Attached files
| file | filename |
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| 8-K - 8-K - Laredo Petroleum, Inc. | a2q14erpr8-k.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 2014 SECOND-QUARTER
FINANCIAL AND OPERATING RESULTS
TULSA, OK - August 7, 2014 - Laredo Petroleum, Inc. (NYSE: LPI) (“Laredo” or “Company”), today announced its 2014 second-quarter results, reporting a net loss attributable to common stockholders of $18.9 million, or $0.13 per diluted share. Adjusted Net Income, a non-GAAP financial measure, for the second quarter of 2014 was $19.4 million, or $0.14 per diluted share. Adjusted EBITDA, a non-GAAP financial measure, for the second quarter of 2014 was $117.9 million. (Please see supplemental financial information at the end of this news release for reconciliations of these non-GAAP financial measures.)
2014 Second-Quarter Highlights
• | Produced a Company Permian Basin record of 28,653 barrels of oil equivalent (“BOE”) per day, on a two-stream basis, up approximately 13% from the second quarter of 2013 and up approximately 6% from first-quarter 2014 |
• | Completed 19 horizontal wells during the quarter with a mean 30-day average initial production (“IP”) rate of 702 BOE per day (“BOE/D”), on a two-stream basis |
• | Completed the Company’s first pad of two extended long-lateral horizontal wells in the Upper Wolfcamp and Cline zones with 30-day average IP rates of 1,155 BOE/D and 1,463 BOE/D, respectively, on a two-stream basis |
• | Commenced additional operations at the end of second-quarter 2014 on the Company’s first production corridor, with centralized gas lift, rig fuel supply facilities and the crude gathering system |
• | Completed the Company’s first four-stacked lateral pad, targeting the Upper, Middle and Lower Wolfcamp and Cline zones, and utilized the water management facilities in the production corridor to deliver the water needed to simultaneously complete four horizontal wells on a common pad |
• | Acquired or entered into agreements to acquire 9,741 net acres of additional leasehold interests in the Midland Basin since the beginning of the second quarter to date, primarily within the Company’s core development area, for an aggregate purchase price of approximately $203 million |
“Our high-quality acreage position continues to yield significant advantages as we build production corridors to support our transition into full-scale development drilling,” said Randy A. Foutch, Laredo Chairman and Chief Executive Officer. “As we accelerate drilling activities and their concentration along the corridors, we expect to realize additional capital savings per well, lower lease operating expenses and enhanced wellhead
realizations. The increased capital efficiency inherent in concentrated drilling, coupled with the ability to begin optimizing completions, is a key driver of well economics as we grow Permian production approximately 25% this year. Selectively adding contiguous acreage is enabling us to add or expand new production corridors and gain additional operating efficiencies. The benefits of our concentrated asset base, infrastructure investments and stacked lateral program are beginning to accrue and we believe will become more impactful as we aggressively accelerate the development of this tremendous resource.”
Operational Update
In the second quarter of 2014, Laredo set another Company record for production from the Permian Basin of 28,653 BOE/D, an increase of approximately 13% from the second quarter of 2013. The Company completed 19 horizontal wells during the second quarter of 2014, 15 of which were drilled as stacked laterals on multi-well pads. Four of the 19 completions were four-stacked laterals from a single pad that targeted the Upper, Middle and Lower Wolfcamp and Cline zones, nine of the completions were three-stacked laterals on three pads that targeted the Upper, Middle and Lower Wolfcamp zones and two completions were two-stacked laterals from a single pad that targeted the Upper Wolfcamp and Cline zones. The four remaining horizontal completions were from single-well pads, three of which targeted the Upper Wolfcamp zone and one which targeted the Cline zone.
The 19 horizontal wells completed in the second quarter of 2014 had a mean 30-day average IP rate of 702 BOE/D. The average lateral length for those wells was 7,149 feet and the average oil cut was 75%. Three of the completed horizontal wells targeted the Cline zone, producing a mean 30-day average IP rate per 1,000 feet of lateral of 124 BOE/D with an average lateral length of 8,089 feet. Two of the horizontal wells the Company completed were extended long-laterals, one targeting the Upper Wolfcamp with a 9,348-foot lateral and one targeting the Cline with a 9,679-foot lateral. The 30-day average IP rates of 1,155 BOE/D and 1,463 BOE/D for the Upper Wolfcamp and Cline, respectively, indicate enhanced rates of return compared to shorter laterals. The Company will continue to analyze the results of the longer laterals and incorporate similar wells in future drilling activity as appropriate.
