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 2017 Second-Quarter Financial and Operating Results
Raises Estimated 2017 Production Growth to 16% - 19%
TULSA, OK - August 7, 2017 - Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or "the Company") today announced its 2017 second-quarter results, reporting net income attributable to common stockholders of $61.1 million, or $0.25 per diluted share. Adjusted Net Income, a non-GAAP financial measure, for the second quarter of 2017 was $25.2 million, or $0.10 per adjusted diluted share. Adjusted EBITDA, a non-GAAP financial measure, for the second quarter of 2017 was $114.3 million. Please see supplemental financial information at the end of this news release for reconciliations of non-GAAP financial measures.
2017 Second-Quarter Highlights
• | Produced a Company record 58,632 barrels of oil equivalent ("BOE") per day, an increase of approximately 23% from the second quarter of 2016 and up 12% from first-quarter 2017 |
• | Grew oil production to a Company record 27,275 barrels of oil per day, an increase of approximately 16% from the first quarter of 2017 |
• | Increased anticipated production growth for full-year 2017 to a range of 16% - 19% from 2016 with no change to the 2017 capital budget of $530 million |
• | Reduced unit lease operating expenses ("LOE") approximately 15% to $3.77 per BOE from the second-quarter 2016 rate of $4.43 per BOE |
• | Recognized approximately $7.0 million in cash benefits from Laredo Midstream Services, LLC ("LMS") field infrastructure investments through reduced costs and increased revenue |
"In the second quarter, Laredo continued to create value for shareholders, adding more than 6,000 BOE per day of production from the rate in the first quarter of 2017," commented Randy A. Foutch, Chairman and Chief Executive Officer. "Our early decision to invest in acquiring high-quality data facilitated the development of proprietary workflows utilizing big data analytics that are powering our modeling efforts, shortening the time from concept to implementation. These efforts have increased well productivity, contributing to our increase in full-year 2017 production guidance. The productivity gains, coupled with the low operating costs facilitated by our investments in infrastructure and production corridors, are driving continued increases in capital efficiency that are expected to sustain our high-return drilling program."
Operational Update
In the second quarter of 2017, Laredo produced a Company record 58,632 BOE per day, completing 16 horizontal wells with an average completed lateral length of approximately 9,100 feet. Well productivity continues to improve as the Company refines its proprietary technology workflows and data analytics to improve landing point selection and individual well completion design. Driven by the improving performance, Laredo is increasing its expected 2017 year-over-year production growth rate to a range of 16% - 19%.
Second-quarter 2017 production was positively impacted by the nine-well JL McMaster-Bodine package, which was completed late in the first quarter of 2017 and utilized Laredo's customized managed flowback procedure. This package is currently outperforming Laredo's Upper/Middle Wolfcamp three-stream type curve by 45% and outperforming the Company's oil type curve by 41%.
Wells on managed flowback initially produce less than those not on managed flowback, but the production deficit is overcome in less than 90 days, on average. Longer-term production data is positive, with wells on Laredo's managed flowback generating first-year cumulative production approximately 5% - 10% higher than non-managed flowback wells. Laredo expects to continue utilizing managed flowback on all newly completed wells and will continue to monitor production data to assess the long-term impact on well performance.
Laredo completed the last six wells of the nine-well Sugg-Graham package in the second quarter of 2017. While early in its production history, this package is currently outperforming the Company's Upper/Middle Wolfcamp three-stream type curve by 24% and outperforming the oil type curve by 25%. Importantly, this package supports tighter spacing between landing points, in a chevroned pattern, between wells at the bottom of the Upper Wolfcamp and top of the Middle Wolfcamp. Tighter vertical spacing between the landing points is one step in the process of testing several landing points for co-development in both the Upper and Middle Wolfcamp formations, which, if successful, will significantly add to the Company's premium Upper and Middle Wolfcamp inventory.
The Company continues to apply in-house technology and data analytics to optimize completion design in relation to well spacing and the co-development of landing points within the Upper and Middle Wolfcamp formations. Individual completion design variables such as perf cluster spacing, clusters per stage, proppant density, sand size, precise landing point selection and well spacing configuration are being tested in all of the Company's well packages. During the second quarter of 2017, Laredo spudded a six-well package on its Western Glasscock production corridor that will test the potential co-development of multiple landing points within the Upper Wolfcamp formation. This test of three landing points in the Upper Wolfcamp will, if successful, increase premium Upper Wolfcamp inventory.
