TULSA, OK, Feb. 16, 2016 (GLOBE NEWSWIRE) -- Laredo Petroleum, Inc. LPI ("Laredo" or the "Company") today announced its 2015 fourth-quarter and full-year results. For the fourth quarter of 2015, the Company reported a net loss attributable to common stockholders of $964.6 million, or $4.57 per diluted share, which includes a pre-tax, non-cash full cost ceiling impairment charge of $975.0 million. Adjusted Net Income, a non-GAAP financial measure, for the fourth quarter of 2015 was $12.9 million, or $0.06 per diluted share. Adjusted EBITDA, a non-GAAP financial measure, for the fourth quarter of 2015 was $115.9 million. For the year ended December 31, 2015, the Company reported a net loss attributable to common stockholders of $2.2 billion, or $11.10 per diluted share, including a pre-tax, non-cash full cost ceiling impairment charge of $2.4 billion. Adjusted Net Income was $46.1 million, or $0.23 per diluted share, and Adjusted EBITDA was $472.3 million.
2015 Highlights
- Produced a Company record 16.3 million barrels of oil equivalent ("MMBOE") in 2015, an increase of approximately 18% from 2014
- Reduced unit general and administrative expenses to $5.53 per barrel of oil equivalent ("BOE") in 2015 from $7.67 in 2014, a decrease of approximately 28%, on a three-stream basis
- Reduced unit cash costs approximately 23% to $13.03 per BOE in 2015 from $17.01 in 2014, on a three-stream basis
- Commenced full operations of the Medallion pipeline system, which is 49%-owned by Laredo Midstream Services, LLC ("LMS"), growing transported volumes on the system to an average of approximately 69,000 barrels of oil per day ("BOPD") in the fourth quarter of 2015
- Expanded the Medallion pipeline system delivery points to Crane and Midland, Texas, which will increase the system's deliverable capacity to 500,000 BOPD, when completed
- Received approximately $255.3 million of cash settlements on commodity derivatives that matured during 2015, increasing the average sales price for oil by $31.14 per barrel and for natural gas by $0.49 per thousand cubic feet compared to pre-hedged average sales prices
Please see supplemental financial information at the end of this news release for reconciliations of the non-GAAP financial measures.
"In January of 2015, Laredo took the steps we felt were necessary at the time for the Company to continue to efficiently operate in an extended low commodity price environment while refining and enhancing the Company's development plan for its Permian-Garden City acreage," commented Randy A. Foutch, Laredo Chairman and Chief Executive Officer. "We recognized the potential of a longer duration commodity price downturn and took appropriate measures. Within the first 70 days of 2015, we drastically reduced our capital budget, reduced our workforce by approximately 20% and completely restructured our balance sheet by executing equity and debt offerings with a combined value of more than $1 billion. These measures, coupled with hedges protecting all of our 2015 oil and natural gas production, enabled the Company to essentially operate within cash flow by mid-2015."
"Although challenging, 2015 also saw Laredo execute and improve upon our development plan, capitalizing on the Company's contiguous acreage base, prior infrastructure investments and data driven decision making. We believe our focus on utilizing our Earth Model, enhancing completions, drilling longer laterals and lowering costs through continuous efficiency improvement and infrastructure investments are optimizing well economics."
Operational Update
In the fourth quarter of 2015, Laredo produced 40,368 BOE per day, bringing average daily production for full-year 2015 to 44,782 BOE per day, an increase of approximately 18% from full-year 2014, adjusted for three-stream production of 37,882 BOE per day. The Company completed 17 horizontal wells during the fourth quarter of 2015 with an average lateral length of approximately 10,000 feet. Laredo has a 100% working interest in all 17 wells. These were completed in the Upper or Middle Wolfcamp zones. Twelve of these wells were completed at the end of December and have begun adding meaningfully to production in the first quarter of 2016.
Ten of the 17 horizontal wells completed in fourth-quarter 2015 and an additional well completed the first week of January 2016 were developed as a single 11-well project along one mile of the Company's Reagan North production corridor, utilizing the advantages of Laredo's contiguous acreage and investments in infrastructure. The production corridor infrastructure facilitated the delivery of approximately 4.75 million barrels of water to the project, enabling back-to-back completions of the 11 wells. The first wells began flowing back in late December and are all currently producing substantial amounts of completion fluids. LMS is currently recycling 100% of the flow-back water.
The 17 wells completed during the fourth quarter of 2015, plus the last horizontal well completed in January 2016 as part of the 11-well package, in the aggregate are performing above their respective oil type curves encompassed in our 1.1 MMBOE Upper Wolfcamp and 1.0 MMBOE Middle Wolfcamp type curves.
