts that have reduced the number of days required to drill horizontal wells and decreased service costs.
The performance of the Company’s horizontal wells continues to support the type curves which now reflect Laredo’s transition to reporting reserves and production on a three-stream basis beginning January 1, 2015. Laredo focuses on production history of at least 180 days to determine the performance of horizontal wells versus the type curve for the well.
Wells with 180 days of Production | Wells with 365 days of Production | |||||||||||
Zone | No. of Wells | Avg. Cumulative Production per Well | % of Type Curve | No. of Wells | Avg. Cumulative Production per Well | % of Type Curve | ||||||
(long laterals) | (Three-stream MBOE) | (long laterals) | (Three-Stream MBOE) | |||||||||
Upper Wolfcamp | 51 | 88.8 | 97% | 31 | 147.9 | 103% | ||||||
Middle Wolfcamp | 17 | 84.4 | 105% | 11 | 134.0 | 106% | ||||||
Lower Wolfcamp | 15 | 77.2 | 97% | 6 | 142.2 | 112% | ||||||
Cline | 10 | 98.4 | 103% | 6 | 134.1 | 95% | ||||||
The Company continues to refine the Earth Model reservoir characterization process. Elements of the Earth Model are being optimized to select landing points and geosteer horizontal wells drilling in areas where the tool is currently available. The Company continually incorporates new well results with existing data to enhance its predictive capabilities. It is expected that when a statistically significant number of horizontal wells, in which the Earth Model has been fully implemented, have 180 days of production history, the benefits of the Earth Model can be more fully assessed.
Laredo Midstream Services Update
During the first quarter of 2015, the Company’s wholly-owned subsidiary, LMS, continued to support the Company through the construction of infrastructure to facilitate production and marketing of oil, natural gas liquids and natural gas as well as the management of Laredo’s investment in Medallion Gathering & Processing, LLC, in which the Company owns a 49% interest.
A major component of the infrastructure that LMS manages, both on production corridors and more broadly across the Company’s leasehold, is the oil and natural gas gathering systems. Ownership and control of these gathering systems provides optionality by enabling LMS to access multiple sales points for oil, natural gas liquids and natural gas and decreases Laredo’s dependence on an individual market. The 175-mile LMS-owned natural gas gathering system provides direct connectivity to three processors
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operating 15 plants. This system currently transports approximately 50% of Laredo’s gross operated gas production, reducing gathering costs by approximately $0.10 per million British thermal units (“MMBtu”). The 20-mile oil gathering system currently gathers approximately 40% of the Company’s gross operated oil production which can be directed to the Medallion or Plains pipelines. This gathering system enables Laredo to minimize field inventory, reduce truck traffic, minimize weather disruptions and benefit from a $0.95 per barrel higher netback price. Additionally, LMS receives $0.75 per barrel in third-party gathering revenue from crude purchasers utilizing the system. The Company expects that approximately 50% of gross operated oil production will be gathered on the system once the 12 horizontal wells on the JE Cox-Blanco corridor are completed and producing.
The Medallion pipeline commenced operations in the fourth quarter of 2014 and became fully operational in the first quarter of 2015. At March 31, 2015, the pipeline was transporting approximately 16,500 barrels of oil per day and is expected to be transporting more than 40,000 barrels of oil per day by the end of the second quarter of 2015. The Midkiff and Santa Rita Laterals, extensions of the original pipeline to the West and South that will transport third-party volumes to Colorado City, Texas, are expected to be fully operational in the second quarter of 2015 and volumes on the Medallion pipeline are expected to reach approximately 70,000 barrels of oil per day by the end of 2015.
2015 Capital Program
During the first quarter of 2015, Laredo invested approximately $211 million in exploration and development activities and approximately $37 million in pipelines and related infrastructure assets held by LMS. Approximately $41 million of the capital invested in exploration and development activities during the quarter were related to activities initiated in 2014.
Liquidity
On May 4, 2015, in connection with the regular semi-annual redetermination of the Company’s senior secured credit facility, lenders increased the Company’s borrowing base to $1.25 billion and the Company increased its aggregate elected commitment amount of $1.0 billion. At May 5, 2015, the Company had approximately $13 million in cash and equivalents and an outstanding balance of $60 million under the senior secured credit facility, resulting in total liquidity of approximately $950 million.