A component of Laredo's completion optimization testing is assessing the productivity and economics of higher proppant concentrations. Utilizing the Company's proprietary models to optimize proppant density and completion design led to internal predictions of production uplift of approximately 50% above type curve. Laredo quickly moved to implement the modeled designs in the field. Currently, the Company has completed 13 wells utilizing a combination of tests of tighter perf cluster spacing, precise landing point selection, sand size, well density, and
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managed flowback, in concert with increased proppant density of 2,400 pounds of proppant per lateral foot. This group of wells is currently outperforming Laredo's Upper and Middle Wolfcamp type curve by approximately 46%. The Company is very encouraged by these results and will continue to evaluate the economics of these variables coupled with higher proppant density.
In the third quarter of 2017, Laredo expects to complete 15 wells with an average lateral length of approximately 9,900 feet. As testing of 15 and 30-foot perf cluster spacing has improved well productivity, the Company expects to accelerate further testing in the second half of 2017. Tighter perf cluster spacing slightly increases cycle-time per well and Laredo now expects to complete approximately 60 - 65 horizontal wells in 2017.
Unit lease operating expenses decreased approximately 15% from the second quarter of 2016 to $3.77 per BOE. This is the fourth consecutive quarter in which unit LOE's were below $4.00 per BOE, driven by Laredo's previous field infrastructure investments.
Laredo Midstream Services Update
Field infrastructure owned by LMS provided significant financial and operating benefits in the second quarter of 2017. Total revenue and cost savings benefits were $7.0 million, driven by gathering on pipe 82% of Laredo's gross operated oil production and 73% of total produced water.
The Company's production corridors are key to operational efficiency and low operating costs. LOE savings in the second quarter of 2017 from reduced trucking of produced water, recycling of produced water and centralized compression facilities resulted in unit LOE reductions of $0.60 per BOE.
2017 Capital Program
During the second quarter of 2017, Laredo invested approximately $123 million in exploration and development activities. Other expenditures incurred during the quarter included approximately $3 million in bolt-on land acquisitions and lease extensions, approximately $6 million in infrastructure held by LMS and approximately $6 million in capitalized employee-related costs.
Through the first half of 2017, base well costs for 10,000-foot horizontal wells completed with 1,800 pounds of sand per lateral foot and 54-foot perf cluster spacing have been within Laredo's budgeted well cost expectations. The Company's $530 million capital budget is unchanged, although upward pressure in service costs, if sustained throughout the remainder of the year, could result in a 5% - 10% increase in the full-year 2017 capital budget.
Liquidity
At June 30, 2017, the Company had cash and cash equivalents of approximately $35 million and undrawn capacity under the senior secured credit facility of $895 million, resulting in total liquidity of approximately $930 million. At August 4, 2017, the Company had cash and equivalents of approximately $12 million and available capacity under the senior secured credit facility of $885 million, resulting in total available liquidity of approximately $900 million.
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Commodity Derivatives
Laredo maintains a disciplined hedging program to reduce the variability in its anticipated cash flow due to fluctuations in commodity prices. At June 30, 2017, the Company had hedges in place for the remaining two quarters of 2017 for 3,454,600 barrels of oil at a weighted-average floor price of $55.82 per barrel.
The Company also had hedges in place for the remaining two quarters of 2017 for 13,606,400 million British thermal units ("MMBtu") of natural gas at a weighted-average floor price of $2.75 per MMBtu. All natural gas hedges the Company has in place are priced at the WAHA hub. Additionally, Laredo had hedged 222,000 barrels of ethane at $11.24 per barrel and 187,500 barrels of propane at $22.26 per barrel.
At June 30, 2017, for 2018, the Company had hedged 6,704,875 barrels of oil at a weighted-average floor price of $46.34 per barrel. All hedged oil volumes in 2018 are structured to retain upside to an increase in oil price. Puts on approximately 2.6 million barrels of oil retain unlimited upside and collars on approximately 4.1 million barrels have a $60.00 per barrel ceiling.
