TULSA, OK, Nov. 01, 2017 (GLOBE NEWSWIRE) -- Laredo Petroleum, Inc. (NYSE:LPI) ("Laredo" or "the Company") today announced its 2017 third-quarter results, reporting net income attributable to common stockholders of $11.0 million, or $0.05 per diluted share. Adjusted Net Income, a non-GAAP financial measure, for the third quarter of 2017 was $33.1 million, or $0.13 per adjusted diluted share. Adjusted EBITDA, a non-GAAP financial measure, for the third quarter of 2017 was $130.9 million. Please see supplemental financial information at the end of this news release for reconciliations of non-GAAP financial measures.
2017 Third-Quarter Highlights
- Produced a Company record 60,011 barrels of oil equivalent ("BOE") per day, an increase of approximately 17% from the third quarter of 2016
- Reduced unit lease operating expenses ("LOE") to a Company record $3.55 per BOE, a decrease of approximately 8% from the third quarter of 2016 and down approximately 6% from second-quarter 2017
- Increased Adjusted EBITDA to $130.9 million, up 11% from the third quarter of 2016 and an increase of approximately 15% from second-quarter 2017
- Recognized approximately $7.6 million in cash benefits from Laredo Midstream Services, LLC ("LMS") field infrastructure investments through reduced costs and increased revenue
"Throughout the third quarter, our operations team precisely executed a challenging testing program for both drilling and completions activities while managing through a broad list of issues derived from one of the worst hurricanes to impact the energy industry in decades," said Randy A. Foutch, Chairman and Chief Executive Officer. "As a result, we achieved record production volumes and drove operating costs on a unit basis to the lowest level in Company history while meaningfully advancing our understanding of ultimate development opportunities to maximize the total net asset value of the Company."
"Laredo has always taken a balanced approach to value creation in every aspect of its business. Preserving meaningful operational and financial flexibility in an ever changing environment ensures today’s investments are truly value-enhancing. Consistent with the infrastructure investments that are key to efficient operations and reduced operating costs, the recent divestiture of our Medallion pipeline interest returned three times our investment in four years while preserving the marketing and cost-saving benefits. In a similar vein, accelerated field testing that applies knowledge derived from our multivariate earth model is expected to further enhance our field development plan. We are very encouraged with many of our initial test results and are now building the production history necessary to fully understand and evaluate the economic impacts that drive net asset values. The efficiencies driven by these investments, coupled with a disciplined capital program, are expected to result in a double-digit oil production growth rate over the next two years, while operating within cash flow by the end of 2019 and enhancing the Company’s return on average capital employed."
Operational Update
The Company's solid performance from base production coupled with initial volumes from 15 new horizontal wells that came online during the third quarter of 2017 resulted in Company record production of 60,011 BOE per day. The 15 new wells during the quarter had an average completed lateral length of approximately 9,900 feet, including three with drilled lateral lengths longer than 15,000 feet. The longer laterals utilized increased water for completion and therefore require a longer flowback period and have not yet achieved peak rates. As a result, both oil and total production came within the Company's quarterly guidance range, although at the lower end.
The three wells drilled with lateral lengths greater than 15,000 feet likely represent the longest laterals drilled to date throughout the Midland Basin. Laredo drilled and completed each of these ultra-long wells without any impact to operations. The wells were part of a five-well package drilled on the Company's Reagan North production corridor. The production corridor was instrumental in facilitating the completions and increasing the expected returns of the project. The five-well package required the delivery of approximately 3.8 million barrels of water to the location, of which 27% was supplied by LMS' recycled water facilities.
Both the operational efficiency and production results of longer laterals confirm Laredo's expectations that incorporating 15,000-foot laterals into the Company's development plan can enhance capital efficiency. The success of these wells provides significant confidence for drilling additional ultra-long lateral locations that exist within Laredo's contiguous acreage block. Laredo currently has approximately 500 land-ready locations in its high-return Upper and Middle Wolfcamp formations that can be developed with 15,000-foot laterals.
