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 2016 Second-Quarter Financial and Operating Results
Raises Estimated 2016 Production to 17.0 - 17.3 Million BOE
TULSA, OK - August 3, 2016 - Laredo Petroleum, Inc. (NYSE: LPI) (“Laredo” or “the Company”) today announced its 2016 second-quarter results, reporting a net loss attributable to common stockholders of $71.4 million, or $0.33 per diluted share, which includes a net loss on derivatives of approximately $68.5 million. Adjusted Net Income, a non-GAAP financial measure, for the second quarter of 2016 was $28.2 million, or $0.13 per diluted share. Adjusted EBITDA, a non-GAAP financial measure, for the second quarter of 2016 was $107.8 million. Please see supplemental financial information at the end of this news release for reconciliations of non-GAAP financial measures.
2016 Second-Quarter Highlights
• | Produced a Company record 47,667 barrels of oil equivalent (“BOE”) per day and increased anticipated production for full-year 2016 to a range midpoint of 17.15 million BOE, up 5.5% from the 16.25 million BOE midpoint of the Company's previous increased guidance and up approximately 11% from the original 2016 guidance midpoint of 15.5 million BOE |
• | Completed 16 horizontal wells with an average completed lateral length of approximately 9,700 feet, 10 of which have reached their peak 30-day initial production (“IP”) rates, averaging 1,147 BOE per day, or 135% of type curve |
• | Reduced unit lease operating expenses (“LOE”) to $4.43 per BOE, down approximately 36% from the second-quarter 2015 rate of $6.90 per BOE |
• | Recognized more than $6.4 million in cash benefits from Laredo Midstream Services, LLC (“LMS”) field infrastructure investments through reduced costs and increased revenue |
• | Grew transported volumes on the Medallion-Midland Basin pipeline system to 99,039 barrels of oil per day (“BOPD”), an increase from 34,600 BOPD in the second quarter of 2015 |
• | Received approximately $45.0 million of net cash settlements, net of premiums paid, on commodity derivatives that matured during second-quarter 2016, increasing the average sales price for oil by $19.49 per barrel and for natural gas by $0.82 per thousand cubic feet compared to pre-hedged average sales prices |
"Positive results of multiple catalysts from prior investments are driving record production volumes delivered at peer-leading unit production costs and significantly improving the Company’s capital investment efficiency," commented Randy A. Foutch, Chairman and Chief Executive Officer. "These investments in data collection, reservoir modeling, infrastructure, product takeaway and actual well testing provide a strong foundation for Laredo to continue to economically enhance value for stakeholders even in challenging industry cycles. Also, our strong hedge position provides further support to mitigate commodity price volatility and we have maintained financial flexibility with current liquidity of approximately $760 million and no public debt maturing for more than five years."
Operational Update
In the second quarter of 2016, Laredo produced a Company record 47,667 BOE per day, of which approximately 73% was oil and natural gas liquids (“NGL”). Production during the quarter demonstrated the positive impact of the Company’s long-term initiatives to collect data and invest in infrastructure to improve capital efficiency. The Earth Model coupled with optimized completions was utilized in all wells completed in second-quarter 2016, driving consistent outperformance versus the Company’s type curves. Additionally, investments in field infrastructure and centralized facilities along the Company’s production corridors enabled more efficient operations, resulting in higher production uptime and reducing the time to sales for produced oil.
Laredo’s field infrastructure investments continue to drive operating costs lower as more wells are drilled along the Company’s production corridors. In the second quarter of 2016, total LOE decreased approximately 34% from the second quarter of 2015, even as production grew, and unit LOE decreased approximately 36% from the prior-year quarter to a peer-leading rate of $4.43 per BOE. In addition to benefiting from previous infrastructure investments, LOE was positively impacted by steps taken to continuously improve field operations. Procedures to optimize and reduce chemicals usage, an enhanced SCADA production monitoring system, optimized water management and a proactive workover program all contributed to the approximately 42% reduction in unit LOE since the beginning of 2015.