The Company also had hedges in place for 2018 for 23,805,500 MMBtu of natural gas at a weighted-average floor price of $2.50 per MMBtu, priced at the WAHA hub.
Guidance
The Company is increasing its anticipated full-year 2017 production growth guidance to a range of 16% - 19% as compared to 2016. The table below reflects the Company’s production guidance for the third and fourth quarters of 2017 and cost guidance for the third quarter of 2017:
3Q-2017 | 4Q-2017 | |||
Production (MBOE/d) | 59 - 62 | 61 - 64 | ||
Product % of total production: | ||||
Crude oil | 45% - 47% | 45% - 47% | ||
Natural gas liquids | 26% - 27% | * | ||
Natural gas | 27% - 28% | * | ||
Price Realizations (pre-hedge): | ||||
Crude oil (% of WTI) | ~88% | * | ||
Natural gas liquids (% of WTI) | ~31% | * | ||
Natural gas (% of Henry Hub) | ~69% | * | ||
Operating Costs & Expenses: | ||||
Lease operating expenses ($/BOE) | $3.60 - $4.00 | * | ||
Midstream expenses ($/BOE) | $0.20 - $0.30 | * | ||
Production and ad valorem taxes (% of oil, NGL and natural gas revenue) | 6.25% | * | ||
General and administrative expenses: | ||||
Cash ($/BOE) | $2.50 - $3.00 | * | ||
Non-cash stock-based compensation ($/BOE) | $1.50 - $1.75 | * | ||
Depletion, depreciation and amortization ($/BOE) | $7.00 - $7.50 | * | ||
* Not provided
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Conference Call Details
On Tuesday, August 8, 2017, at 7:30 a.m. CT, Laredo will host a conference call to discuss its second-quarter 2017 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." Portfolio managers and analysts who would like to participate on the call should dial 877.930.8286, using conference code 56287044, approximately 10 minutes prior to the scheduled conference time. International participants should dial 253.336.8309, also using conference code 56287044. A telephonic replay will be available approximately two hours after the call on August 8, 2017 through Tuesday, August 15, 2017. Participants may access this replay by dialing 855.859.2056, using conference code 56287044.
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 gathering of oil and liquids-rich 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, contain forward-looking statements as defined under Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, that address activities that Laredo assumes, plans, expects, believes, intends, projects, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. The forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.
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, 2016, 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
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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 costs 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) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
(unaudited) | (unaudited) | |||||||||||||||
Revenues: | ||||||||||||||||
Oil, NGL and natural gas sales | $ | 141,837 | $ | 102,526 | $ | 280,573 | $ | 175,668 | ||||||||
Midstream service revenues | 2,703 | 1,632 | 5,702 | 3,433 | ||||||||||||
Sales of purchased oil | 42,461 | 42,615 | 89,732 | 74,229 | ||||||||||||
Total revenues | 187,001 | 146,773 | 376,007 | 253,330 | ||||||||||||
Costs and expenses: | ||||||||||||||||
Lease operating expenses | 20,104 | 19,225 | 37,096 | 39,743 | ||||||||||||
Production and ad valorem taxes | 8,472 | 7,982 | 17,253 | 14,417 | ||||||||||||
Midstream service expenses | 896 | 1,178 | 1,812 | 1,787 | ||||||||||||
Costs of purchased oil | 44,020 | 44,012 | 94,276 | 76,958 | ||||||||||||
General and administrative | 22,008 | 20,502 | 47,605 | 39,953 | ||||||||||||
Depletion, depreciation and amortization | 38,003 | 34,177 | 72,115 | 75,655 | ||||||||||||
Impairment expense | — | 963 | — | 162,027 | ||||||||||||
Other operating expenses | 1,437 | 860 | 2,463 | 1,704 | ||||||||||||
Total costs and expenses | 134,940 | 128,899 | 272,620 | 412,244 | ||||||||||||
Operating income (loss) | 52,061 | 17,874 | 103,387 | (158,914 | ) | |||||||||||