Laredo is currently operating three horizontal rigs and expects to complete nine horizontal wells in the first quarter of 2016, with an average Laredo working interest of 100%. Of the nine wells, seven target the Upper Wolfcamp, one the Middle Wolfcamp and one the Cline. Seven of the wells are expected to be completed early enough in the quarter to contribute meaningful production during the first quarter of 2016.
Well costs are benefitting from ongoing efficiency measures coupled with additional reductions in service costs. Drilling and completion efficiency improved by 39% and 16%, respectively, in 2015 from 2014. Laredo is now budgeting to drill 10,000-foot Upper and Middle Wolfcamp horizontal wells on multi-well pads at a cost of approximately $5.9 million per well, a reduction of approximately 13% from second-half 2015 well costs.
The Company is continuing to optimize completions through the use of the Earth Model and increased proppant density. During 2015, Laredo tested various increased proppant densities in 10 Earth Model optimized wells, ranging from 1,400 to 1,950 pounds of sand per lateral foot. On average, these wells are performing significantly better than wells completed with the 1,100 pounds per foot that Laredo has traditionally utilized. Although more production history is needed to determine the uplift to estimated ultimate recovery, to date, all wells in which Laredo has utilized increased sand and the Earth Model are performing, on average, approximately 30% above the oil type curve. The Company believes that the current positive results provide enough certainty for it to plan using at least 1,400 pounds of sand per foot in all wells that the Company expects to drill in the first half of 2016.
Laredo Midstream Services Update
The Company's investments in crude oil, gas and water services infrastructure provided substantial financial and operational benefits to Laredo in 2015. The accumulated reductions in lease operating expenses and capital costs, increased price realizations and realized revenue to LMS totaled approximately $13 million for full-year 2015 and are expected to total more than $21 million in 2016.
The Medallion pipeline system, in which LMS owns a 49% interest, continued to grow transported volumes. The system transported approximately 69,000 BOPD in the fourth quarter of 2015 and 15.2 million barrels of oil for full-year 2015. It is estimated that volumes will continue to grow to approximately 85,000 BOPD in the first quarter of 2016 and to approximately 150,000 BOPD by the end of 2016.
In the fourth quarter of 2015, Medallion continued to expand its system of gathering and transportation pipelines. The expansion includes the buildout of a connection to the Alon refinery in Howard County, Texas. Upon completion of the expansions, the system will have approximately 500 miles of pipeline with connections to long-haul pipelines in Colorado City, Crane and Midland, Texas with combined deliverable capacity of 500,000 BOPD.
2015 Capital Program
During the fourth quarter of 2015, Laredo invested approximately $123 million in exploration and development activities and approximately $30 million in pipelines and related infrastructure held by LMS, including investments representing the Company's 49% interest in the Medallion pipeline system. For full-year 2015, the Company invested approximately $521 million in exploration and development activities and approximately $160 million in pipelines and related infrastructure held by LMS, including investments in the Medallion pipeline system.
2016 Capital Budget
Laredo's Board of Directors approved a $345 million capital budget for 2016, excluding investments in the Medallion system and potential acquisitions, a reduction of approximately 39% from 2015. The budget includes $280 million for drilling and completions, $35 million for production facilities and $30 million for land, seismic and other capitalized costs. Included in the 2016 budgeted drilling and completions capital are $13 million for increased proppant and approximately $55 million for 10 wells that commenced drilling in 2015.
The Company expects to operate the equivalent of 2.5 horizontal rigs in 2016 and anticipates drilling 36 to 38 gross horizontal wells with an average Laredo working interest of approximately 96%. Laredo anticipates operating three horizontal rigs in the first half of 2016 and two horizontal rigs in the second half of the year. No vertical wells are planned in 2016.
The advantages afforded by Laredo's contiguous acreage base, completed infrastructure investments and concerted cost reduction efforts enable the Company to continue to drill economically in the current commodity price environment. The 2016 drilling program is focused to maximize rate of return, with more than 65% of the wells planned to be 10,000-foot laterals, approximately 80% on multi-well pads, approximately 55% on existing production corridors and approximately 95% targeting the Upper and Middle Wolfcamp zones.
Expected capital costs for Upper and Middle Wolfcamp horizontal wells drilled on two-well pads in the 2016 budget are approximately $5.25 million for 7,500-foot laterals and $5.90 million for 10,000-foot laterals. Included in these costs are pad preparation, separators, heater treaters, well-site metering and artificial lift equipment.
Laredo expects full-year 2016 production to be in the range of 15.3 MMBOE to 15.7 MMBOE. Operating cash flow, including the Company's commodity derivatives, is expected to fund 75% to 80% of the planned capital budget for the year.