Laredo decreased unit LOE to a Company record $3.55 per BOE, down approximately 6% from the previous quarter. The Company has recorded five consecutive quarters of unit LOE below $4.00 per BOE, driven primarily by Laredo's investments in field infrastructure through its wholly-owned subsidiary, LMS. As the number of horizontal wells benefiting from production corridor services has grown from 195 at the beginning of 2017 to 240 through third-quarter 2017, infrastructure driven LOE savings have increased 28% from the first quarter of 2017.
The Company remains focused on testing various vertical, horizontal and tangential spacing combinations within specific well packages to maximize efficiencies and resource development. These tests are focused on increasing the inventory of premium locations in the Upper and Middle Wolfcamp formations through the co-development of the six to eight combined landing points that Laredo has identified in these formations. Should these tests add locations, recovery factors and capital efficiencies are expected to benefit, increasing value per section.
The nine-well Sugg-Graham package, completed in the first and second quarters of 2017, continues to perform well, outperforming the Company's Upper/Middle Wolfcamp three-stream type curve by 30% and the oil type curve by 18%. The results support tighter spacing between landing points, in a chevroned pattern, between the Upper and Middle Wolfcamp formations and the potential for additional premium locations in those formations. Effective horizontal spacing of approximately 440 feet and vertical spacing of approximately 200 feet between some wells in the package could result in a 50% increase in locations in the Upper and Middle Wolfcamp formations around the Company's production corridors. Laredo's six-well package on the Company's Western Glasscock production corridor, expected to be completed during the fourth quarter of 2017, will further test tighter effective spacing in the Upper Wolfcamp formation.
A key component of increasing well density is enhancing fracture complexity and concentration around the wellbore. Laredo has tested various completion designs to accomplish this and, based on production results and microseismic data, is completing a significant number of wells with 30-foot cluster intervals. The Company expects to continue to test additional completion designs related to perforation cluster spacing, including 15-foot cluster spacing and varying the number of clusters per stage.
Through the third quarter of 2017, Laredo has utilized proprietary analytics and modeling to optimize completions on 96 horizontal wells. On average, these wells are outperforming the Company's type curves by 36%. Importantly, this outperformance has remained consistent as Laredo has expanded testing to additional landing points within the Upper and Middle Wolfcamp formations. Tests also incorporate increased proppant density of 2,400 pounds per lateral foot. This group of 22 wells using 2,400 pounds of proppant per foot is currently outperforming Laredo's type curves by 42%, including the 13 wells with the longest production history that are outperforming the Company's type curves by 49%.
Laredo continues to evaluate the economics of multiple spacing and completion tests and is incorporating the analysis into the Company's overall development plan. In 2017, Laredo anticipates a total of 11 of the Company's multi-well packages will test spacing concepts, co-development of landing points and additional landing points. Completions tests have been integrated into these packages to determine the impact of proppant density, cluster interval spacing, stage length and proprietary concepts in spacing design. The primary goal is to enhance long-term value through efficient resource recovery while retaining the ability to appropriately adjust well package elements of spacing and completion design as service costs and commodity prices fluctuate.
In the third quarter of 2017, Laredo continued to experience higher well costs as service cost increases seen at the end of second-quarter 2017 continued throughout the third quarter. Laredo is currently budgeting $7.7 million for an Upper/Middle Wolfcamp 10,000-foot horizontal well, completed with 1,800 pounds of sand per lateral foot and utilizing 30-foot perforation cluster spacing. The Company is actively pursuing initiatives to reduce well costs, including self-sourcing local sand supplies and increasing the number of clusters per stage to reduce costs associated with tighter cluster spacing.
In the fourth quarter of 2017, Laredo expects to complete 20 wells, 12 of which are expected to meaningfully impact fourth quarter production, with an average lateral length of approximately 9,400 feet and an average working interest of 99%. The Company is currently operating four horizontal development rigs. During the third quarter of 2017, Laredo employed a fifth rig to drill a core test to further its data analysis efforts and has released the rig subsequent to the end of the quarter.
The Company is focused on driving efficiencies in its drilling and completion operations through the development of multi-well packages on its production corridors. It is expected that these efficiencies will result in a continued increase in work-in-progress wells from the third-quarter 2017 level of 21 wells. The Company's goal is to manage the number of work-in-progress wells, focus on return on capital and better align capital spending with cash flow.