Non-operating income (expense): | ||||||||||||||||
Gain (loss) on derivatives, net | 28,897 | (68,518 | ) | 65,568 | (50,633 | ) | ||||||||||
Income from equity method investee | 2,471 | 3,696 | 5,539 | 5,994 | ||||||||||||
Interest expense | (23,173 | ) | (23,512 | ) | (45,893 | ) | (47,217 | ) | ||||||||
Other, net | 854 | (972 | ) | 785 | (1,033 | ) | ||||||||||
Non-operating income (expense), net | 9,049 | (89,306 | ) | 25,999 | (92,889 | ) | ||||||||||
Income (loss) before income taxes | 61,110 | (71,432 | ) | 129,386 | (251,803 | ) | ||||||||||
Income tax: | ||||||||||||||||
Deferred | — | — | — | — | ||||||||||||
Total income tax | — | — | — | — | ||||||||||||
Net income (loss) | $ | 61,110 | $ | (71,432 | ) | $ | 129,386 | $ | (251,803 | ) | ||||||
Net income (loss) per common share: | ||||||||||||||||
Basic | $ | 0.26 | $ | (0.33 | ) | $ | 0.54 | $ | (1.17 | ) | ||||||
Diluted | $ | 0.25 | $ | (0.33 | ) | $ | 0.53 | $ | (1.17 | ) | ||||||
Weighted-average common shares outstanding: | ||||||||||||||||
Basic | 239,231 | 217,564 | 238,870 | 214,562 | ||||||||||||
Diluted | 244,417 | 217,564 | 244,385 | 214,562 | ||||||||||||
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Laredo Petroleum, Inc.
Condensed consolidated balance sheets
(in thousands) | June 30, 2017 | December 31, 2016 | ||||||
(unaudited) | (unaudited) | |||||||
Assets: | ||||||||
Current assets | $ | 167,664 | $ | 154,777 | ||||
Property and equipment, net | 1,499,286 | 1,366,867 | ||||||
Other noncurrent assets | 274,304 | 260,702 | ||||||
Total assets | $ | 1,941,254 | $ | 1,782,346 | ||||
Liabilities and stockholders' equity: | ||||||||
Current liabilities | $ | 172,083 | $ | 187,945 | ||||
Long-term debt, net | 1,390,277 | 1,353,909 | ||||||
Other noncurrent liabilities | 54,491 | 59,919 | ||||||
Stockholders' equity | 324,403 | 180,573 | ||||||
Total liabilities and stockholders' equity | $ | 1,941,254 | $ | 1,782,346 | ||||
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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) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
(unaudited) | (unaudited) | |||||||||||||||
Cash flows from operating activities: | ||||||||||||||||
Net income (loss) | $ | 61,110 | $ | (71,432 | ) | $ | 129,386 | $ | (251,803 | ) | ||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||||
Depletion, depreciation and amortization | 38,003 | 34,177 | 72,115 | 75,655 | ||||||||||||
Impairment expense | — | 963 | — | 162,027 | ||||||||||||
Non-cash stock-based compensation, net of amounts capitalized | 8,687 | 6,073 | 17,911 | 9,911 | ||||||||||||
Mark-to-market on derivatives: | ||||||||||||||||
(Gain) loss on derivatives, net | (28,897 | ) | 68,518 | (65,568 | ) | 50,633 | ||||||||||
Cash settlements received for matured derivatives, net | 13,705 | 47,382 | 21,156 | 113,319 | ||||||||||||
Cash settlements received for early terminations of derivatives, net | 4,234 | — | 4,234 | 80,000 | ||||||||||||
Cash premiums paid for derivatives | (9,987 | ) | (2,413 | ) | (12,094 | ) | (84,263 | ) | ||||||||
Other, net | (1,158 | ) | (723 | ) | (1,920 | ) | (7,217 | ) | ||||||||
Cash flows from operations before changes in working capital and other noncurrent liabilities | 85,697 | 82,545 | 165,220 | 148,262 | ||||||||||||
Increase (decrease) in working capital | 7,541 | (304 | ) | (8,154 | ) | (9,435 | ) | |||||||||
Decrease in other noncurrent liabilities | (121 | ) | (127 | ) | (165 | ) | (196 | ) | ||||||||
Net cash provided by operating activities | 93,117 | 82,114 | 156,901 | 138,631 | ||||||||||||
Cash flows from investing activities: | ||||||||||||||||
Capital expenditures: | ||||||||||||||||
Oil and natural gas properties | (121,677 | ) | (91,887 | ) | (232,219 | ) | (197,042 | ) | ||||||||
Midstream service assets | (4,386 | ) | (1,488 | ) | (6,117 | ) | (3,425 | ) | ||||||||
Other fixed assets | (1,480 | ) | (202 | ) | (2,683 | ) | (832 | ) | ||||||||
Investment in equity method investee | — | (16,021 | ) | — | (42,681 | ) | ||||||||||