Continued improvement in the Company’s pacesetting drilling operations benefited Laredo’s capital efficiency. In the second quarter of 2016, Laredo operated three horizontal rigs that drilled an average of 990 feet per day from rig acceptance to rig release, an improvement of approximately 66% from the second quarter of 2015. These efficiencies have reduced the average number of days to drill a well by approximately 36% from the second quarter of 2015, even as the Company has extended the majority of its laterals to 10,000 feet and longer.
Laredo is seeing continued improvement in well costs driven by a combination of an intense focus on drilling efficiencies and on deriving the maximum value from its service providers. On average, the Company’s well cost for 10,000-foot laterals in the Upper and Middle Wolfcamp that utilize optimized completions are approximately $6.3 million, but the Company’s most recent costs are trending to the mid $5 million level.
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The Company completed 16 horizontal development wells during the second quarter of 2016, five of which began flowback in the last half of June and had minimal impact on production during the quarter. These 16 wells have an average lateral length of approximately 9,700 feet and a working interest of 100%. The Company’s proprietary Earth Model was used on each of these wells to land and steer the lateral and aid in optimizing completions. Ten of the 16 wells have achieved peak 30-day average IP rates with the average of those 10 wells performing 35% above type curve. The results of these 10 wells are detailed in the following table.
Well Name | Zone | Completed Lateral Length (feet) | 30-Day Average IP (BOE) | % of Type Curve(1) | ||||
Sugg-E-197-198-5NU | Upper WC | 7,371 | 1,089 | 153% | ||||
Sugg-E-197-198-6NU | Upper WC | 7,438 | 959 | 134% | ||||
LPI-Cox-21-16-4NU | Upper WC | 9,892 | 1,038 | 110% | ||||
Cox-21-16-5NU | Upper WC | 9,853 | 950 | 101% | ||||
Cox-21-16-7NU | Upper WC | 9,936 | 987 | 104% | ||||
Cox-21-16-8NU | Upper WC | 9,936 | 887 | 94% | ||||
Holt-C-132-130-4NM | Middle WC | 10,491 | 1,381 | 159% | ||||
Holt-C-132-130-8NM | Middle WC | 10,671 | 1,355 | 153% | ||||
Holt-C-132-133-4SM | Middle WC | 9,757 | 1,329 | 164% | ||||
Holt-C-132-133-8SM | Middle WC | 9,937 | 1,494 | 181% | ||||
2Q-16 Average | 1,147 | 135% | ||||||
(1) Adjusted for lateral length
The Company is currently operating three horizontal rigs and anticipates completing 10 horizontal development wells during the third quarter of 2016, with an average working interest of approximately 99%. Nine of the wells target the Upper and Middle Wolfcamp and one the Cline shale. The wells are expected to have an average lateral length of approximately 11,000 feet, including four that are at least 13,000 feet, as the Company continues to benefit from its contiguous acreage position that enables the drilling of more capital efficient longer laterals.
The Company expects to move one of its three operated rigs to the Western Glasscock production corridor position during the third quarter of 2016 and anticipates accelerating development of this acreage in 2017.
Laredo Midstream Services Update
Laredo’s field infrastructure and production corridor assets continue to reduce operational costs and have increasing cash benefits to the Company. Savings from transporting water by pipe, water recycling and centralized gas lift reduced unit LOE in the second quarter of 2016 by approximately 14%, or $0.72 per BOE. As utilization of these assets has increased, the total cash benefit to Laredo for the second quarter of 2016 was approximately $6.4 million. LMS’ crude and natural gas gathering systems transported approximately 60% of the Company’s gross operated crude oil production during the quarter and approximately 58% of gross operated natural gas production. LMS’ water gathering and treatment systems gathered 58% of flowback and produced water by pipe and 22% of water used in second-quarter 2016 completions was fulfilled with recycled water from LMS’ water recycling facility.