Reserves
At year-end 2015, the Company adjusted its approach to booking proved undeveloped reserves ("PUD") in order to maximize its flexibility to drill the highest rate of return wells. When booking PUD reserves, the Company is required to specify the precise location and zone it intends to drill within at least five years. Over time, the order in which Laredo drills wells can be affected by how the Company targets the best rate of return, lower commodity prices and rapidly evolving technologies that enable Laredo to quickly modify development strategies. With approximately 1,100 locations believed to be capable of generating at least a 12% rate of return in the current price environment, the Company determined that reducing PUD commitments to wells to be drilled within two years provides the most flexibility to maximize its rate of return at prevailing conditions and minimize the requirement to drill wells assigned as specific PUD locations.
Laredo's proved reserves at year-end 2015 were 125.7 MMBOE, consisting of 100.4 MMBOE of proved developed reserves and 25.3 MMBOE of PUD reserves. Consistent with the Company's adjusted methodology, it booked a total of 38 horizontal PUD locations, all of which are scheduled to be drilled by the end of 2017. The reduction of 196 horizontal and 182 vertical PUD locations from year-end 2014 resulted in a 131.4 MMBOE downward revision of PUDs, on a comparable three-stream basis, due to lower prices and rig cadence. While these horizontal locations are expected to be developed in the future, based on the Company's development pace and plan, such wells are not booked as proved reserves. Laredo does not expect to develop the vertical wells previously identified as PUDs as the Company believes horizontal drilling provides a substantially better rate of return and believes it can meet its anticipated drilling obligations with horizontal wells.
Additionally, proved developed reserves decreased 27.4 MMBOE, reflecting 37.2 MMBOE in price-related downward revisions (driven by the decrease in the benchmark oil price from $91.48 as of year-end 2014 to $46.79 as of year-end 2015) and 27.9 MMBOE added from drilling activities in 2015, including PUD conversions, all on a comparable three-stream basis. Changes in reserves for 2015 are summarized below, with 2014 reserves reflected on the reported two-stream basis and 2015 reserves reflected on a three-stream basis:
| Natural | Oil | ||||||||||||
| Oil | NGL | Gas | Equivalents | ||||||||||
| MMBbls | MMBbls | Bcf | MMBOE | ||||||||||
| Beginning of year - December 31, 2014 | 140.2 | — | 642.8 | 247.3 | |||||||||
| Revisions of previous estimates | (88.9 | ) | 35.5 | (424.5 | ) | (124.2 | ) | ||||||
| Extensions, discoveries and other additions | 10.5 | 5.9 | 36.1 | 22.4 | |||||||||
| Purchases of reserves in place | — | — | — | — | |||||||||
| Sales of reserves in place | (1.6 | ) | (1.0 | ) | (5.6 | ) | (3.5 | ) | |||||
| Production | (7.6 | ) | (4.3 | ) | (26.8 | ) | (16.3 | ) | |||||
| End of year - December 31, 2015 | 52.6 | 36.1 | 222.0 | 125.7 | |||||||||
| Standardized measure - ($ millions) | $ | 830,747 | |||||||||||
| Pre-tax PV-10 - ($ millions) | $ | 830,747 | |||||||||||
Commodity Derivatives
Laredo maintains an active hedging program to reduce the variability in its anticipated cash flow due to fluctuations in commodity prices. At December 31, 2015, the Company had hedges in place for 2016 for 6,523,800 barrels of oil at a weighted-average floor price of $70.84 per barrel, representing approximately 85% to 90% of anticipated oil production for 2016. The Company had also hedged 18,666,000 million British thermal units ("MMBtu") of natural gas for 2016 at a weighted-average floor price of $3.00 per MMBtu, representing approximately 70% to 75% of anticipated natural gas production for 2016.
At December 31, 2015, for 2017, the Company had hedged 2,628,000 barrels of oil at a weighted-average floor price of $77.22 per barrel and 5,475,000 MMBtu of natural gas at a weighted-average floor price of $3.00 per MMBtu. Subsequently, the Company hedged an additional 8,040,000 MMBtu of natural gas for 2017 and currently has 13,515,000 MMBtu of natural gas hedged at a weighted-average floor price of $2.70 per MMBtu for 2017.