The Company exited the second quarter with 14 horizontal wells drilled and uncompleted, 10 of which were on multi-well pads. Stimulation operations were under way on four of these wells, nine wells were being prepared for completion, and one well was not available for completion due to being part of a multi-well pad where drilling operations were continuing. The Company is currently operating seven horizontal rigs and expects to complete approximately 20 horizontal wells that could achieve peak production during the third quarter of 2014.
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Leasehold Acquisitions
Since the beginning of the second quarter of 2014 to date, the Company acquired or entered into agreements to acquire 9,741 net acres in the Midland Basin for approximately $203 million. The addition of this acreage furthers the Company’s strategy of efficiently developing its Permian-Garden City asset with high working interest, long lateral horizontal wells. In Reagan County, approximately 6,900 of the new net acres are adjacent to the Company’s full-scale development area and combine with existing leasehold to bring the Company’s working interest in the leases to approximately 100%. The contiguous nature of the leases will enable Laredo to construct at least two additional production corridors that are expected to provide a meaningful benefit in the efficient development of the acreage.
The acquisitions are expected to add approximately 280 gross horizontal drilling locations in the Upper, Middle and Lower Wolfcamp and Cline zones and an estimated net resource potential of approximately 142 million BOE.
The Company continues to evaluate acreage acquisitions that are contiguous to existing leasehold with the goal of optimizing drilling geometry, facilitating production corridors or increasing working interest. These attributes further the Company’s existing plan to efficiently develop the entire resource in the four currently delineated zones, with the ability to incorporate additional zones as they are delineated.
Laredo Midstream Services Update
The Company’s wholly-owned subsidiary, Laredo Midstream Services, has made significant progress to support a concentrated field development program through the construction of our initial production corridor, located in Reagan County. During the second quarter, centralized gas lift facilities began operations and to date, 16 horizontal wells have been tied into the centralized gas lift facility. The corridor’s oil gathering system began operations late in the quarter and is currently delivering approximately 6,000 gross barrels of oil per day into the Company’s Reagan Oil Station. The direct connection of wells to the Reagan Oil Station eliminates the need, potential delays and costs associated with trucking and is projected to enhance wellhead realizations by approximately $0.95 per barrel on these volumes. As new wells are developed along the corridor, the oil gathering system has the capacity to accommodate additional volumes.
Capital Program
During the second quarter of 2014, Laredo invested approximately $235 million in drilling and completion capital expenditures, with approximately $220 million allocated to development activities, approximately $8 million for exploration and approximately $7 million in bolt-on acquisitions, all within the Permian-Garden
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City area. Additionally, approximately $15 million was invested in pipelines and related infrastructure assets held by Laredo Midstream Services.
Liquidity
At June 30, 2014, the Company had approximately $400 million in cash and cash equivalents and an undrawn senior secured credit facility, which had $825 million available for borrowings, resulting in total liquidity of more than $1.2 billion.
Commodity Derivatives
Laredo maintains an active hedging program to underpin its capital program and reduce the variability in its anticipated cash flow due to fluctuations in commodity prices. At August 6, 2014, the Company had hedges in place for the third and fourth quarters of 2014 for 3,114,998 barrels of oil at a weighted-average floor price of $89.45 per barrel, representing approximately 85% of anticipated oil production for the third and fourth quarters of 2014. Additionally, the Company had hedges in place for the third and fourth quarters of 2014 for 10,964,000 million British thermal units (“MMBtu”) of natural gas at a weighted-average floor price of $3.66 per MMBtu, representing approximately 50% of anticipated natural gas production for the second half of 2014.