Laredo Midstream Services Update
LMS-owned field infrastructure provided combined benefits from increased revenue and cost savings of $7.6 million in the third quarter of 2017. Without the benefits generated by LMS' water infrastructure and centralized gas lift infrastructure, unit LOE would have increased by an estimated $0.51 per BOE in third-quarter 2017.
Efficient use of water resources is a priority for the Company, and through LMS, Laredo has invested in water infrastructure since 2013. The Company gathered 72% of its produced water by pipe and recycled 30% of its produced water in the third quarter of 2017. Additionally, LMS supplied 46% of the water needed for Laredo's third-quarter 2017 completions with recycled water or fresh water from LMS-owned water wells. In total, LMS' water infrastructure assets delivered approximately $4.5 million in operating and capital cost savings in the third quarter of 2017.
LMS' oil gathering assets generated approximately $2.8 million in benefits to the Company through a combination of increased realized prices and operating income from third-party shippers. Approximately 81% of Laredo's gross operated production was gathered on pipe and 81% was transported on the Medallion-Midland Basin pipeline system.
The Company expects that the sale of the Company's interest in Medallion, announced subsequent to the end of the third quarter of 2017, will have no impact on Laredo's future operating cost structure or realized oil pricing.
2017 Capital Program
During the third quarter of 2017, Laredo invested approximately $156 million in exploration and development activities, including approximately $46 million in wells expected to be completed in the fourth quarter of 2017. Other expenditures incurred during the quarter included approximately $4 million in bolt-on land acquisitions and lease extensions, approximately $4 million in infrastructure held by LMS and approximately $7 million in capitalized employee-related costs.
Through the third quarter of 2017, the Company has incurred total expenditures of approximately $442 million, exclusive of investments in the Medallion-Midland Basin pipeline system, which Laredo divested subsequent to the end of third-quarter 2017.
The Company has increased its 2017 capital budget to $630 million from the previously anticipated $530 million. The new budget reflects service cost inflation, additional completion optimization testing and data collection. Approximately $90 million of expected costs incurred in 2017 are associated with wells drilled in multi-well packages that will benefit production in 2018.
Liquidity
At September 30, 2017, the Company had cash and cash equivalents of approximately $21 million and undrawn capacity under the senior secured credit facility of $845 million, resulting in total liquidity of approximately $866 million.
On October 20, 2017, in connection with the semi-annual redetermination of the Company's senior secured credit facility, lenders reaffirmed the Company's borrowing base at $1 billion.
At October 31, 2017, subsequent to the closing of the sale of LMS' interest in the Medallion-Midland Basin pipeline system, the Company had cash and equivalents of approximately $735 million and available capacity under the senior secured credit facility of $1 billion, resulting in total available liquidity of approximately $1.735 billion. Approximately $521 million of this amount will be utilized to satisfy the redemption of the Company's 7.375% senior notes, which is expected to be completed on November 29, 2017.
Commodity Derivatives
Laredo maintains a disciplined hedging program to reduce the variability in its anticipated cash flow due to fluctuations in commodity prices. At September 30, 2017, the Company had hedges in place for the remainder of 2017 for 1,727,300 barrels of oil at a weighted-average floor price of $55.82 per barrel and for 6,803,200 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 111,000 barrels of ethane at $11.24 per barrel and 93,750 barrels of propane at $22.26 per barrel.
At September 30, 2017, for 2018, the Company had hedged 9,515,375 barrels of oil at a weighted-average floor price of $47.42 per barrel. All of the Company's 2018 oil hedges enable Laredo to benefit from an increase in the price of oil from current levels with 4,088,000 barrels structured as collars with a weighted-average ceiling price of $60.00 per barrel and 5,427,375 barrels hedged with puts and thus do not have a ceiling. The Company has also hedged 23,805,500 MMBtu of natural gas for 2018 at a weighted-average floor price of $2.50 per MMBtu, priced at the WAHA hub. Additionally, Laredo has basis swaps for 2018 for 3,650,000 barrels of oil to hedge the Midland-West Texas Intermediate ("WTI") basis differential at WTI less $0.56 per barrel.