Guidance
The table below reflects the Company's guidance for the first quarter of 2016:
| 1Q-2016 | ||||
| Production (MMBOE) | 3.7 - 4.0 | |||
| Product % of total production: | ||||
| Crude oil | ~48% | |||
| Natural gas liquids | ~26% | |||
| Natural gas | ~26% | |||
| Price Realizations (pre-hedge): | ||||
| Crude oil (% of WTI) | ~80% | |||
| Natural gas liquids (% of WTI) | ~22% | |||
| Natural gas (% of Henry Hub) | ~67% | |||
| Operating Costs & Expenses: | ||||
| Lease operating expenses ($/BOE) | $5.75 - $6.75 | |||
| Midstream expenses ($/BOE) | $0.20 - $0.40 | |||
| Production and ad valorem taxes (% of oil, NGL and natural gas revenue) | 8.25 | % | ||
| General and administrative expenses ($/BOE) | $5.50 - $6.50 | |||
| Depletion, depreciation and amortization ($/BOE) | $10.00 - $11.00 | |||
Conference Call
On Wednesday, February 17, 2016, at 7:00 a.m. CT, Laredo will host a conference call to discuss its fourth-quarter and full-year 2015 financial and operating results. The Company invites interested parties to listen to the call via the Company's website at www.laredopetro.com, under the tab for "Investor Relations." Individuals who would like to participate on the call should dial 877.930.8286, using conference code 36181178, approximately 10 minutes prior to the scheduled conference time. A telephonic replay will be available approximately two hours after the call on February 17, 2016 through Wednesday, February 24, 2016. Participants may access this replay by dialing 855.859.2056, using conference code 36181178.
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 and the transportation of oil and natural gas from such properties, primarily in the Permian Basin of West Texas.
Additional information about Laredo may be found on its website at www.laredopetro.com.
Forward-Looking Statements
This press release and any oral statements made regarding the subject of this release, including in the conference call referenced 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 decline in prices of oil, natural gas liquids and natural gas and the related impact to financial statements as a result of asset impairments and revisions to reserve estimates, and other factors, including those and other 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, its Quarterly Report on Form 10-Q for the quarter ended September 30, 2015 and those set forth from time to time in other filings including in our to be filed Annual Report or Form 10-K for the year ended December 31, 2015 with the Securities 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 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 natural 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 potentially supporting numerous drilling locations, 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 undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases.
Laredo Petroleum, Inc.
Condensed consolidated statements of operations
| Three months ended December 31, | Year ended December 31, | |||||||||||||||
| (in thousands, except per share data) | 2015 | 2014 | 2015 | 2014 | ||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||
| Revenues: | ||||||||||||||||
| Oil, NGL and natural gas sales | $ | 83,455 | $ | 181,627 | $ | 431,734 | $ | 737,203 | ||||||||
| Midstream service revenues | 1,640 | 1,226 | 6,548 | 2,245 | ||||||||||||
| Sales of purchased oil | 38,180 | 54,437 | 168,358 | 54,437 | ||||||||||||
| Total revenues | 123,275 | 237,290 | 606,640 | 793,885 | ||||||||||||
| Costs and expenses: | ||||||||||||||||
| Lease operating expenses | 21,643 | 29,374 | 108,341 | 96,503 | ||||||||||||
| Production and ad valorem taxes | 6,411 | 12,152 | 32,892 | 50,312 | ||||||||||||
| Midstream service expenses | 1,583 | 1,833 | 5,846 | 5,429 | ||||||||||||
| Minimum volume commitments | — | 773 | 5,235 | 2,552 | ||||||||||||
| Costs of purchased oil | 41,760 | 53,967 | 174,338 | 53,967 | ||||||||||||
| Drilling rig fees | — | 527 | — | 527 | ||||||||||||
| General and administrative | 22,449 | 21,760 | 90,425 | 106,044 | ||||||||||||
| Restructuring expenses | — | — | 6,042 | — | ||||||||||||
| Accretion of asset retirement obligations | 652 | 508 | 2,423 | 1,787 | ||||||||||||
| Depletion, depreciation and amortization | 66,893 | 79,869 | 277,724 | 246,474 | ||||||||||||
| Impairment expense | 977,561 | 3,904 | 2,374,888 | 3,904 | ||||||||||||
| Total costs and expenses | 1,138,952 | 204,667 | 3,078,154 | 567,499 | ||||||||||||