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Commodity Derivatives
Laredo maintains an active hedging program to reduce the variability in its anticipated cash flow due to fluctuations in commodity prices. At March 31, 2015, the Company had hedges in place for the remaining three quarters of 2015 for 5,768,140 barrels of oil at a weighted-average floor price of $80.99 per barrel, representing approximately 100% of anticipated oil production for the last nine months of 2015. The Company has also hedged 21,520,000 MMBtu of natural gas for the remaining nine months of 2015 at a weighted-average floor price of $3.00 per MMBtu, representing approximately 60% of anticipated natural gas and natural gas liquids production for the last three quarters of 2015. Additionally, the Company has basis swaps for the remaining nine months of 2015 totaling 2,750,000 barrels of oil to hedge the Midland-West Texas Intermediate (“WTI”) basis differential at WTI less $1.95 per barrel.
For 2016, the Company has hedged 4,129,800 barrels of oil at a weighted-average floor price of $81.84 per barrel and 18,666,000 MMBtu of natural gas at a weighted-average floor price of $3.00 per MMBtu. Additionally, for 2017, the Company has hedged 2,628,000 barrels of oil at a weighted-average floor price of $77.22 per barrel.
Potential Transaction
As previously announced, the Company has been in discussions regarding a drilling fund opportunity involving a portion of its northern Permian-Garden City properties as well as additional operational locations in its southern area. Although the Company received significant interest regarding such an opportunity, it has not reached terms that the Company believes would be beneficial to its stockholders. Further pursuit of a joint development opportunity may occur, but there can be no assurance of any discussions or any transaction of this nature.
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Guidance
The table below reflects the Company’s guidance for second-quarter 2015:
2Q-2015 | FY-2015 | ||
Production (MMBOE) | 4.0 - 4.2 | 15.6 - 16.0 | |
Crude oil % of production | 50% | 50% | |
Natural gas liquids % of production | 25% | 25% | |
Natural gas % of production | 25% | 25% | |
Price Realizations (pre-hedge): | |||
Crude oil (% of WTI) | ~85% | ~85% | |
Natural gas liquids (% of WTI) | ~25% | ~25% | |
Natural Gas (% of Henry Hub) | ~70% | ~70% | |
Operating Costs & Expenses: | |||
Lease operating expenses ($/BOE) | $6.75 - $7.75 | $6.75 - $7.75 | |
Midstream expenses ($/BOE) | $0.40 - $0.50 | $0.40 - $0.50 | |
Production and ad valorem taxes (% of oil and gas revenue) | 7.75% | 7.75% | |
General and administrative expenses ($/BOE) | $6.00 - $7.00 | $6.00 - $7.00 | |
Depletion, depreciation and amortization ($/BOE) | $16.50 - $17.50 | $16.75 - $17.75 | |
Conference Call Details
Laredo has scheduled a conference call today at 9:00 a.m. CT (10:00 a.m. ET) to discuss its first-quarter 2015 financial and operating results and management’s outlook for the future, the content of which is not part of this earnings release. Participants may listen to the call via the Company’s website at www.laredopetro.com, under the tab for “Investor Relations.” The conference call may also be accessed by dialing 1-877-930-8286, using the conference code 21467111. International participants may access the call by dialing 1-253-336-8309, also using conference code 21467111. It is recommended that participants dial in approximately 10 minutes prior to the start of the conference call. A telephonic replay will be available approximately two hours after the call on May 7, 2015 through Thursday, May 14, 2015. Participants may access this replay by dialing 1-855-859-2056, using conference code 21467111.
About Laredo
Laredo Petroleum, Inc. is an independent energy company with headquarters in Tulsa, Oklahoma. Laredo's business strategy is focused on the acquisition, exploration and development of oil and natural gas properties primarily in the Permian Basin in West Texas.
Additional information about Laredo may be found on its website at www.laredopetro.com.
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Forward-Looking Statements
This press release and any oral statements made regarding the subject of this release, including in the conference call referenced herein, contain forward-looking statements as defined under Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, that address activities that Laredo assumes, plans, expects, believes, intends, projects, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. The forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events.
The preliminary results above are based on the most current information available to management. As a result, our final results may vary from these preliminary estimates. Such variances may be material; accordingly, you should not place undue reliance on these preliminary estimates.