At September 30, 2017, for 2019, the Company had hedged 730,000 barrels of oil with puts having a weighted-average floor price of $50.00 per barrel.
Guidance
The Company is reiterating its anticipated full-year 2017 production growth guidance range of 16% - 19% as compared to 2016. The table below reflects the Company’s guidance for the fourth quarter of 2017.
| 4Q-2017 | ||
| Production (MBOE/d) | 61 - 64 | |
| Product % of total production: | ||
| Crude oil | 43% - 45% | |
| Natural gas liquids | 27% - 29% | |
| Natural gas | 27% - 29% | |
| Price Realizations (pre-hedge): | ||
| Crude oil (% of WTI) | ~94% | |
| Natural gas liquids (% of WTI) | ~39% | |
| Natural gas (% of Henry Hub) | ~67% | |
| Operating Costs & Expenses: | ||
| Lease operating expenses ($/BOE) | $3.50 - $4.00 | |
| Midstream expenses ($/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) | $7.25 - $7.75 | |
Conference Call Details
On Thursday, November 2, 2017, at 7:30 a.m. CT, Laredo will host a conference call to discuss its third-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 2277457, approximately 10 minutes prior to the scheduled conference time. International participants should dial 253.336.8309, also using conference code 2277457. A telephonic replay will be available approximately two hours after the call on November 2, 2017 through Thursday, November 9, 2017. Participants may access this replay by dialing 855.859.2056, using conference code 2277457.
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, the increase in service costs, the impact of the Medallion sale, hedging activities, possible impacts of pending or potential litigation 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 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.
| Laredo Petroleum, Inc. | ||||||||||||||||
| Condensed consolidated statements of operations | ||||||||||||||||
| Three months ended September 30, | Nine months ended September 30, | |||||||||||||||
| (in thousands, except per share data) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||
| Revenues: | ||||||||||||||||
| Oil, NGL and natural gas sales | $ | 157,558 | $ | 114,805 | $ | 438,131 | $ | 290,473 | ||||||||
| Midstream service revenues | 2,446 | 2,488 | 8,148 | 5,921 | ||||||||||||
| Sales of purchased oil | 45,814 | 42,441 | 135,546 | 116,670 | ||||||||||||
| Total revenues | 205,818 | 159,734 | 581,825 | 413,064 | ||||||||||||
| Costs and expenses: | ||||||||||||||||
| Lease operating expenses | 19,594 | 18,177 | 56,690 | 57,920 | ||||||||||||
| Production and ad valorem taxes | 9,558 | 7,066 | 26,811 | 21,483 | ||||||||||||
| Midstream service expenses | 1,174 | 1,039 | 2,986 | 2,826 | ||||||||||||
| Costs of purchased oil | 47,385 | 44,232 | 141,661 | 121,190 | ||||||||||||
| General and administrative | 25,000 | 26,105 | 72,605 | 66,058 | ||||||||||||
| Depletion, depreciation and amortization | 41,212 | 35,158 | 113,327 | 110,813 | ||||||||||||
| Impairment expense | — | — | — | 162,027 | ||||||||||||
| Other operating expenses | 1,443 | 2,465 | 3,906 | 4,169 | ||||||||||||
| Total costs and expenses | 145,366 | 134,242 | 417,986 | 546,486 | ||||||||||||
| Operating income (loss) | 60,452 | 25,492 | 163,839 | (133,422 | ) | |||||||||||
| Non-operating income (expense): | ||||||||||||||||
| Gain (loss) on derivatives, net | (27,441 | ) | 6,850 | 38,127 | (43,783 | ) | ||||||||||
| Income from equity method investee** | 2,371 | 265 | 7,910 | 6,259 | ||||||||||||
| Interest expense | (23,697 | ) | (23,077 | ) | (69,590 | ) | (70,294 | ) | ||||||||
| Other, net | (658 | ) | (45 | ) | 127 | (1,078 | ) | |||||||||