| Operating income (loss) | (1,015,677 | ) | 32,623 | (2,471,514 | ) | 226,386 | ||||||||||
| Non-operating income (expense): | ||||||||||||||||
| Gain on derivatives, net | 72,455 | 329,367 | 214,291 | 327,920 | ||||||||||||
| Income (loss) from equity method investee | 2,214 | (106 | ) | 6,799 | (192 | ) | ||||||||||
| Interest expense | (23,487 | ) | (30,981 | ) | (103,219 | ) | (121,173 | ) | ||||||||
| Loss on early redemption of debt | — | — | (31,537 | ) | — | |||||||||||
| Other, net | (152 | ) | (850 | ) | (1,701 | ) | (3,082 | ) | ||||||||
| Non-operating income, net | 51,030 | 297,430 | 84,633 | 203,473 | ||||||||||||
| Income (loss) before income taxes | (964,647 | ) | 330,053 | (2,386,881 | ) | 429,859 | ||||||||||
| Income tax (expense) benefit: | ||||||||||||||||
| Deferred | — | (128,775 | ) | 176,945 | (164,286 | ) | ||||||||||
| Total income tax (expense) benefit | — | (128,775 | ) | 176,945 | (164,286 | ) | ||||||||||
| Net income (loss) | $ | (964,647 | ) | $ | 201,278 | $ | (2,209,936 | ) | $ | 265,573 | ||||||
| Net income (loss) per common share: | ||||||||||||||||
| Basic | $ | (4.57 | ) | $ | 1.42 | $ | (11.10 | ) | $ | 1.88 | ||||||
| Diluted | $ | (4.57 | ) | $ | 1.40 | $ | (11.10 | ) | $ | 1.85 | ||||||
| Weighted-average common shares outstanding: | ||||||||||||||||
| Basic | 211,255 | 141,464 | 199,158 | 141,312 | ||||||||||||
| Diluted | 211,255 | 143,694 | 199,158 | 143,554 | ||||||||||||
Laredo Petroleum, Inc.
Condensed consolidated balance sheets
| (in thousands) | December 31, 2015 | December 31, 2014 | ||||||
| Assets: | (unaudited) | (unaudited) | ||||||
| Current assets | $ | 332,232 | $ | 365,253 | ||||
| Net property and equipment | 1,200,255 | 3,354,082 | ||||||
| Other noncurrent assets | 280,800 | 191,366 | ||||||
| Total assets | $ | 1,813,287 | $ | 3,910,701 | ||||
| Liabilities and stockholders' equity: | ||||||||
| Current liabilities | $ | 216,815 | $ | 353,834 | ||||
| Long-term debt, net | 1,416,226 | 1,779,447 | ||||||
| Other noncurrent liabilities | 48,799 | 214,219 | ||||||
| Stockholders' equity | 131,447 | 1,563,201 | ||||||
| Total liabilities and stockholders' equity | $ | 1,813,287 | $ | 3,910,701 | ||||
Laredo Petroleum, Inc.
Condensed consolidated statements of cash flows
| Three months ended December 31, | Year ended December 31, | |||||||||||||||
| (in thousands) | 2015 | 2014 | 2015 | 2014 | ||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||
| Cash flows from operating activities: | ||||||||||||||||
| Net income (loss) | $ | (964,647 | ) | $ | 201,278 | $ | (2,209,936 | ) | $ | 265,573 | ||||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||||
| Deferred income tax expense (benefit) | — | 128,775 | (176,945 | ) | 164,286 | |||||||||||
| Depletion, depreciation and amortization | 66,893 | 79,869 | 277,724 | 246,474 | ||||||||||||
| Impairment expense | 977,561 | 3,904 | 2,374,888 | 3,904 | ||||||||||||
| Loss on early redemption of debt | — | — | 31,537 | — | ||||||||||||
| Bad debt expense | 148 | 342 | 255 | 342 | ||||||||||||
| Non-cash stock-based compensation, net of amounts capitalized | 6,576 | 6,160 | 24,509 | 23,079 | ||||||||||||
| Accretion of asset retirement obligations | 652 | 508 | 2,423 | 1,787 | ||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||||
| Gain on derivatives, net | (72,455 | ) | (329,367 | ) | (214,291 | ) | (327,920 | ) | ||||||||
| Cash settlements received for matured derivatives, net | 79,402 | 29,561 | 255,281 | 28,241 | ||||||||||||
| Cash settlements received for early terminations of derivatives, net | — | — | — | 76,660 | ||||||||||||
| Cash premiums paid for derivatives | (1,249 | ) | (1,820 | ) | (5,167 | ) | (7,419 | ) | ||||||||
| Amortization of debt issuance costs | 1,115 | 1,314 | 4,727 | 5,137 | ||||||||||||
| Other, net | (1,959 | ) | 1,163 | (7,203 | ) | 4,191 | ||||||||||
| Cash flows from operations before changes in working capital | 92,037 | 121,687 | 357,802 | 484,335 | ||||||||||||
| Changes in working capital | (2,839 | ) | (32 | ) | (46,055 | ) | 10,516 | |||||||||
| Changes in other noncurrent liabilities and fair value of performance unit awards | 1,245 | 286 | 4,200 | 3,426 | ||||||||||||
| Net cash provided by operating activities | 90,443 | 121,941 | 315,947 | 498,277 | ||||||||||||
| Cash flows from investing activities: | ||||||||||||||||
| Capital expenditures: | ||||||||||||||||
| Acquisitions of oil and natural gas properties | — | — | — | (6,493 | ) | |||||||||||