Guidance
The table below reflects the Company’s guidance for the third and fourth quarters and full-year 2014:
3Q-2014 | 4Q-2014 | FY-2014 | ||||
Production (MMBOE) | 2.9 - 3.2 | 3.2 - 3.5 | 11.1 - 11.7 | |||
Crude Oil % of production | 58% | 58% | 58% | |||
Price Realizations (pre-hedge, two-stream basis, % of NYMEX): | ||||||
Crude oil | 90% - 95% | 90% - 95% | 90% - 95% | |||
Natural gas, including natural gas liquids | 135% - 145% | 135% - 145% | 135% - 145% | |||
Operating Costs & Expenses: | ||||||
Lease operating expenses ($/BOE) | $7.25 - $7.75 | $7.00 - $7.50 | $7.50 - $8.00 | |||
Production and ad valorem taxes (% of oil and gas revenue) | 7.25% | 7.25% | 7.25% | |||
General and administrative expenses ($/BOE) | $9.75 - $10.25 | $9.50 - $10.00 | $10.25 - $10.75 | |||
Depletion, depreciation and amortization ($/BOE) | $20.00 - $21.00 | $20.00 - $21.00 | $20.00 - $21.00 | |||
Midstream Expenses ($/BOE) | $0.75 - $0.85 | $0.80 - $0.90 | $0.70 - $0.80 | |||
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Conference Call Details
Laredo has scheduled a conference call today at 9:00 a.m. CT to discuss its second-quarter 2014 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 1-866-515-2910, using the conference code 74636508. International participants may access the call by dialing 1-617-399-5124, also using conference code 74636508. 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 August 7, 2014 through Thursday, August 14, 2014. Participants may access this replay by dialing 1-888-286-8010, using conference code 20677420.
About Laredo
Laredo Petroleum, Inc. is an independent energy company with headquarters in Tulsa, Oklahoma. Laredo's business strategy is focused on the exploration, development and acquisition of oil and natural gas properties primarily in the Permian region of the United States.
Additional information about Laredo may be found on its website at www.laredopetro.com.
Forward-Looking Statements
This press release (and oral statements made regarding the subjects of this release, including any statements made on the conference call announced herein) contains 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.
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, 2013, and those set forth from time to time in other filings with the Securities and Exchange Commission (“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. The Company may use the term “resource potential” which the SEC guidelines restrict from being included in filings with the SEC
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without strict compliance with SEC definitions or “recoverable resource” which refers to the Company’s internal estimates of booked reserves plus resource potential.“Resource potential” refers 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. Unbooked resource potential does not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules and does not include any proved reserves. Actual quantities that may be ultimately recovered from the Company’s interests will differ substantially. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and 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, the Company’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the 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 June 30, | Six months ended June 30, | |||||||||||||||
(in thousands, except per share data) | 2014 | 2013 | 2014 | 2013 | ||||||||||||
(unaudited) | (unaudited) | |||||||||||||||
Revenues: | ||||||||||||||||
Oil and natural gas sales | $ | 182,872 | $ | 177,048 | $ | 356,086 | $ | 340,673 | ||||||||
Midstream service revenue | 172 | 248 | 268 | 328 | ||||||||||||
Total revenues | 183,044 | 177,296 | 356,354 | 341,001 | ||||||||||||