| Non-operating expense, net | (49,425 | ) | (16,007 | ) | (23,426 | ) | (108,896 | ) | ||||||||
| Income (loss) before income taxes | 11,027 | 9,485 | 140,413 | (242,318 | ) | |||||||||||
| Income tax: | ||||||||||||||||
| Deferred | — | — | — | — | ||||||||||||
| Total income tax | — | — | — | — | ||||||||||||
| Net income (loss) | $ | 11,027 | $ | 9,485 | $ | 140,413 | $ | (242,318 | ) | |||||||
| Net income (loss) per common share: | ||||||||||||||||
| Basic | $ | 0.05 | $ | 0.04 | $ | 0.59 | $ | (1.09 | ) | |||||||
| Diluted | $ | 0.05 | $ | 0.04 | $ | 0.57 | $ | (1.09 | ) | |||||||
| Weighted-average common shares outstanding: | ||||||||||||||||
| Basic | 239,306 | 234,639 | 239,017 | 221,303 | ||||||||||||
| Diluted | 244,887 | 238,108 | 244,693 | 221,303 | ||||||||||||
| Laredo Petroleum, Inc. | ||||||||
| Condensed consolidated balance sheets | ||||||||
| (in thousands) | September 30, 2017 | December 31, 2016 | ||||||
| (unaudited) | (unaudited) | |||||||
| Assets: | ||||||||
| Current assets | $ | 142,465 | $ | 154,777 | ||||
| Property and equipment, net | 1,631,319 | 1,366,867 | ||||||
| Other noncurrent assets** | 292,542 | 260,702 | ||||||
| Total assets | $ | 2,066,326 | $ | 1,782,346 | ||||
| Liabilities and stockholders' equity: | ||||||||
| Current liabilities | $ | 223,260 | $ | 187,945 | ||||
| Long-term debt, net | 1,440,968 | 1,353,909 | ||||||
| Other noncurrent liabilities | 55,873 | 59,919 | ||||||
| Stockholders' equity | 346,225 | 180,573 | ||||||
| Total liabilities and stockholders' equity | $ | 2,066,326 | $ | 1,782,346 | ||||
| Laredo Petroleum, Inc. | ||||||||||||||||
| Condensed consolidated statements of cash flows | ||||||||||||||||
| Three months ended September 30, | Nine months ended September 30, | |||||||||||||||
| (in thousands) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||
| Cash flows from operating activities: | ||||||||||||||||
| Net income (loss) | $ | 11,027 | $ | 9,485 | $ | 140,413 | $ | (242,318 | ) | |||||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||||
| Depletion, depreciation and amortization | 41,212 | 35,158 | 113,327 | 110,813 | ||||||||||||
| Impairment expense | — | — | — | 162,027 | ||||||||||||
| Non-cash stock-based compensation, net of amounts capitalized | 8,966 | 9,651 | 26,877 | 19,562 | ||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||||
| (Gain) loss on derivatives, net | 27,441 | (6,850 | ) | (38,127 | ) | 43,783 | ||||||||||
| Cash settlements received for matured derivatives, net | 13,635 | 44,307 | 34,791 | 157,626 | ||||||||||||
| Cash settlements received for early terminations of derivatives, net | — | — | 4,234 | 80,000 | ||||||||||||
| Cash premiums paid for derivatives | (1,448 | ) | (2,709 | ) | (13,542 | ) | (86,972 | ) | ||||||||
| Other, net | 786 | 1,794 | (1,134 | ) | (5,423 | ) | ||||||||||
| Cash flows from operations before changes in working capital and other noncurrent liabilities | 101,619 | 90,836 | 266,839 | 239,098 | ||||||||||||
| Increase in working capital | 13,656 | 16,088 | 5,502 | 6,653 | ||||||||||||
| Decrease in other noncurrent liabilities | (125 | ) | (101 | ) | (290 | ) | (297 | ) | ||||||||
| Net cash provided by operating activities | 115,150 | 106,823 | 272,051 | 245,454 | ||||||||||||
| Cash flows from investing activities: | ||||||||||||||||
| Capital expenditures: | ||||||||||||||||
| Acquisitions of oil and natural gas properties | — | (115,600 | ) | — | (115,600 | ) | ||||||||||
| Oil and natural gas properties | (148,946 | ) | (79,693 | ) | (381,165 | ) | (276,735 | ) | ||||||||