Proceeds from dispositions of capital assets, net of selling costs | 3,926 | 132 | 63,441 | 350 | ||||||||||||
Net cash used in investing activities | (123,617 | ) | (109,466 | ) | (177,578 | ) | (243,630 | ) | ||||||||
Cash flows from financing activities: | ||||||||||||||||
Borrowings on Senior Secured Credit Facility | 40,000 | 35,000 | 90,000 | 120,000 | ||||||||||||
Payments on Senior Secured Credit Facility | — | (119,682 | ) | (55,000 | ) | (144,682 | ) | |||||||||
Proceeds from issuance of common stock, net of offering costs | — | 119,310 | — | 119,310 | ||||||||||||
Other, net | (4,828 | ) | (62 | ) | (11,971 | ) | (1,474 | ) | ||||||||
Net cash provided by financing activities | 35,172 | 34,566 | 23,029 | 93,154 | ||||||||||||
Net increase (decrease) in cash and cash equivalents | 4,672 | 7,214 | 2,352 | (11,845 | ) | |||||||||||
Cash and cash equivalents, beginning of period | 30,352 | 12,095 | 32,672 | 31,154 | ||||||||||||
Cash and cash equivalents, end of period | $ | 35,024 | $ | 19,309 | $ | 35,024 | $ | 19,309 | ||||||||
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Laredo Petroleum, Inc.
Selected operating data
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||||||
(unaudited) | (unaudited) | |||||||||||||||
Sales volumes: | ||||||||||||||||
Oil (MBbl) | 2,482 | 2,012 | 4,602 | 4,018 | ||||||||||||
NGL (MBbl) | 1,433 | 1,153 | 2,696 | 2,219 | ||||||||||||
Natural gas (MMcf) | 8,524 | 7,038 | 16,524 | 13,834 | ||||||||||||
Oil equivalents (MBOE)(1)(2) | 5,336 | 4,338 | 10,052 | 8,542 | ||||||||||||
Average daily sales volumes (BOE/D)(1) | 58,632 | 47,667 | 55,536 | 46,935 | ||||||||||||
% Oil | 47 | % | 46 | % | 46 | % | 47 | % | ||||||||
Average sales prices(1): | ||||||||||||||||
Oil, realized ($/Bbl)(3) | $ | 42.00 | $ | 39.37 | $ | 44.26 | $ | 33.45 | ||||||||
NGL, realized ($/Bbl)(3) | $ | 13.82 | $ | 12.24 | $ | 15.07 | $ | 10.44 | ||||||||
Natural gas, realized ($/Mcf)(3) | $ | 2.09 | $ | 1.31 | $ | 2.19 | $ | 1.31 | ||||||||
Average price, realized ($/BOE)(3) | $ | 26.58 | $ | 23.64 | $ | 27.91 | $ | 20.56 | ||||||||
Oil, hedged ($/Bbl)(4) | $ | 46.95 | $ | 58.86 | $ | 48.22 | $ | 57.85 | ||||||||
NGL, hedged ($/Bbl)(4) | $ | 13.61 | $ | 12.24 | $ | 14.75 | $ | 10.44 | ||||||||
Natural gas, hedged ($/Mcf)(4) | $ | 2.12 | $ | 2.13 | $ | 2.21 | $ | 2.10 | ||||||||
Average price, hedged ($/BOE)(4) | $ | 28.88 | $ | 34.00 | $ | 29.66 | $ | 33.33 | ||||||||
Average costs per BOE sold(1): | ||||||||||||||||
Lease operating expenses | $ | 3.77 | $ | 4.43 | $ | 3.69 | $ | 4.65 | ||||||||
Production and ad valorem taxes | 1.59 | 1.84 | 1.72 | 1.69 | ||||||||||||
Midstream service expenses | 0.17 | 0.27 | 0.18 | 0.21 | ||||||||||||
General and administrative: | ||||||||||||||||
Cash | 2.50 | 3.33 | 2.95 | 3.52 | ||||||||||||
Non-cash stock-based compensation, net of amounts capitalized | 1.63 | 1.40 | 1.78 | 1.16 | ||||||||||||
Depletion, depreciation and amortization | 7.12 | 7.88 | 7.17 | 8.86 | ||||||||||||
Total | $ | 16.78 | $ | 19.15 | $ | 17.49 | $ | 20.09 | ||||||||
_______________________________________________________________________________
(1) | The numbers presented are based on actual results and are not calculated using the rounded numbers presented in the table above. |
(2) | BOE is calculated using a conversion rate of six Mcf per one Bbl. |
(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. |
(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. |
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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) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
(unaudited) | (unaudited) | |||||||||||||||
Property acquisition costs: | ||||||||||||||||
Evaluated | $ | — | $ | — | $ | — | $ | — | ||||||||
Unevaluated | — | — | — | — | ||||||||||||
Exploration costs | 5,658 | 19,769 | 21,201 | 27,032 | ||||||||||||
Development costs(1) | 125,738 | 70,806 | 236,896 | 152,692 | ||||||||||||
Total costs incurred | $ | 131,396 | $ | 90,575 | $ | 258,097 | $ | 179,724 | ||||||||