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The Medallion Gathering & Processing, LLC pipeline system (“Medallion-Midland Basin”), in which LMS owns a 49% interest, continued to grow transported volumes at a rapid pace. Transported volumes in the second quarter of 2016 increased to an average of 99,039 BOPD, an increase of approximately 186% from the second quarter of 2015 and up approximately 19% compared to the first quarter of 2016. The Medallion-Midland Basin system is expected to transport an average of approximately 120,000 BOPD in the third quarter of 2016.
2016 Capital Program
During the second quarter of 2016, Laredo invested approximately $80 million in exploration and development activities, approximately $11 million in a previously announced bolt-on land acquisition and approximately $15 million in infrastructure held by LMS, including the Medallion-Midland Basin pipeline system.
Liquidity
At June 30, 2016, the Company had cash and equivalents of approximately $19 million and undrawn capacity under the senior secured credit facility of approximately $705 million, resulting in total liquidity of approximately $724 million. At August 2, 2016, the Company had cash and equivalents of approximately $15 million and undrawn capacity under the senior secured credit facility of approximately $745 million, resulting in total liquidity of approximately $760 million.
Commodity Derivatives
Laredo maintains an active hedging program to reduce the variability in its anticipated cash flow due to fluctuations in commodity prices while retaining meaningful upside to commodity prices. At June 30, 2016, the Company had hedges in place for the remaining two quarters of 2016 for 3,722,700 barrels of oil at a weighted-average floor price of $67.13 per barrel, representing approximately 95% of anticipated oil production for the remainder of 2016, and 9,384,000 million British thermal units (“MMBtu”) of natural gas at a weighted-average floor price of $3.00 per MMBtu, representing approximately 65% of anticipated natural gas production for 2016.
At June 30, 2016, for 2017, the Company had hedged 3,677,375 barrels of oil at a weighted-average floor price of $60.00 per barrel and 18,771,000 MMBtu of natural gas at a weighted-average floor price of $2.65 per MMBtu. Subsequently, the Company hedged an additional 2,007,500 barrels of oil for 2017 and currently has 5,684,875 barrels of oil hedged for 2017 at a weighted-average floor price of $57.01 per barrel. Additionally, the Company hedged 444,000 barrels of ethane for 2017 at $11.24 per barrel and 375,000 barrels of propane for 2017 at $22.26 per barrel.
At June 30, 2016, for 2018, the Company had hedged 2,144,375 barrels of oil at a weighted-average floor price of $55.98 per barrel and 12,855,500 MMBtu of natural gas at a weighted-average floor price of $2.50 per MMBtu.
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Increased 2016 Production Guidance and Third-Quarter 2016 Guidance
The Company is increasing full-year 2016 production guidance under its current budget from a range of 16.1-16.4 million BOE to 17.0-17.3 million BOE.
The table below reflects the Company’s guidance for the third quarter of 2016:
3Q-2016 | ||
Production (MMBOE) | 4.2 - 4.4 | |
Product % of total production: | ||
Crude oil | 45% - 47% | |
Natural gas liquids | 26% - 27% | |
Natural gas | 27% - 28% | |
Price Realizations (pre-hedge): | ||
Crude oil (% of WTI) | ~85% | |
Natural gas liquids (% of WTI) | ~25% | |
Natural gas (% of Henry Hub) | ~70% | |
Operating Costs & Expenses: | ||
Lease operating expenses ($/BOE) | $4.25 - $4.75 | |
Midstream expenses ($/BOE) | $0.15 - $0.35 | |
Production and ad valorem taxes (% of oil, NGL and natural gas revenue) | 8.25% | |
General and administrative expenses: | ||
General and administrative - cash ($/BOE) | $3.00 - $3.75 | |
General and administrative - non-cash stock-based compensation ($/BOE) | $2.25 - $3.00 | |
Depletion, depreciation and amortization ($/BOE) | $8.00 - $9.00 | |
Conference Call Details
On Thursday, August 4, 2016, at 7:30 a.m. CT, Laredo will host a conference call to discuss its second-quarter 2016 financial and operating results and management’s outlook, the content of which is not part of this earnings release. A slide presentation providing summary financial and statistical information that will be discussed on the call will be posted to the Company’s website and available for review. 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 49616756, approximately 10 minutes prior to the scheduled conference time. International participants should dial 253.336.8309, also using conference code 49616756. A telephonic replay will be available approximately two hours after the call on August 4, 2016 through Thursday, August 11, 2016. Participants may access this replay by dialing 855.859.2056, using conference code 49616756.