Costs and expenses: | ||||||||||||||||
Lease operating expenses | 20,179 | 22,185 | 41,964 | 44,627 | ||||||||||||
Production and ad valorem taxes | 13,160 | 9,722 | 25,610 | 21,167 | ||||||||||||
Midstream service expense | 1,526 | 697 | 2,371 | 1,479 | ||||||||||||
Natural gas volume commitment - affiliates | 588 | 139 | 1,104 | 139 | ||||||||||||
General and administrative | 23,156 | 16,032 | 46,481 | 32,449 | ||||||||||||
Stock-based compensation | 6,396 | 4,463 | 10,725 | 7,680 | ||||||||||||
Accretion of asset retirement obligations | 422 | 410 | 837 | 804 | ||||||||||||
Depletion, depreciation and amortization | 53,056 | 66,234 | 102,663 | 130,737 | ||||||||||||
Total costs and expenses | 118,483 | 119,882 | 231,755 | 239,082 | ||||||||||||
Operating income | 64,561 | 57,414 | 124,599 | 101,919 | ||||||||||||
Non-operating income (expense): | ||||||||||||||||
Gain (loss) on derivatives: | ||||||||||||||||
Commodity derivatives, net | (63,125 | ) | 23,975 | (94,237 | ) | 7,121 | ||||||||||
Interest rate derivatives, net | — | (9 | ) | — | (15 | ) | ||||||||||
Loss from equity method investee | (41 | ) | (49 | ) | (25 | ) | (113 | ) | ||||||||
Interest expense | (30,657 | ) | (25,943 | ) | (59,643 | ) | (51,292 | ) | ||||||||
Other | (11 | ) | (47 | ) | (73 | ) | (32 | ) | ||||||||
Non-operating expense, net | (93,834 | ) | (2,073 | ) | (153,978 | ) | (44,331 | ) | ||||||||
Income (loss) from continuing operations before income taxes | (29,273 | ) | 55,341 | (29,379 | ) | 57,588 | ||||||||||
Income tax benefit (expense): | ||||||||||||||||
Deferred | 10,374 | (20,047 | ) | 10,267 | (21,157 | ) | ||||||||||
Total income tax benefit (expense) | 10,374 | (20,047 | ) | 10,267 | (21,157 | ) | ||||||||||
Income (loss) from continuing operations | (18,899 | ) | 35,294 | (19,112 | ) | 36,431 | ||||||||||
Income from discontinued operations, net of tax | — | 518 | — | 790 | ||||||||||||
Net income (loss) | $ | (18,899 | ) | $ | 35,812 | $ | (19,112 | ) | $ | 37,221 | ||||||
Net income (loss) per common share: | ||||||||||||||||
Basic: | ||||||||||||||||
Income (loss) from continuing operations | $ | (0.13 | ) | $ | 0.28 | $ | (0.14 | ) | $ | 0.29 | ||||||
Income from discontinued operations, net of tax | — | — | — | 0.01 | ||||||||||||
Net income (loss) per share | $ | (0.13 | ) | $ | 0.28 | $ | (0.14 | ) | $ | 0.30 | ||||||
Diluted: | ||||||||||||||||
Income (loss) from continuing operations | $ | (0.13 | ) | $ | 0.27 | $ | (0.14 | ) | $ | 0.28 | ||||||
Income from discontinued operations, net of tax | — | — | — | 0.01 | ||||||||||||
Net income (loss) per share | $ | (0.13 | ) | $ | 0.27 | $ | (0.14 | ) | $ | 0.29 | ||||||
Weighted-average common shares outstanding: | ||||||||||||||||
Basic | 141,298 | 127,362 | 141,183 | 127,281 | ||||||||||||
Diluted | 141,298 | 129,384 | 141,183 | 129,119 | ||||||||||||
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Laredo Petroleum, Inc.
Condensed consolidated balance sheets
(in thousands) | June 30, 2014 | December 31, 2013 | ||||||
Assets: | (unaudited) | |||||||
Current assets | $ | 530,621 | $ | 307,609 | ||||
Net property and equipment | 2,578,216 | 2,204,324 | ||||||
Other noncurrent assets | 72,201 | 111,827 | ||||||
Total assets | $ | 3,181,038 | $ | 2,623,760 | ||||
Liabilities and stockholders' equity: | ||||||||
Current liabilities | $ | 334,668 | $ | 253,969 | ||||
Long-term debt | 1,501,419 | 1,051,538 | ||||||
Other noncurrent liabilities | 80,642 | 45,997 | ||||||
Stockholders' equity | 1,264,309 | 1,272,256 | ||||||
Total liabilities and stockholders' equity | $ | 3,181,038 | $ | 2,623,760 | ||||
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Laredo Petroleum, Inc.