| Midstream service assets | (5,563 | ) | (806 | ) | (11,680 | ) | (4,231 | ) | ||||||||
| Other fixed assets | (921 | ) | (150 | ) | (3,604 | ) | (982 | ) | ||||||||
| Investment in equity method investee** | (24,572 | ) | (16,031 | ) | (24,572 | ) | (58,712 | ) | ||||||||
| Proceeds from dispositions of capital assets, net of selling costs | 687 | 15 | 64,128 | 365 | ||||||||||||
| Net cash used in investing activities | (179,315 | ) | (212,265 | ) | (356,893 | ) | (455,895 | ) | ||||||||
| Cash flows from financing activities: | ||||||||||||||||
| Borrowings on Senior Secured Credit Facility | 65,000 | 94,682 | 155,000 | 214,682 | ||||||||||||
| Payments on Senior Secured Credit Facility | (15,000 | ) | (135,000 | ) | (70,000 | ) | (279,682 | ) | ||||||||
| Proceeds from issuance of common stock, net of offering costs | — | 156,742 | — | 276,052 | ||||||||||||
| Other, net | (41 | ) | 69 | (12,012 | ) | (1,405 | ) | |||||||||
| Net cash provided by financing activities | 49,959 | 116,493 | 72,988 | 209,647 | ||||||||||||
| Net (decrease) increase in cash and cash equivalents | (14,206 | ) | 11,051 | (11,854 | ) | (794 | ) | |||||||||
| Cash and cash equivalents, beginning of period | 35,024 | 19,309 | 32,672 | 31,154 | ||||||||||||
| Cash and cash equivalents, end of period | $ | 20,818 | $ | 30,360 | $ | 20,818 | $ | 30,360 | ||||||||
| Laredo Petroleum, Inc. | ||||||||||||||||
| Selected operating data | ||||||||||||||||
| Three months ended September 30, | Nine months ended September 30, | |||||||||||||||
| 2017 | 2016 | 2017 | 2016 | |||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||
| Sales volumes: | ||||||||||||||||
| Oil (MBbl) | 2,425 | 2,150 | 7,027 | 6,168 | ||||||||||||
| NGL (MBbl) | 1,491 | 1,272 | 4,187 | 3,491 | ||||||||||||
| Natural gas (MMcf) | 9,630 | 7,766 | 26,154 | 21,600 | ||||||||||||
| Oil equivalents (MBOE)(1)(2) | 5,521 | 4,718 | 15,573 | 13,260 | ||||||||||||
| Average daily sales volumes (BOE/D)(1) | 60,011 | 51,276 | 57,044 | 48,392 | ||||||||||||
| % Oil | 44 | % | 46 | % | 45 | % | 47 | % | ||||||||
| Average sales prices(1): | ||||||||||||||||
| Oil, realized ($/Bbl)(3) | $ | 45.44 | $ | 39.10 | $ | 44.67 | $ | 35.42 | ||||||||
| NGL, realized ($/Bbl)(3) | $ | 18.58 | $ | 11.54 | $ | 16.32 | $ | 10.84 | ||||||||
| Natural gas, realized ($/Mcf)(3) | $ | 2.04 | $ | 2.07 | $ | 2.14 | $ | 1.58 | ||||||||
| Average price, realized ($/BOE)(3) | $ | 28.54 | $ | 24.34 | $ | 28.13 | $ | 21.91 | ||||||||
| Oil, hedged ($/Bbl)(4) | $ | 50.72 | $ | 57.57 | $ | 49.08 | $ | 57.76 | ||||||||
| NGL, hedged ($/Bbl)(4) | $ | 17.98 | $ | 11.54 | $ | 15.90 | $ | 10.84 | ||||||||
| Natural gas, hedged ($/Mcf)(4) | $ | 2.10 | $ | 2.31 | $ | 2.17 | $ | 2.18 | ||||||||
| Average price, hedged ($/BOE)(4) | $ | 30.80 | $ | 33.15 | $ | 30.07 | $ | 33.27 | ||||||||
| Average costs per BOE sold(1): | ||||||||||||||||
| Lease operating expenses | $ | 3.55 | $ | 3.85 | $ | 3.64 | $ | 4.37 | ||||||||
| Production and ad valorem taxes | 1.73 | 1.50 | 1.72 | 1.62 | ||||||||||||
| Midstream service expenses | 0.21 | 0.22 | 0.19 | 0.21 | ||||||||||||
| General and administrative: | ||||||||||||||||
| Cash | 2.90 | 3.49 | 2.94 | 3.51 | ||||||||||||
| Non-cash stock-based compensation, net of amounts capitalized | 1.62 | 2.05 | 1.73 | 1.48 | ||||||||||||
| Depletion, depreciation and amortization | 7.46 | 7.45 | 7.28 | 8.36 | ||||||||||||
| Total | $ | 17.47 | $ | 18.56 | $ | 17.50 | $ | 19.55 | ||||||||
_______________________________________________________________________________
(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.