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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, 2015, and those set forth from time to time in other filings 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.
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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) | 2016 | 2015 | 2016 | 2015 | ||||||||||||
(unaudited) | (unaudited) | |||||||||||||||
Revenues: | ||||||||||||||||
Oil, NGL and natural gas sales | $ | 102,526 | $ | 125,554 | $ | 175,668 | $ | 243,672 | ||||||||
Midstream service revenues | 1,632 | 1,726 | 3,433 | 3,035 | ||||||||||||
Sales of purchased oil | 42,615 | 55,051 | 74,229 | 86,318 | ||||||||||||
Total revenues | 146,773 | 182,331 | 253,330 | 333,025 | ||||||||||||
Costs and expenses: | ||||||||||||||||
Lease operating expenses | 19,225 | 29,206 | 39,743 | 61,586 | ||||||||||||
Production and ad valorem taxes | 7,982 | 9,500 | 14,417 | 18,586 | ||||||||||||
Midstream service expenses | 1,178 | 1,597 | 1,787 | 3,171 | ||||||||||||
Minimum volume commitments | — | 3,579 | — | 5,235 | ||||||||||||
Costs of purchased oil | 44,012 | 54,417 | 76,958 | 85,617 | ||||||||||||
General and administrative | 20,502 | 23,208 | 39,953 | 45,063 | ||||||||||||
Restructuring expenses | — | — | — | 6,042 | ||||||||||||
Accretion of asset retirement obligations | 860 | 593 | 1,704 | 1,172 | ||||||||||||
Depletion, depreciation and amortization | 34,177 | 72,112 | 75,655 | 144,054 | ||||||||||||
Impairment expense | 963 | 489,599 | 162,027 | 490,477 | ||||||||||||
Total costs and expenses | 128,899 | 683,811 | 412,244 | 861,003 | ||||||||||||
Operating income (loss) | 17,874 | (501,480 | ) | (158,914 | ) | (527,978 | ) | |||||||||
Non-operating income (expense): | ||||||||||||||||
Loss on derivatives, net | (68,518 | ) | (63,899 | ) | (50,633 | ) | (744 | ) | ||||||||
Income from equity method investee | 3,696 | 2,914 | 5,994 | 2,481 | ||||||||||||
Interest expense | (23,512 | ) | (23,970 | ) | (47,217 | ) | (56,384 | ) | ||||||||
Loss on early redemption of debt | — | (31,537 | ) | — | (31,537 | ) | ||||||||||
Other, net | (972 | ) | (908 | ) | (1,033 | ) | (1,547 | ) | ||||||||
Non-operating expense, net | (89,306 | ) | (117,400 | ) | (92,889 | ) | (87,731 | ) | ||||||||
Loss before income taxes | (71,432 | ) | (618,880 | ) | (251,803 | ) | (615,709 | ) | ||||||||
Income tax benefit: | ||||||||||||||||
Deferred | — | 221,846 | — | 218,203 | ||||||||||||
Total income tax benefit | — | 221,846 | — | 218,203 | ||||||||||||
Net loss | $ | (71,432 | ) | $ | (397,034 | ) | $ | (251,803 | ) | $ | (397,506 | ) | ||||
Net loss per common share: | ||||||||||||||||
Basic | $ | (0.33 | ) | $ | (1.88 | ) | $ | (1.17 | ) | $ | (2.13 | ) | ||||
Diluted | $ | (0.33 | ) | $ | (1.88 | ) | $ | (1.17 | ) | $ | (2.13 | ) | ||||
Weighted-average common shares outstanding: | ||||||||||||||||
Basic | 217,564 | 211,078 | 214,562 | 186,886 | ||||||||||||
Diluted | 217,564 | 211,078 | 214,562 | 186,886 | ||||||||||||
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Laredo Petroleum, Inc.