(1) | Development costs include $0.1 million in asset retirement obligations for each of the three months ended June 30, 2017 and 2016, and $0.2 million for each of the six months ended June 30, 2017 and 2016. |
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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, mark-to-market on derivatives, cash premiums paid for derivatives, impairment expense, gains or losses on disposal of assets, write-off of debt issuance costs and other non-recurring income and expenses 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.
Including a higher weighted-average shares outstanding in the denominator of a diluted per-share computation results in an anti-dilutive per share amount when an entity is in a loss position. As such, for the three and six months ended June 30, 2016, our net loss (GAAP) per common share calculation utilizes the same denominator for both basic and diluted net loss per common share. However, our calculation of Adjusted Net Income (non-GAAP) results in income for both periods presented. Therefore, we believe it appropriate and more conservative to calculate an Adjusted diluted weighted-average common shares outstanding utilizing our fully dilutive weighted-average common shares. As such, for each of the three and six months ended June 30, 2017 and 2016, we present a line item that calculates Adjusted Net Income per Adjusted diluted common share. This line item was not presented in the prior periods.
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The following presents a reconciliation of net income (loss) (GAAP) to Adjusted Net Income (non-GAAP):
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
(in thousands, except per share data, unaudited) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Net income (loss) | $ | 61,110 | $ | (71,432 | ) | $ | 129,386 | $ | (251,803 | ) | ||||||
Plus: | ||||||||||||||||
Mark-to-market on derivatives: | ||||||||||||||||
(Gain) loss on derivatives, net | (28,897 | ) | 68,518 | (65,568 | ) | 50,633 | ||||||||||
Cash settlements received for matured derivatives, net | 13,705 | 47,382 | 21,156 | 113,319 | ||||||||||||
Cash settlements received for early terminations of derivatives, net | 4,234 | — | 4,234 | 80,000 | ||||||||||||
Cash premiums paid for derivatives | (9,987 | ) | (2,413 | ) | (12,094 | ) | (84,263 | ) | ||||||||
Impairment expense | — | 963 | — | 162,027 | ||||||||||||
(Gain) loss on disposal of assets, net | (805 | ) | 141 | (591 | ) | 301 | ||||||||||
Write-off of debt issuance costs | — | 842 | — | 842 | ||||||||||||
Adjusted net income before adjusted income tax expense | 39,360 | 44,001 | 76,523 | 71,056 | ||||||||||||
Adjusted income tax expense | (14,170 | ) | (15,840 | ) | (27,548 | ) | (25,580 | ) | ||||||||
Adjusted Net Income | $ | 25,190 | $ | 28,161 | $ | 48,975 | $ | 45,476 | ||||||||
Net income (loss) per common share: | ||||||||||||||||
Basic | $ | 0.26 | $ | (0.33 | ) | $ | 0.54 | $ | (1.17 | ) | ||||||
Diluted | $ | 0.25 | $ | (0.33 | ) | $ | 0.53 | $ | (1.17 | ) | ||||||
Adjusted Net Income per common share: | ||||||||||||||||
Basic | $ | 0.11 | $ | 0.13 | $ | 0.21 | $ | 0.21 | ||||||||
Adjusted diluted | $ | 0.10 | $ | 0.13 | $ | 0.20 | $ | 0.21 | ||||||||
Weighted-average common shares outstanding: | ||||||||||||||||
Basic | 239,231 | 217,564 | 238,870 | 214,562 | ||||||||||||
Diluted | 244,417 | 217,564 | 244,385 | 214,562 | ||||||||||||
Adjusted diluted | 244,417 | 222,032 | 244,385 | 218,122 | ||||||||||||
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, impairment expense, non-cash stock-based compensation, net of amounts capitalized, accretion expense, mark-to-market on derivatives, cash premiums paid for derivatives, interest expense, write-off of debt issuance costs, gains or losses on disposal of assets, income or loss from equity method investee, proportionate Adjusted EBITDA of equity method investee and other non-recurring income and expenses. 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.