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 September 30, | Nine months ended September 30, | |||||||||||||||
| (in thousands) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||
| Property acquisition costs: | ||||||||||||||||
| Evaluated(1) | $ | — | $ | 5,905 | $ | — | $ | 5,905 | ||||||||
| Unevaluated | — | 110,800 | — | 110,800 | ||||||||||||
| Exploration costs | 7,136 | 6,718 | 28,337 | 33,750 | ||||||||||||
| Development costs(2) | 160,359 | 72,411 | 397,255 | 225,103 | ||||||||||||
| Total costs incurred | $ | 167,495 | $ | 195,834 | $ | 425,592 | $ | 375,558 | ||||||||
_______________________________________________________________
(1) Evaluated property acquisition costs include $1.1 million in asset retirement obligations for the three and nine months ended September 30, 2016.
(2) Development costs include $0.4 million and $0.3 million in asset retirement obligations for the three months ended September 30, 2017 and 2016, respectively, and $0.6 million and $0.5 million for the nine months ended September 30, 2017 and 2016, respectively.
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 nine months ended September 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 the period 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 nine months ended September 30, 2017 and 2016, we present a line item that calculates Adjusted Net Income per Adjusted diluted common share.
The following presents a reconciliation of net income (loss) (GAAP) to Adjusted Net Income (non-GAAP):
| Three months ended September 30, | Nine months ended September 30, | |||||||||||||||
| (in thousands, except per share data, unaudited) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
| Net income (loss) | $ | 11,027 | $ | 9,485 | $ | 140,413 | $ | (242,318 | ) | |||||||
| Plus: | ||||||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||||
| (Gain) loss on derivatives, net | 27,441 | (6,850 | ) | (38,127 | ) | 43,783 | ||||||||||
| Cash settlements received for matured derivatives, net | 13,635 | 44,307 | 34,791 | 157,626 | ||||||||||||
| Cash settlements received for early terminations of derivatives, net | — | — | 4,234 | 80,000 | ||||||||||||
| Cash premiums paid for derivatives | (1,448 | ) | (2,709 | ) | (13,542 | ) | (86,972 | ) | ||||||||
| Impairment expense | — | — | — | 162,027 | ||||||||||||
| Loss on disposal of assets, net | 991 | 78 | 400 | 379 | ||||||||||||
| Write-off of debt issuance costs | — | — | — | 842 | ||||||||||||
| Adjusted net income before adjusted income tax expense | 51,646 | 44,311 | 128,169 | 115,367 | ||||||||||||
| Adjusted income tax expense | (18,593 | ) | (15,952 | ) | (46,141 | ) | (41,532 | ) | ||||||||
| Adjusted Net Income | $ | 33,053 | $ | 28,359 | $ | 82,028 | $ | 73,835 | ||||||||
| Net income (loss) per common share: | ||||||||||||||||
| Basic | $ | 0.05 | $ | 0.04 | $ | 0.59 | $ | (1.09 | ) | |||||||
| Diluted | $ | 0.05 | $ | 0.04 | $ | 0.57 | $ | (1.09 | ) | |||||||
| Adjusted Net Income per common share: | ||||||||||||||||
| Basic | $ | 0.14 | $ | 0.12 | $ | 0.34 | $ | 0.33 | ||||||||
| Adjusted diluted | $ | 0.13 | $ | 0.12 | $ | 0.34 | $ | 0.33 | ||||||||
| Weighted-average common shares outstanding: | ||||||||||||||||
| Basic | 239,306 | 234,639 | 239,017 | 221,303 | ||||||||||||
| Diluted | 244,887 | 238,108 | 244,693 | 221,303 | ||||||||||||
| Adjusted diluted | 244,887 | 238,108 | 244,693 | 223,197 | ||||||||||||
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.