Condensed consolidated balance sheets
(in thousands) | June 30, 2016 | December 31, 2015 | ||||||
Assets: | (unaudited) | (unaudited) | ||||||
Current assets | $ | 211,262 | $ | 332,232 | ||||
Net property and equipment | 1,144,179 | 1,200,255 | ||||||
Other noncurrent assets | 254,710 | 280,800 | ||||||
Total assets | $ | 1,610,151 | $ | 1,813,287 | ||||
Liabilities and stockholders' equity: | ||||||||
Current liabilities | $ | 153,812 | $ | 216,815 | ||||
Long-term debt, net | 1,392,877 | 1,416,226 | ||||||
Other noncurrent liabilities | 54,300 | 48,799 | ||||||
Stockholders' equity | 9,162 | 131,447 | ||||||
Total liabilities and stockholders' equity | $ | 1,610,151 | $ | 1,813,287 | ||||
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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) | 2016 | 2015 | 2016 | 2015 | ||||||||||||
(unaudited) | (unaudited) | |||||||||||||||
Cash flows from operating activities: | ||||||||||||||||
Net loss | $ | (71,432 | ) | $ | (397,034 | ) | $ | (251,803 | ) | $ | (397,506 | ) | ||||
Adjustments to reconcile net loss to net cash provided by operating activities: | ||||||||||||||||
Deferred income tax benefit | — | (221,846 | ) | — | (218,203 | ) | ||||||||||
Depletion, depreciation and amortization | 34,177 | 72,112 | 75,655 | 144,054 | ||||||||||||
Impairment expense | 963 | 489,599 | 162,027 | 490,477 | ||||||||||||
Loss on early redemption of debt | — | 31,537 | — | 31,537 | ||||||||||||
Non-cash stock-based compensation, net of amounts capitalized | 6,073 | 6,268 | 9,911 | 11,056 | ||||||||||||
Mark-to-market on derivatives: | ||||||||||||||||
Loss on derivatives, net | 68,518 | 63,899 | 50,633 | 744 | ||||||||||||
Cash settlements received for matured derivatives, net | 47,382 | 46,596 | 113,319 | 109,737 | ||||||||||||
Cash settlements received for early terminations of derivatives, net | — | — | 80,000 | — | ||||||||||||
Cash premiums paid for derivatives | (2,413 | ) | (1,249 | ) | (84,263 | ) | (2,670 | ) | ||||||||
Amortization of debt issuance costs | 1,067 | 1,124 | 2,187 | 2,501 | ||||||||||||
Other, net | (1,790 | ) | (1,166 | ) | (9,404 | ) | (2,119 | ) | ||||||||
Cash flows from operations before changes in working capital | 82,545 | 89,840 | 148,262 | 169,608 | ||||||||||||
Changes in working capital | (304 | ) | (3,209 | ) | (9,435 | ) | (57,295 | ) | ||||||||
Changes in other noncurrent liabilities and fair value of performance unit awards | (127 | ) | 809 | (196 | ) | 1,992 | ||||||||||
Net cash provided by operating activities | 82,114 | 87,440 | 138,631 | 114,305 | ||||||||||||
Cash flows from investing activities: | ||||||||||||||||
Capital expenditures: | ||||||||||||||||
Oil and natural gas properties | (91,887 | ) | (130,775 | ) | (197,042 | ) | (374,508 | ) | ||||||||
Midstream service assets | (1,488 | ) | (13,703 | ) | (3,425 | ) | (34,137 | ) | ||||||||
Other fixed assets | (202 | ) | (2,622 | ) | (832 | ) | (6,541 | ) | ||||||||
Investment in equity method investee | (16,021 | ) | — | (42,681 | ) | (14,495 | ) | |||||||||
Proceeds from dispositions of capital assets, net of costs | 132 | — | 350 | 35 | ||||||||||||
Net cash used in investing activities | (109,466 | ) | (147,100 | ) | (243,630 | ) | (429,646 | ) | ||||||||
Cash flows from financing activities: | ||||||||||||||||