Condensed consolidated statements of cash flows
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
(in thousands) | 2014 | 2013 | 2014 | 2013 | ||||||||||||
(unaudited) | (unaudited) | |||||||||||||||
Cash flows from operating activities: | ||||||||||||||||
Net income (loss) | $ | (18,899 | ) | $ | 35,812 | $ | (19,112 | ) | $ | 37,221 | ||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||||
Deferred income tax (benefit) expense | (10,374 | ) | 20,338 | (10,267 | ) | 21,601 | ||||||||||
Depletion, depreciation and amortization | 53,056 | 66,234 | 102,663 | 131,364 | ||||||||||||
Non-cash stock-based compensation, net of amount capitalized | 6,396 | 4,463 | 10,725 | 7,680 | ||||||||||||
Accretion of asset retirement obligations | 422 | 410 | 837 | 804 | ||||||||||||
Mark-to-market on derivatives: | ||||||||||||||||
(Gain) loss on derivatives, net | 63,125 | (23,966 | ) | 94,237 | (7,106 | ) | ||||||||||
Cash settlements (paid) received for matured derivatives, net | (4,420 | ) | 981 | (5,851 | ) | 4,657 | ||||||||||
Cash settlements received for early terminations of derivatives, net | — | — | 76,660 | — | ||||||||||||
Change in net present value of deferred premiums paid for derivatives | 55 | 131 | 120 | 282 | ||||||||||||
Cash premiums paid for derivatives | (1,820 | ) | (2,827 | ) | (3,779 | ) | (5,249 | ) | ||||||||
Amortization of deferred loan costs | 1,305 | 1,333 | 2,512 | 2,627 | ||||||||||||
Write-off of deferred loan costs | — | — | 124 | — | ||||||||||||
Other | 192 | 58 | 145 | 74 | ||||||||||||
Cash flow from operations before changes in working capital | 89,038 | 102,967 | 249,014 | 193,955 | ||||||||||||
Changes in working capital | 20,471 | 9,946 | (11,710 | ) | (18,242 | ) | ||||||||||
Changes in other noncurrent liabilities and fair value of performance unit awards | 2,473 | 2,317 | 2,795 | 2,577 | ||||||||||||
Net cash provided by operating activities | 111,982 | 115,230 | 240,099 | 178,290 | ||||||||||||
Cash flows from investing activities: | ||||||||||||||||
Capital expenditures: | ||||||||||||||||
Acquisition of oil and natural gas properties | (6,493 | ) | — | (6,493 | ) | — | ||||||||||
Acquisition of mineral interests | — | — | (7,305 | ) | — | |||||||||||
Investment in equity method investee | (8,171 | ) | (2,349 | ) | (19,471 | ) | (3,287 | ) | ||||||||
Oil and natural gas properties | (225,171 | ) | (188,088 | ) | (412,211 | ) | (375,901 | ) | ||||||||
Midstream service assets | (15,389 | ) | (4,256 | ) | (25,909 | ) | (8,302 | ) | ||||||||
Other fixed assets | (5,067 | ) | (2,215 | ) | (8,436 | ) | (8,803 | ) | ||||||||
Proceeds from dispositions of capital assets, net of costs | 329 | — | 597 | — | ||||||||||||
Net cash used in investing activities | (259,962 | ) | (196,908 | ) | (479,228 | ) | (396,293 | ) | ||||||||
Cash flows from financing activities: | ||||||||||||||||
Borrowings on revolving credit facilities | — | 95,000 | — | 230,000 | ||||||||||||
Issuance of January 2022 Notes | — | — | 450,000 | — | ||||||||||||
Other | (33 | ) | (758 | ) | (9,518 | ) | (1,633 | ) | ||||||||
Net cash provided (used) by financing activities | (33 | ) | 94,242 | 440,482 | 228,367 | |||||||||||
Net increase (decrease) in cash and cash equivalents | (148,013 | ) | 12,564 | 201,353 | 10,364 | |||||||||||
Cash and cash equivalents, beginning of period | 547,519 | 31,024 | 198,153 | 33,224 | ||||||||||||
Cash and cash equivalents, end of period | $ | 399,506 | $ | 43,588 | $ | 399,506 | $ | 43,588 | ||||||||
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Laredo Petroleum, Inc.