| Acquisition of mineral interests | — | — | — | (7,305 | ) | |||||||||||
| Oil and natural gas properties | (97,666 | ) | (326,636 | ) | (588,017 | ) | (1,251,757 | ) | ||||||||
| Midstream service assets | (222 | ) | (15,285 | ) | (35,459 | ) | (60,548 | ) | ||||||||
| Other fixed assets | (586 | ) | (13,832 | ) | (9,125 | ) | (27,444 | ) | ||||||||
| Investment in equity method investee | (36,844 | ) | (17,583 | ) | (99,855 | ) | (55,164 | ) | ||||||||
| Proceeds from dispositions of capital assets, net of costs | (312 | ) | 123 | 64,949 | 1,750 | |||||||||||
| Net cash used in investing activities | (135,630 | ) | (373,213 | ) | (667,507 | ) | (1,406,961 | ) | ||||||||
| Cash flows from financing activities: | ||||||||||||||||
| Borrowings on Senior Secured Credit Facility | — | 225,000 | 310,000 | 300,000 | ||||||||||||
| Payments on Senior Secured Credit Facility | — | — | (475,000 | ) | — | |||||||||||
| Issuance of March 2023 and January 2022 Notes | — | — | 350,000 | 450,000 | ||||||||||||
| Redemption of January 2019 Notes | — | — | (576,200 | ) | — | |||||||||||
| Proceeds from issuance of common stock, net of offering costs | — | — | 754,163 | — | ||||||||||||
| Other, net | (62 | ) | (167 | ) | (9,570 | ) | (10,148 | ) | ||||||||
| Net cash (used) provided by financing activities | (62 | ) | 224,833 | 353,393 | 739,852 | |||||||||||
| Net (decrease) increase in cash and cash equivalents | (45,249 | ) | (26,439 | ) | 1,833 | (168,832 | ) | |||||||||
| Cash and cash equivalents, beginning of period | 76,403 | 55,760 | 29,321 | 198,153 | ||||||||||||
| Cash and cash equivalents, end of period | $ | 31,154 | $ | 29,321 | $ | 31,154 | $ | 29,321 | ||||||||
Laredo Petroleum, Inc.
Selected operating data
| Three months ended December 31, | Year ended December 31, | |||||||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||
| Sales volumes:(1) | ||||||||||||||||
| Oil (MBbl) | 1,656 | 2,189 | 7,610 | 6,901 | ||||||||||||
| NGL (MBbl) | 1,033 | — | 4,267 | — | ||||||||||||
| Natural gas (MMcf) | 6,153 | 8,789 | 26,816 | 28,965 | ||||||||||||
| Oil equivalents (MBOE)(2)(3) | 3,714 | 3,655 | 16,346 | 11,729 | ||||||||||||
| Average daily sales volumes (BOE/D)(3) | 40,368 | 39,722 | 44,782 | 32,134 | ||||||||||||
| % Oil | 45 | % | 60 | % | 47 | % | 59 | % | ||||||||
| Average sales prices:(1) | ||||||||||||||||
| Oil, realized ($/Bbl)(4) | $ | 36.97 | $ | 65.05 | $ | 43.27 | $ | 82.83 | ||||||||
| NGL, realized ($/Bbl)(4) | 11.06 | — | 11.86 | — | ||||||||||||
| Natural gas, realized ($/Mcf)(4) | 1.76 | 4.46 | 1.93 | 5.72 | ||||||||||||
| Average price, realized ($/BOE)(4) | 22.47 | 49.70 | 26.41 | 62.86 | ||||||||||||
| Oil, hedged ($/Bbl)(5) | 80.61 | 77.25 | 74.41 | 85.77 | ||||||||||||
| NGL, hedged ($/Bbl)(5) | 11.06 | — | 11.86 | — | ||||||||||||
| Natural gas, hedged ($/Mcf)(5) | 2.72 | 4.58 | 2.42 | 5.73 | ||||||||||||
| Average price, hedged ($/BOE)(5) | 43.51 | 57.30 | 41.71 | 64.62 | ||||||||||||
| Average costs per BOE sold:(1) | ||||||||||||||||
| Lease operating expenses | $ | 5.83 | $ | 8.04 | $ | 6.63 | $ | 8.23 | ||||||||
| Production and ad valorem taxes | 1.73 | 3.32 | 2.01 | 4.29 | ||||||||||||
| Midstream service expenses | 0.43 | 0.50 | 0.36 | 0.46 | ||||||||||||
| General and administrative(6) | 6.04 | 5.95 | 5.53 | 9.04 | ||||||||||||
| Depletion, depreciation and amortization | 18.01 | 21.85 | 16.99 | 21.01 | ||||||||||||
| Total | $ | 32.04 | $ | 39.66 | $ | 31.52 | $ | 43.03 | ||||||||
_______________________________________________________________________________
(1) For periods prior to January 1, 2015, we presented our sales volumes, average sales prices and average costs per BOE sold for oil and natural gas, which combined NGL with the natural gas stream, and did not separately report NGL. This change impacts the comparability of the 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 adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received 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 amounts capitalized, of $6.6 million and $6.2 million for the three months ended December 31, 2015 and 2014, respectively, and $24.5 million and $23.1 million for the years ended December 31, 2015 and 2014, respectively. Excluding stock-based compensation, net of amounts capitalized, from the above metric results in general and administrative cost per BOE sold of $4.27 for both the three months ended December 31, 2015 and 2014, respectively, and $4.03 and $7.07 for the years ended December 31, 2015 and 2014, respectively.