Borrowings on Senior Secured Credit Facility | 35,000 | 125,000 | 120,000 | 300,000 | ||||||||||||
Payments on Senior Secured Credit Facility | (119,682 | ) | — | (144,682 | ) | (475,000 | ) | |||||||||
Issuance of March 2023 Notes | — | — | — | 350,000 | ||||||||||||
Redemption of January 2019 Notes | — | (576,200 | ) | — | (576,200 | ) | ||||||||||
Proceeds from issuance of common stock, net of offering costs | 119,310 | — | 119,310 | 754,163 | ||||||||||||
Other, net | (62 | ) | (640 | ) | (1,474 | ) | (9,350 | ) | ||||||||
Net cash provided by (used in) financing activities | 34,566 | (451,840 | ) | 93,154 | 343,613 | |||||||||||
Net increase (decrease) in cash and cash equivalents | 7,214 | (511,500 | ) | (11,845 | ) | 28,272 | ||||||||||
Cash and cash equivalents, beginning of period | 12,095 | 569,093 | 31,154 | 29,321 | ||||||||||||
Cash and cash equivalents, end of period | $ | 19,309 | $ | 57,593 | $ | 19,309 | $ | 57,593 | ||||||||
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Laredo Petroleum, Inc.
Selected operating data
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||||
(unaudited) | (unaudited) | |||||||||||||||
Sales volumes: | ||||||||||||||||
Oil (MBbl) | 2,012 | 1,938 | 4,018 | 4,110 | ||||||||||||
NGL (MBbl) | 1,153 | 1,095 | 2,219 | 2,084 | ||||||||||||
Natural gas (MMcf) | 7,038 | 7,205 | 13,834 | 13,885 | ||||||||||||
Oil equivalents (MBOE)(1)(2) | 4,338 | 4,234 | 8,542 | 8,508 | ||||||||||||
Average daily sales volumes (BOE/D)(2) | 47,667 | 46,532 | 46,935 | 47,007 | ||||||||||||
% Oil | 46 | % | 46 | % | 47 | % | 48 | % | ||||||||
Average sales prices: | ||||||||||||||||
Oil, realized ($/Bbl)(3) | $ | 39.37 | $ | 50.77 | $ | 33.45 | $ | 45.99 | ||||||||
NGL, realized ($/Bbl)(3) | $ | 12.24 | $ | 12.85 | $ | 10.44 | $ | 13.08 | ||||||||
Natural gas, realized ($/Mcf)(3) | $ | 1.31 | $ | 1.82 | $ | 1.31 | $ | 1.97 | ||||||||
Average price, realized ($/BOE)(3) | $ | 23.64 | $ | 29.65 | $ | 20.56 | $ | 28.64 | ||||||||
Oil, hedged ($/Bbl)(4) | $ | 58.86 | $ | 72.39 | $ | 57.85 | $ | 70.87 | ||||||||
NGL, hedged ($/Bbl)(4) | $ | 12.24 | $ | 12.85 | $ | 10.44 | $ | 13.08 | ||||||||
Natural gas, hedged ($/Mcf)(4) | $ | 2.13 | $ | 2.29 | $ | 2.10 | $ | 2.32 | ||||||||
Average price, hedged ($/BOE)(4) | $ | 34.00 | $ | 40.36 | $ | 33.33 | $ | 41.22 | ||||||||
Average costs per BOE sold: | ||||||||||||||||
Lease operating expenses | $ | 4.43 | $ | 6.90 | $ | 4.65 | $ | 7.24 | ||||||||
Production and ad valorem taxes | 1.84 | 2.24 | 1.69 | 2.18 | ||||||||||||
Midstream service expenses | 0.27 | 0.38 | 0.21 | 0.37 | ||||||||||||
General and administrative(5) | 4.73 | 5.48 | 4.68 | 5.30 | ||||||||||||
Depletion, depreciation and amortization | 7.88 | 17.03 | 8.86 | 16.93 | ||||||||||||
Total | $ | 19.15 | $ | 32.03 | $ | 20.09 | $ | 32.02 | ||||||||
_______________________________________________________________________________
(1) | BOE is 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, 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. |
(4) | Hedged prices reflect the after-effect of our hedging transactions on our average sales prices. Our calculation of such after-effects includes current period settlements of matured 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 amounts capitalized, of $6.1 million and $6.3 million for the three months ended June 30, 2016 and 2015, respectively, and $9.9 million and $11.1 million for the six months ended June 30, 2016 and 2015, respectively. |