Selected operating data
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
(unaudited) | (unaudited) | |||||||||||||||
Production data: | ||||||||||||||||
Oil (MBbl) | 1,513 | 1,423 | 2,934 | 2,845 | ||||||||||||
Natural gas (MMcf) | 6,567 | 10,841 | 12,643 | 21,060 | ||||||||||||
Oil equivalents (MBOE)(1)(2) | 2,607 | 3,230 | 5,041 | 6,355 | ||||||||||||
Average daily production (BOE/D)(2) | 28,653 | 35,494 | 27,852 | 35,110 | ||||||||||||
% Oil | 58 | % | 44 | % | 58 | % | 45 | % | ||||||||
Average sales prices: | ||||||||||||||||
Oil, realized ($/Bbl)(3) | $ | 94.47 | $ | 89.14 | $ | 93.17 | $ | 85.64 | ||||||||
Natural gas, realized ($/Mcf)(3) | $ | 6.08 | $ | 4.63 | $ | 6.54 | $ | 4.61 | ||||||||
Average price, realized ($/BOE)(3) | $ | 70.13 | $ | 54.81 | $ | 70.63 | $ | 53.62 | ||||||||
Oil, hedged ($/Bbl)(4) | $ | 90.55 | $ | 88.33 | $ | 90.25 | $ | 85.09 | ||||||||
Natural gas, hedged ($/Mcf)(4) | $ | 6.04 | $ | 4.55 | $ | 6.46 | $ | 4.64 | ||||||||
Average price, hedged ($/BOE)(4) | $ | 67.75 | $ | 54.19 | $ | 68.73 | $ | 53.47 | ||||||||
Average costs per BOE: | ||||||||||||||||
Lease operating expenses | $ | 7.74 | $ | 6.87 | $ | 8.32 | $ | 7.02 | ||||||||
Production and ad valorem taxes | 5.05 | 3.01 | 5.08 | 3.33 | ||||||||||||
Midstream service expense | 0.59 | 0.22 | 0.47 | 0.23 | ||||||||||||
General and administrative(5) | 11.34 | 6.35 | 11.35 | 6.31 | ||||||||||||
Depletion, depreciation and amortization | 20.35 | 20.51 | 20.37 | 20.57 | ||||||||||||
Total | $ | 45.07 | $ | 36.96 | $ | 45.59 | $ | 37.46 | ||||||||
_______________________________________________________________________________
(1) | Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl. |
(2) | The volumes presented are based on actual results and are not calculated using the rounded numbers presented in the table above. |
(3) | Realized oil and natural gas prices are the actual prices realized at the wellhead after all adjustments for natural gas liquid content, 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. |
(4) | 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. |
(5) | General and administrative includes non-cash stock-based compensation, net of amount capitalized, of $6.4 million and $4.5 million for the three months ended June 30, 2014 and 2013, respectively, and $10.7 million and $7.7 million for the six months ended June 30, 2014 and 2013, respectively. Excluding stock-based compensation, net of amount capitalized, from the above metric results in general and administrative cost per BOE of $8.88 and $4.96 for the three months ended June 30, 2014 and 2013, respectively, and $9.22 and $5.11 for the six months ended June 30, 2014 and 2013, 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 June 30, | Six months ended June 30, | |||||||||||||||
(in thousands) | 2014 | 2013 | 2014 | 2013 | ||||||||||||
(unaudited) | (unaudited) | |||||||||||||||
Property acquisition costs: | ||||||||||||||||
Proved | $ | 3,848 | $ | — | $ | 3,873 | $ | — | ||||||||
Unproved | 2,645 | — | 9,925 | — | ||||||||||||
Exploration | 8,143 | 12,167 | 16,642 | 20,928 | ||||||||||||
Development costs(1) | 220,240 | 165,416 | 408,553 | 322,732 | ||||||||||||
Total costs incurred | $ | 234,876 | $ | 177,583 | $ | 438,993 | $ | 343,660 | ||||||||
(1) | The costs incurred for oil and natural gas development activities include $0.9 million and $0.7 million in asset retirement obligations for the three months ended June 30, 2014 and 2013, respectively, and $1.5 million and $1.3 million for the six months ended June 30, 2014 and 2013, 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 cash flow from operating activities. Adjusted Net Income or and Adjusted EBITDA should not be considered in isolation or as a substitute for GAAP measures, such as net income or loss, operating income 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 impairment of long-lived assets, gains or losses on derivatives, cash settlements of matured commodity derivatives, cash settlements on early terminated derivatives, gains or losses on sale of assets, write-off of deferred loan costs and bad debt expense.