Laredo Petroleum, Inc.
Costs incurred
Costs incurred in the acquisition, exploration and development of oil, NGL and natural gas assets are presented below:
| Three months ended December 31, | Year ended December 31, | |||||||||||||||
| (in thousands) | 2015 | 2014 | 2015 | 2014 | ||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||
| Property acquisition costs: | ||||||||||||||||
| Evaluated | $ | — | $ | — | $ | — | $ | 3,873 | ||||||||
| Unevaluated | — | — | — | 9,925 | ||||||||||||
| Exploration(1) | 4,540 | 24,931 | 20,697 | 242,284 | ||||||||||||
| Development costs(2) | 118,936 | 315,646 | 500,577 | 1,049,317 | ||||||||||||
| Total costs incurred | $ | 123,476 | $ | 340,577 | $ | 521,274 | $ | 1,305,399 | ||||||||
_______________________________________________________________________________
(1) The Company acquired significant leasehold interests during the year ended December 31, 2014.
(2) The costs incurred for oil, NGL and natural gas development activities include $12.1 million and $3.8 million in asset retirement obligations for the three months ended December 31, 2015 and 2014, respectively, and $13.4 million and $6.9 million for the years ended December 31, 2015 and 2014, respectively.
Laredo Petroleum, Inc.
Supplemental reconciliations of GAAP to non-GAAP financial measures
(Unaudited)
Non-GAAP financial measures
The non-GAAP financial measures of Adjusted Net Income, Adjusted EBITDA and PV-10, 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, Adjusted EBITDA or PV-10 should not be considered in isolation or as a substitute for GAAP measures, such as net income or loss, operating income or loss, standardized measure of discounted future net cash flows or any other GAAP measure of liquidity or financial performance.
Adjusted Net Income
Adjusted Net Income is a non-GAAP financial measure we use to evaluate performance, prior to gains or losses on derivatives, cash settlements of matured commodity derivatives, cash settlements on early terminated commodity derivatives, impairment expense, restructuring expenses, loss on early redemption of debt, buyout of minimum volume commitment, gains or losses on disposal of assets, write-off of debt issuance costs, bad debt expense and after applying adjusted income tax expense. We believe Adjusted Net Income helps investors compare our results with other oil and natural gas companies. During the year ended December 31, 2015, we changed the methodology for calculating adjusted income tax expense. As such, the prior periods' adjusted income tax expense has been modified for comparability.