10
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 June 30, | Six months ended June 30, | |||||||||||||||
(in thousands) | 2016 | 2015 | 2016 | 2015 | ||||||||||||
(unaudited) | (unaudited) | |||||||||||||||
Property acquisition costs: | ||||||||||||||||
Evaluated | $ | — | $ | — | $ | — | $ | — | ||||||||
Unevaluated | — | — | — | — | ||||||||||||
Exploration | 19,769 | 3,841 | 27,032 | 8,354 | ||||||||||||
Development costs(1) | 70,806 | 110,518 | 152,692 | 317,190 | ||||||||||||
Total costs incurred | $ | 90,575 | $ | 114,359 | $ | 179,724 | $ | 325,544 | ||||||||
(1) | The costs incurred for oil, NGL and natural gas development activities include $0.1 million and $0.5 million in asset retirement obligations for the three months ended June 30, 2016 and 2015, respectively, and $0.2 million and $1.0 million for the six months ended June 30, 2016 and 2015, respectively. |
11
Laredo Petroleum, Inc.
Supplemental reconciliation of GAAP to non-GAAP financial measures
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 (Unaudited)
Adjusted Net Income is a non-GAAP financial measure we use to evaluate performance, prior to deferred income taxes, gains or losses on derivatives, cash settlements of matured derivatives, cash settlements on early terminated derivatives, premiums paid for 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 and bad debt expense and after applying adjusted income tax expense. We believe Adjusted Net Income helps investors in the oil and natural gas industry to measure and compare our performance to other oil and natural gas companies by excluding from the calculation, items that can vary significantly from company to company depending upon accounting methods, the book value of assets and other non-operational factors. At December 31, 2015 we changed the methodology for calculating Adjusted Net Income by applying a tax rate of 36% to all periods. As such, the prior periods’ Adjusted Net Income has been modified for comparability.
The following presents a reconciliation of Net loss (GAAP) to Adjusted Net Income (non-GAAP):
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
(in thousands, except for per share data, unaudited) | 2016 | 2015 | 2016 | 2015 | ||||||||||||
Net loss | $ | (71,432 | ) | $ | (397,034 | ) | $ | (251,803 | ) | $ | (397,506 | ) | ||||
Plus: | ||||||||||||||||
Deferred income tax benefit | — | (221,846 | ) | — | (218,203 | ) | ||||||||||
Mark-to-market on derivatives: | ||||||||||||||||
Loss on derivatives, net | 68,518 | 63,899 | 50,633 | 744 | ||||||||||||
Cash settlements received for matured derivatives, net | 47,382 | 46,596 | 113,319 | 109,737 | ||||||||||||
Cash settlements received for early terminations of derivatives, net | — | — | 80,000 | — | ||||||||||||
Premiums paid for derivatives | (2,413 | ) | (1,249 | ) | (84,263 | ) | (2,670 | ) | ||||||||
Impairment expense | 963 | 489,599 | 162,027 | 490,477 | ||||||||||||
Restructuring expenses | — | — | — | 6,042 | ||||||||||||
Loss on early redemption of debt | — | 31,537 | — | 31,537 | ||||||||||||
Buyout of minimum volume commitment | — | 3,014 | — | 3,014 | ||||||||||||