The following presents a reconciliation of net income (loss) to Adjusted Net Income:
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
(in thousands, except for per share data, unaudited) | 2014 | 2013 | 2014 | 2013 | ||||||||||||
Net income (loss) | $ | (18,899 | ) | $ | 35,812 | $ | (19,112 | ) | $ | 37,221 | ||||||
Plus: | ||||||||||||||||
(Gain) loss on derivatives, net | 63,125 | (23,966 | ) | 94,237 | (7,106 | ) | ||||||||||
Cash settlements (paid) received for matured commodity derivatives, net | (4,420 | ) | 1,086 | (5,851 | ) | 4,863 | ||||||||||
Cash settlements received for early terminations of derivatives, net | — | — | 76,660 | — | ||||||||||||
Loss on disposal of assets, net | 205 | 59 | 226 | 59 | ||||||||||||
Write-off of deferred loan costs | — | — | 124 | — | ||||||||||||
40,011 | 12,991 | 146,284 | 35,037 | |||||||||||||
Income tax adjustment(1) | (20,619 | ) | 8,216 | (57,889 | ) | 808 | ||||||||||
Adjusted Net Income | $ | 19,392 | $ | 21,207 | $ | 88,395 | $ | 35,845 | ||||||||
Adjusted Net Income per common share: | ||||||||||||||||
Basic | $ | 0.14 | $ | 0.17 | $ | 0.63 | $ | 0.28 | ||||||||
Diluted | $ | 0.14 | $ | 0.16 | $ | 0.63 | $ | 0.28 | ||||||||
Weighted-average common shares outstanding: | ||||||||||||||||
Basic | 141,298 | 127,362 | 141,183 | 127,281 | ||||||||||||
Diluted | 141,298 | 129,384 | 141,183 | 129,119 | ||||||||||||
(1) | The income tax adjustment is calculated by applying the effective tax rates of 35% and 36% for the three months ended June 30, 2014 and 2013, and 35% and 37% for the six months ended June 30, 2014 and 2013. |
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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 of long-lived assets, write-off of deferred loan costs, bad debt expense, gains or losses on disposal of assets, gains or losses on derivatives, cash settlements of matured commodity derivatives, cash settlements on early terminated 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 if directors, 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 income (loss) for continuing and discontinued operations to Adjusted EBITDA:
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
(in thousands, unaudited) | 2014 | 2013 | 2014 | 2013 | ||||||||||||
Net income (loss) | $ | (18,899 | ) | $ | 35,812 | $ | (19,112 | ) | $ | 37,221 | ||||||
Plus: | ||||||||||||||||
Interest expense | 30,657 | 25,943 | 59,643 | 51,292 | ||||||||||||
Depletion, depreciation and amortization | 53,056 | 66,234 | 102,663 | 131,364 | ||||||||||||
Write-off of deferred loan costs | — | — | 124 | — | ||||||||||||
Loss on disposal of assets, net | 205 | 59 | 226 | 59 | ||||||||||||
(Gain) loss on derivatives, net | 63,125 | (23,966 | ) | 94,237 | (7,106 | ) | ||||||||||
Cash settlements (paid) received for matured commodity derivatives, net | (4,420 | ) | 1,086 | (5,851 | ) | 4,863 | ||||||||||
Cash settlements received for early terminations of derivatives, net | — | — | 76,660 | — | ||||||||||||
Premiums paid for derivatives that matured during the period(1) | (1,820 | ) | (3,080 | ) | (3,779 | ) | (5,756 | ) | ||||||||
Non-cash stock-based compensation, net of amount capitalized | 6,396 | 4,463 | 10,725 | 7,680 | ||||||||||||
Deferred income tax (benefit) expense | (10,374 | ) | 20,338 | (10,267 | ) | 21,601 | ||||||||||
Adjusted EBITDA | $ | 117,926 | $ | 126,889 | $ | 305,269 | $ | 241,218 | ||||||||
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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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