General risks relating to Laredo include, but are not limited to, the risks described in its Annual Report on Form 10-K for the year ended December 31, 2014, its Quarterly Report on Form 10-Q for the quarter ended March 31, 2015 and those set forth from time to time in other filings with the SEC. These documents are available through Laredo’s website at www.laredopetro.com under the tab “Investor Relations” or through the SEC’s Electronic Data Gathering and Analysis Retrieval System ("EDGAR") at www.sec.gov. Any of these factors could cause Laredo's actual results and plans to differ materially from those in the forward-looking statements. Therefore, Laredo can give no assurance that its future results will be as estimated. Laredo does not intend to, and disclaims any obligation to, update or revise any forward-looking statement.
The SEC generally permits oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions and certain probable and possible reserves that meet the SEC’s definitions for such terms. In this press release and the conference call, the Company may use the terms “resource potential” and “estimated ultimate recovery, or EURs,” each of which the SEC guidelines restrict from being included in filings with the SEC without strict compliance with SEC definitions. These terms refer to the Company’s internal estimates of unbooked hydrocarbon quantities that may be potentially added to proved reserves, largely from a specified resource play. A resource play is a term used by the Company to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section, which, when compared to a conventional play, typically has a lower geological and/or commercial development risk. EURs are based on the Company’s previous operating experience in a given area and publicly available information relating to the operations of producers who are conducting operations in these areas. Unbooked resource potential or EURs do not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules and do not include any proved reserves. Actual quantities of reserves that may be ultimately recovered from the Company’s interests may differ substantially from those presented herein. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, decreases in oil and natural gas prices, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals, negative revisions to reserve estimates and other factors as well as actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of unproved reserves may change significantly as development of the Company’s core assets provides additional data. In addition, our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the
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undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases.
# # #
Contact:
Ron Hagood: (918) 858-5504 - RHagood@laredopetro.com
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Laredo Petroleum, Inc.
Condensed consolidated statements of operations
Three months ended March 31, | ||||||||
(in thousands, except per share data) | 2015 | 2014 | ||||||
(unaudited) | ||||||||
Revenues: | ||||||||
Oil, NGL and natural gas sales | $ | 118,118 | $ | 173,214 | ||||
Midstream service revenues | 1,309 | 96 | ||||||
Sales of purchased oil | 31,267 | — | ||||||
Total revenues | 150,694 | 173,310 | ||||||
Costs and expenses: | ||||||||
Lease operating expenses | 32,380 | 21,785 | ||||||
Midstream service expenses | 1,574 | 845 | ||||||
Production and ad valorem taxes | 9,086 | 12,450 | ||||||
Minimum volume commitments | 1,656 | 516 | ||||||
Costs of purchased oil | 31,200 | — | ||||||
General and administrative | 21,855 | 27,654 | ||||||
Restructuring expenses | 6,042 | — | ||||||
Accretion of asset retirement obligations | 579 | 415 | ||||||
Depletion, depreciation and amortization | 71,942 | 49,607 | ||||||
Impairment expense | 878 | — | ||||||
Total costs and expenses | 177,192 | 113,272 | ||||||
Operating income (loss) | (26,498 | ) | 60,038 | |||||
Non-operating income (expense): | ||||||||
Gain (loss) on derivatives, net | 63,155 | (31,112 | ) | |||||
Income (loss) from equity method investee | (433 | ) | 16 | |||||
Interest expense | (32,414 | ) | (28,986 | ) | ||||
Other | (639 | ) | (62 | ) | ||||
Non-operating income (expense), net | 29,669 | (60,144 | ) | |||||
Income (loss) before income taxes | 3,171 | (106 | ) | |||||
Income tax expense: | ||||||||
Deferred | (3,643 | ) | (107 | ) | ||||
Total income tax expense | (3,643 | ) | (107 | ) | ||||
Net loss | $ | (472 | ) | $ | (213 | ) | ||
Net loss per common share: | ||||||||
Basic | $ | — | $ | — | ||||
Diluted | $ | — | $ | — | ||||
Weighted-average common shares outstanding: | ||||||||
Basic | 162,426 | 141,067 | ||||||
Diluted | 162,426 | 141,067 | ||||||
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Laredo Petroleum, Inc.