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During the year ended December 31, 2016, we changed the methodology for calculating Adjusted EBITDA by including adjustments for both accretion of asset retirement obligations and our proportionate share of our equity method investee's Adjusted EBITDA. Accordingly, the prior period's Adjusted EBITDA has been modified for comparability.
The following presents a reconciliation of net income (loss) (GAAP) to Adjusted EBITDA (non-GAAP):
_______________________________________________________________________________
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
(in thousands, unaudited) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Net income (loss) | $ | 61,110 | $ | (71,432 | ) | $ | 129,386 | $ | (251,803 | ) | ||||||
Plus: | ||||||||||||||||
Depletion, depreciation and amortization | 38,003 | 34,177 | 72,115 | 75,655 | ||||||||||||
Impairment expense | — | 963 | — | 162,027 | ||||||||||||
Non-cash stock-based compensation, net of amounts capitalized | 8,687 | 6,073 | 17,911 | 9,911 | ||||||||||||
Accretion expense | 943 | 860 | 1,871 | 1,704 | ||||||||||||
Mark-to-market on derivatives: | ||||||||||||||||
(Gain) loss on derivatives, net | (28,897 | ) | 68,518 | (65,568 | ) | 50,633 | ||||||||||
Cash settlements received for matured derivatives, net | 13,705 | 47,382 | 21,156 | 113,319 | ||||||||||||
Cash settlements received for early terminations of derivatives, net | 4,234 | — | 4,234 | 80,000 | ||||||||||||
Cash premiums paid for derivatives | (9,987 | ) | (2,413 | ) | (12,094 | ) | (84,263 | ) | ||||||||
Interest expense | 23,173 | 23,512 | 45,893 | 47,217 | ||||||||||||
Write-off of debt issuance costs | — | 842 | — | 842 | ||||||||||||
(Gain) loss on disposal of assets, net | (805 | ) | 141 | (591 | ) | 301 | ||||||||||
Income from equity method investee | (2,471 | ) | (3,696 | ) | (5,539 | ) | (5,994 | ) | ||||||||
Proportionate Adjusted EBITDA of equity method investee(1) | 6,601 | 5,103 | 12,966 | 8,787 | ||||||||||||
Adjusted EBITDA | $ | 114,296 | $ | 110,030 | $ | 221,740 | $ | 208,336 | ||||||||
(1) | Proportionate Adjusted EBITDA of Medallion, our equity method investee, is calculated as follows: |
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
(in thousands, unaudited) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Income from equity method investee | $ | 2,471 | $ | 3,696 | $ | 5,539 | $ | 5,994 | ||||||||
Adjusted for proportionate share of: | ||||||||||||||||
Depreciation and amortization | 4,130 | 1,407 | 7,427 | 2,793 | ||||||||||||
Proportionate Adjusted EBITDA of equity method investee | $ | 6,601 | $ | 5,103 | $ | 12,966 | $ | 8,787 | ||||||||
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Contacts:
Ron Hagood: (918) 858-5504 - RHagood@laredopetro.com
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