Loss on disposal of assets, net | 141 | 1,081 | 301 | 1,843 | ||||||||||||
Write-off of debt issuance costs | 842 | — | 842 | — | ||||||||||||
44,001 | 15,597 | 71,056 | 25,015 | |||||||||||||
Adjusted income tax expense(1) | (15,840 | ) | (5,615 | ) | (25,580 | ) | (9,005 | ) | ||||||||
Adjusted Net Income | $ | 28,161 | $ | 9,982 | $ | 45,476 | $ | 16,010 | ||||||||
Net loss per common share: | ||||||||||||||||
Basic | $ | (0.33 | ) | $ | (1.88 | ) | $ | (1.17 | ) | $ | (2.13 | ) | ||||
Diluted | $ | (0.33 | ) | $ | (1.88 | ) | $ | (1.17 | ) | $ | (2.13 | ) | ||||
Adjusted Net Income per common share: | ||||||||||||||||
Basic | $ | 0.13 | $ | 0.05 | $ | 0.21 | $ | 0.09 | ||||||||
Diluted | $ | 0.13 | $ | 0.05 | $ | 0.21 | $ | 0.09 | ||||||||
Weighted-average common shares outstanding: | ||||||||||||||||
Basic | 217,564 | 211,078 | 214,562 | 186,886 | ||||||||||||
Diluted | 217,564 | 211,078 | 214,562 | 186,886 | ||||||||||||
_______________________________________________________________________________
(1) | Adjusted income tax expense is calculated by applying a tax rate of 36% for each of the three and six months ended June 30, 2016 and 2015. |
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Adjusted EBITDA (Unaudited)
Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss plus adjustments for deferred 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 received for matured derivatives, cash settlements on early terminated derivatives, premiums paid for derivatives, 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 loss (GAAP) to Adjusted EBITDA (non-GAAP):
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
(in thousands, unaudited) | 2016 | 2015 | 2016 | 2015 | ||||||||||||
Net loss | $ | (71,432 | ) | $ | (397,034 | ) | $ | (251,803 | ) | $ | (397,506 | ) | ||||
Plus: | ||||||||||||||||
Deferred income tax benefit | — | (221,846 | ) | — | (218,203 | ) | ||||||||||
Depletion, depreciation and amortization | 34,177 | 72,112 | 75,655 | 144,054 | ||||||||||||
Impairment expense | 963 | 489,599 | 162,027 | 490,477 | ||||||||||||
Non-cash stock-based compensation, net of amounts capitalized | 6,073 | 6,268 | 9,911 | 11,056 | ||||||||||||
Restructuring expenses | — | — | — | 6,042 | ||||||||||||
Mark-to-market on derivatives: | ||||||||||||||||
Loss on derivatives, net | 68,518 | 63,899 | 50,633 | 744 | ||||||||||||
Cash settlements received for matured derivatives, net | 47,382 | 46,596 | 113,319 | 109,737 | ||||||||||||
Cash settlements received for early terminations of derivatives, net | — | — | 80,000 | — | ||||||||||||
Premiums paid for derivatives | (2,413 | ) | (1,249 | ) | (84,263 | ) | (2,670 | ) | ||||||||
Interest expense | 23,512 | 23,970 | 47,217 | 56,384 | ||||||||||||
Write-off of debt issuance costs | 842 | — | 842 | — | ||||||||||||
Loss on disposal of assets, net | 141 | 1,081 | 301 | 1,843 | ||||||||||||
Loss on early redemption of debt | — | 31,537 | — | 31,537 | ||||||||||||
Buyout of minimum volume commitment | — | 3,014 | — | 3,014 | ||||||||||||
Adjusted EBITDA | $ | 107,763 | $ | 117,947 | $ | 203,839 | $ | 236,509 | ||||||||
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# # #
Contacts:
Ron Hagood: (918) 858-5504 - RHagood@laredopetro.com
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