Condensed consolidated balance sheets
(in thousands) | March 31, 2015 | December 31, 2014 | ||||||
Assets: | (unaudited) | (unaudited) | ||||||
Current assets | $ | 901,604 | $ | 365,253 | ||||
Net property and equipment | 3,520,459 | 3,354,082 | ||||||
Other noncurrent assets | 232,960 | 213,214 | ||||||
Total assets | $ | 4,655,023 | $ | 3,932,549 | ||||
Liabilities and stockholders' equity: | ||||||||
Current liabilities | $ | 892,832 | $ | 425,025 | ||||
Long-term debt | 1,300,000 | 1,801,295 | ||||||
Other noncurrent liabilities | 143,079 | 143,028 | ||||||
Stockholders' equity | 2,319,112 | 1,563,201 | ||||||
Total liabilities and stockholders' equity | $ | 4,655,023 | $ | 3,932,549 | ||||
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Laredo Petroleum, Inc.
Condensed consolidated statements of cash flows
Three months ended March 31, | ||||||||
(in thousands) | 2015 | 2014 | ||||||
(unaudited) | ||||||||
Cash flows from operating activities: | ||||||||
Net loss | $ | (472 | ) | $ | (213 | ) | ||
Adjustments to reconcile net loss to net cash provided by operating activities: | ||||||||
Deferred income tax expense | 3,643 | 107 | ||||||
Depletion, depreciation and amortization | 71,942 | 49,607 | ||||||
Impairment expense | 878 | — | ||||||
Non-cash stock-based compensation, net of amounts capitalized | 4,788 | 4,329 | ||||||
Accretion of asset retirement obligations | 579 | 415 | ||||||
Mark-to-market on derivatives: | ||||||||
(Gain) loss on derivatives, net | (63,155 | ) | 31,112 | |||||
Cash settlements received (paid) for matured derivatives, net | 63,141 | (1,431 | ) | |||||
Cash settlements received for early terminations of derivatives, net | — | 76,660 | ||||||
Change in net present value of deferred premiums paid for derivatives | 43 | 65 | ||||||
Cash premiums paid for derivatives | (1,421 | ) | (1,959 | ) | ||||
Amortization of debt issuance costs | 1,377 | 1,207 | ||||||
Write-off of debt issuance costs | — | 124 | ||||||
Other | (1,575 | ) | (47 | ) | ||||
Cash flows from operations before changes in working capital | 79,768 | 159,976 | ||||||
Changes in working capital | (54,086 | ) | (32,181 | ) | ||||
Changes in other noncurrent liabilities and fair value of performance unit awards | 1,183 | 322 | ||||||
Net cash provided by operating activities | 26,865 | 128,117 | ||||||
Cash flows from investing activities: | ||||||||
Capital expenditures: | ||||||||
Acquisition of mineral interests | — | (7,305 | ) | |||||
Oil and natural gas properties | (243,733 | ) | (187,040 | ) | ||||
Midstream service assets | (20,434 | ) | (10,520 | ) | ||||
Other fixed assets | (3,919 | ) | (3,369 | ) | ||||
Investment in equity method investee | (14,495 | ) | (11,300 | ) | ||||
Proceeds from dispositions of capital assets, net of costs | 35 | 268 | ||||||
Net cash used in investing activities | (282,546 | ) | (219,266 | ) | ||||
Cash flows from financing activities: | ||||||||
Borrowings on Senior Secured Credit Facility | 175,000 | — | ||||||
Payments on Senior Secured Credit Facility | (475,000 | ) | — | |||||
Issuance of March 2023 Notes | 350,000 | — | ||||||
Issuance of January 2022 Notes | — | 450,000 | ||||||
Proceeds from issuance of common stock, net of offering costs | 754,163 | — | ||||||
Other | (8,710 | ) | (9,485 | ) | ||||
Net cash provided by financing activities | 795,453 | 440,515 | ||||||
Net increase in cash and cash equivalents | 539,772 | 349,366 | ||||||
Cash and cash equivalents, beginning of period | 29,321 | 198,153 | ||||||
Cash and cash equivalents, end of period | $ | 569,093 | $ | 547,519 | ||||
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Laredo Petroleum, Inc.