The following presents a reconciliation of income (loss) to Adjusted Net Income:
| Three months ended December 31, | Year ended December 31, | |||||||||||||||
| (in thousands, except for per share data, unaudited) | 2015 | 2014 | 2015 | 2014 | ||||||||||||
| Income (loss) before income taxes | $ | (964,647 | ) | $ | 330,053 | $ | (2,386,881 | ) | $ | 429,859 | ||||||
| Plus: | ||||||||||||||||
| Gain on derivatives, net | (72,455 | ) | (329,367 | ) | (214,291 | ) | (327,920 | ) | ||||||||
| Cash settlements received for matured commodity derivatives, net | 79,402 | 29,561 | 255,281 | 28,241 | ||||||||||||
| Cash settlements received for early terminations of commodity derivatives, net | — | — | — | 76,660 | ||||||||||||
| Impairment expense | 977,561 | 3,904 | 2,374,888 | 3,904 | ||||||||||||
| Restructuring expenses | — | — | 6,042 | — | ||||||||||||
| Loss on early redemption of debt | — | — | 31,537 | — | ||||||||||||
| Buyout of minimum volume commitment | — | — | 3,014 | — | ||||||||||||
| Loss on disposal of assets, net | 190 | 834 | 2,127 | 3,252 | ||||||||||||
| Write-off of debt issuance costs | — | — | — | 124 | ||||||||||||
| Bad debt expense | 148 | 342 | 255 | 342 | ||||||||||||
| 20,199 | 35,327 | 71,972 | 214,462 | |||||||||||||
| Adjusted income tax expense(1) | (7,272 | ) | (12,364 | ) | (25,910 | ) | (75,062 | ) | ||||||||
| Adjusted Net Income | $ | 12,927 | $ | 22,963 | $ | 46,062 | $ | 139,400 | ||||||||
| Adjusted Net Income per common share: | ||||||||||||||||
| Basic | $ | 0.06 | $ | 0.16 | $ | 0.23 | $ | 0.99 | ||||||||
| Diluted | $ | 0.06 | $ | 0.16 | $ | 0.23 | $ | 0.97 | ||||||||
| Weighted-average common shares outstanding: | ||||||||||||||||
| Basic | 211,255 | 141,464 | 199,158 | 141,312 | ||||||||||||
| Diluted | 211,255 | 143,694 | 199,158 | 143,554 | ||||||||||||
_______________________________________________________________________________
(1) Adjusted income tax expense is calculated by applying tax rates of 36% for the three and twelve months ended December 31, 2015, respectively, and 35% for the three and twelve months ended December 31, 2014, respectively.
Adjusted EBITDA
Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss plus adjustments for income tax expense or benefit, depletion, depreciation and amortization, bad debt expense, impairment expense, non-cash stock-based compensation, restructuring expenses, 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, interest expense, write-off of debt issuance costs, gains or losses on disposal of assets, loss on early redemption of debt and buyout of minimum volume commitment. 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 income (loss) to Adjusted EBITDA:
| Three months ended December 31, | Year ended December 31, | |||||||||||||||
| (in thousands, unaudited) | 2015 | 2014 | 2015 | 2014 | ||||||||||||
| Net income (loss) | $ | (964,647 | ) | $ | 201,278 | $ | (2,209,936 | ) | $ | 265,573 | ||||||
| Plus: | ||||||||||||||||
| Deferred income tax expense (benefit) | — | 128,775 | (176,945 | ) | 164,286 | |||||||||||
| Depletion, depreciation and amortization | 66,893 | 79,869 | 277,724 | 246,474 | ||||||||||||
| Bad debt expense | 148 | 342 | 255 | 342 | ||||||||||||
| Impairment expense | 977,561 | 3,904 | 2,374,888 | 3,904 | ||||||||||||
| Non-cash stock-based compensation, net of amounts capitalized | 6,576 | 6,160 | 24,509 | 23,079 | ||||||||||||
| Restructuring expenses | — | — | 6,042 | — | ||||||||||||
| Gain on derivatives, net | (72,455 | ) | (329,367 | ) | (214,291 | ) | (327,920 | ) | ||||||||
| Cash settlements received for matured commodity derivatives, net | 79,402 | 29,561 | 255,281 | 28,241 | ||||||||||||
| Cash settlements received for early terminations of commodity derivatives, net | — | — | — | 76,660 | ||||||||||||
| Premiums paid for derivatives that matured during the period(1) | (1,249 | ) | (1,820 | ) | (5,167 | ) | (7,419 | ) | ||||||||
| Interest expense | 23,487 | 30,981 | 103,219 | 121,173 | ||||||||||||
| Write-off of debt issuance costs | — | — | — | 124 | ||||||||||||
| Loss on disposal of assets, net | 190 | 834 | 2,127 | 3,252 | ||||||||||||
| Loss on early redemption of debt | — | — | 31,537 | — | ||||||||||||
| Buyout of minimum volume commitment | — | — | 3,014 | — | ||||||||||||
| Adjusted EBITDA | $ | 115,906 | $ | 150,517 | $ | 472,257 | $ | 597,769 | ||||||||
_______________________________________________________________________________
(1) Reflects premiums incurred previously or upon settlement that are attributable to instruments settled in the respective periods presented.
PV-10
PV-10 is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas assets. However, PV-10 is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil, NGL and natural gas reserves.
| (in thousands, unaudited) | December 31, 2015 | |||
| Pre-tax PV-10 | $ | 830,747 | ||
| Present value of future income taxes discounted at 10% | — | |||
| Standardized measure of discounted future net cash flows | $ | 830,747 | ||
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