Selected operating data
Three months ended March 31, | ||||||||
2015 | 2014 | |||||||
(unaudited) | ||||||||
Sales volumes(1): | ||||||||
Oil (MBbl) | 2,172 | 1,421 | ||||||
NGL (MBbl) | 989 | — | ||||||
Natural gas (MMcf) | 6,680 | 6,076 | ||||||
Oil equivalents (MBOE)(2)(3) | 4,274 | 2,434 | ||||||
Average daily sales volumes (BOE/D)(3) | 47,487 | 27,041 | ||||||
% Oil | 51 | % | 58 | % | ||||
Average sales prices(1): | ||||||||
Oil, realized ($/Bbl)(4) | $ | 41.73 | $ | 91.78 | ||||
NGL, realized ($/Bbl)(4) | $ | 13.34 | $ | — | ||||
Natural gas, realized ($/Mcf)(4) | $ | 2.14 | $ | 7.04 | ||||
Average price, realized ($/BOE)(4) | $ | 27.64 | $ | 71.17 | ||||
Oil, hedged ($/Bbl)(5) | $ | 69.51 | $ | 89.94 | ||||
NGL, hedged ($/Bbl)(5) | $ | 13.34 | $ | — | ||||
Natural gas, hedged ($/Mcf)(5) | $ | 2.35 | $ | 6.92 | ||||
Average price, hedged ($/BOE)(5) | $ | 42.08 | $ | 69.79 | ||||
Average costs per BOE sold(1): | ||||||||
Lease operating expenses | $ | 7.58 | $ | 8.95 | ||||
Midstream service expenses | 0.37 | 0.35 | ||||||
Production and ad valorem taxes | 2.13 | 5.12 | ||||||
General and administrative(6) | 5.11 | 11.36 | ||||||
Depletion, depreciation and amortization | 16.83 | 20.38 | ||||||
Total | $ | 32.02 | $ | 46.16 | ||||
_______________________________________________________________________________
(1) | For periods prior to January 1, 2015, we presented our sales volumes, average sales prices for oil and natural gas and average costs per BOE sold, which combined NGL with the natural gas stream, and did not separately report NGL. This change impacts the comparability of the two periods presented. |
(2) | Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl. |
(3) | The volumes presented are based on actual results and are not calculated using the rounded numbers presented in the table above. |
(4) | Realized oil, NGL and natural gas prices are the actual prices realized at the wellhead after all adjustments for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price at the wellhead. The prices presented are based on actual results and are not calculated using the rounded numbers presented in the table above. |
(5) | Hedged prices reflect the after-effect of our commodity hedging transactions on our average sales prices. Our calculation of such after-effects include current period settlements of matured commodity derivatives in accordance with GAAP and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to instruments that settled in the period. The prices presented are based on actual results and are not calculated using the rounded numbers presented in the table above. |
(6) | General and administrative includes non-cash stock-based compensation, net of amount capitalized, of $4.8 million and $4.3 million for the three months ended March 31, 2015 and 2014, respectively. |
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Laredo Petroleum, Inc.
Costs incurred
Costs incurred in the acquisition, exploration and development of oil and natural gas assets are presented below for the periods presented:
_______________________________________________________________________________
Three months ended March 31, | ||||||||
(in thousands) | 2015 | 2014 | ||||||
(unaudited) | ||||||||
Property acquisition costs: | ||||||||
Evaluated | $ | — | $ | 25 | ||||
Unevaluated | — | 7,280 | ||||||
Exploration | 4,513 | 8,499 | ||||||
Development costs(1) | 206,672 | 188,313 | ||||||
Total costs incurred | $ | 211,185 | $ | 204,117 | ||||
(1) | The costs incurred for oil and natural gas development activities include $0.5 million and $0.6 million in asset retirement obligations for the three months ended March 31, 2015 and 2014, respectively. |
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Laredo Petroleum, Inc.
Supplemental reconciliation of GAAP to non-GAAP financial measures
(Unaudited)
Non-GAAP financial measures
The non-GAAP financial measures of Adjusted Net Income and Adjusted EBITDA, as defined by us, may not be comparable to similarly titled measures used by other companies. Therefore, these non-GAAP measures should be considered in conjunction with net income or loss and other performance measures prepared in accordance with GAAP, such as operating income or loss or cash flow from operating activities. Adjusted Net Income or Adjusted EBITDA should not be considered in isolation or as a substitute for GAAP measures, such as net income or loss, operating income or loss or any other GAAP measure of liquidity or financial performance.
Adjusted Net Income
Adjusted Net Income is a non-GAAP financial measure used by the Company to evaluate performance, prior to total gains or losses on derivatives, cash settlements of matured commodity derivatives, cash settlements on early terminated commodity derivatives, impairment expense, restructuring expenses, gains or losses on sale of assets, write-off of debt issuance costs and bad debt expense.
The following presents a reconciliation of net loss to Adjusted Net Income:
Three months ended March 31, | ||||||||
(in thousands, except for per share data, unaudited) | 2015 | 2014 | ||||||
Net loss | $ | (472 | ) | $ | (213 | ) | ||
Plus: | ||||||||
(Gain) loss on derivatives, net | (63,155 | ) | 31,112 | |||||
Cash settlements received (paid) for matured commodity derivatives, net | 63,141 | (1,431 | ) | |||||
Cash settlements received for early terminations of commodity derivatives, net | — | 76,660 | ||||||
Impairment expense | 878 | — | ||||||
Restructuring expenses | 6,042 | — | ||||||
Loss on disposal of assets, net | 762 | 21 | ||||||
Write-off of debt issuance costs | — | 124 | ||||||
7,196 | 106,273 | |||||||
Income tax adjustment(1) | (2,760 | ) | (37,270 | ) | ||||
Adjusted Net Income | $ | 4,436 | $ | 69,003 | ||||
Adjusted Net Income per common share: | ||||||||
Basic | $ | 0.03 | $ | 0.49 | ||||
Diluted | $ | 0.03 | $ | 0.49 | ||||
Weighted-average common shares outstanding: | ||||||||
Basic | 162,426 | 141,067 | ||||||
Diluted | 162,426 | 141,067 | ||||||
(1) | The income tax adjustment for the three months ended March 31, 2015 and 2014 is calculated by applying the estimated annual effective tax rate of 36% and 35%, respectively. |
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Adjusted EBITDA
Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss plus adjustments for interest expense, depletion, depreciation and amortization, impairment expense, restructuring expenses, write-off of debt issuance costs, bad debt expense, gains or losses on disposal of assets, total gains or losses on derivatives, cash settlements of matured commodity derivatives, cash settlements on early terminated commodity derivatives, premiums paid for derivatives that matured during the period, non-cash stock-based compensation and income tax expense or benefit. Adjusted EBITDA provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position. Adjusted EBITDA does not represent funds available for discretionary use because those funds are required for debt service, capital expenditures and working capital, income taxes, franchise taxes and other commitments and obligations. However, our management believes Adjusted EBITDA is useful to an investor in evaluating our operating performance because this measure:
• | is widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods, book value of assets, capital structure and the method by which assets were acquired, among other factors; |
• | helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and |
• | is used by our management for various purposes, including as a measure of operating performance, in presentations to our board of directors and as a basis for strategic planning and forecasting. |
There are significant limitations to the use of Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations to different companies and the different methods of calculating Adjusted EBITDA reported by different companies. Our measurements of Adjusted EBITDA for financial reporting as compared to compliance under our debt agreements differ.
The following presents a reconciliation of net loss to Adjusted EBITDA:
Three months ended March 31, | ||||||||
(in thousands, unaudited) | 2015 | 2014 | ||||||
Net loss | $ | (472 | ) | $ | (213 | ) | ||
Plus: | ||||||||
Interest expense | 32,414 | 28,986 | ||||||
Depletion, depreciation and amortization | 71,942 | 49,607 | ||||||
Impairment expense | 878 | — | ||||||
Restructuring expenses | 6,042 | — | ||||||
Write-off of debt issuance costs | — | 124 | ||||||
Loss on disposal of assets, net | 762 | 21 | ||||||
(Gain) loss on derivatives, net | (63,155 | ) | 31,112 | |||||
Cash settlements received (paid) for matured commodity derivatives, net | 63,141 | (1,431 | ) | |||||
Cash settlements received for early terminations of commodity derivatives, net | — | 76,660 | ||||||
Premiums paid for derivatives that matured during the period(1) | (1,421 | ) | (1,959 | ) | ||||
Non-cash stock-based compensation, net of amounts capitalized | 4,788 | 4,329 | ||||||
Deferred income tax expense | 3,643 | 107 | ||||||
Adjusted EBITDA | $ | 118,562 | $ | 187,343 | ||||
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(1) | Reflects premiums incurred previously or upon settlement that are attributable to instruments settled in the respective periods presented. |
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