The following presents a reconciliation of net income (loss) (GAAP) to Adjusted EBITDA (non-GAAP):
| Three months ended September 30, | Nine months ended September 30, | |||||||||||||||
| (in thousands, unaudited) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
| Net income (loss) | $ | 11,027 | $ | 9,485 | $ | 140,413 | $ | (242,318 | ) | |||||||
| Plus: | ||||||||||||||||
| Depletion, depreciation and amortization | 41,212 | 35,158 | 113,327 | 110,813 | ||||||||||||
| Impairment expense | — | — | — | 162,027 | ||||||||||||
| Non-cash stock-based compensation, net of amounts capitalized | 8,966 | 9,651 | 26,877 | 19,562 | ||||||||||||
| Accretion expense | 951 | 883 | 2,822 | 2,587 | ||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||||
| (Gain) loss on derivatives, net | 27,441 | (6,850 | ) | (38,127 | ) | 43,783 | ||||||||||
| Cash settlements received for matured derivatives, net | 13,635 | 44,307 | 34,791 | 157,626 | ||||||||||||
| Cash settlements received for early terminations of derivatives, net | — | — | 4,234 | 80,000 | ||||||||||||
| Cash premiums paid for derivatives | (1,448 | ) | (2,709 | ) | (13,542 | ) | (86,972 | ) | ||||||||
| Interest expense | 23,697 | 23,077 | 69,590 | 70,294 | ||||||||||||
| Write-off of debt issuance costs | — | — | — | 842 | ||||||||||||
| Loss on disposal of assets, net | 991 | 78 | 400 | 379 | ||||||||||||
| Income from equity method investee** | (2,371 | ) | (265 | ) | (7,910 | ) | (6,259 | ) | ||||||||
| Proportionate Adjusted EBITDA of equity method investee**(1) | 6,789 | 5,194 | 19,755 | 13,981 | ||||||||||||
| Adjusted EBITDA | $ | 130,890 | $ | 118,009 | $ | 352,630 | $ | 326,345 | ||||||||
_____________________________________________________________
(1) Proportionate Adjusted EBITDA of Medallion, our equity method investee, is calculated as follows:
| Three months ended September 30, | Nine months ended September 30, | |||||||||||||||
| (in thousands, unaudited) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
| Income from equity method investee | $ | 2,371 | $ | 265 | $ | 7,910 | $ | 6,259 | ||||||||
| Adjusted for proportionate share of: | ||||||||||||||||
| Depreciation and amortization | 4,418 | 4,929 | 11,845 | 7,722 | ||||||||||||
| Proportionate Adjusted EBITDA of equity method investee | $ | 6,789 | $ | 5,194 | $ | 19,755 | $ | 13,981 | ||||||||
** On October 30, 2017, LMS, together with Medallion Midstream Holdings, LLC, which is owned and controlled by an affiliate of The Energy & Minerals Group, completed the previously announced sale of 100% of the ownership interests in Medallion (the "Medallion Sale") to an affiliate of Global Infrastructure Partners ("GIP"), for cash consideration of $1.825 billion, subject to customary post-closing adjustments. LMS' net cash proceeds for its 49% ownership interest in Medallion are $829.6 million, before post-closing adjustments and taxes, but after deduction of its proportionate share of fees and other expenses associated with the Medallion Sale. The Medallion Sale closed pursuant to the membership interest purchase and sale agreement, which provides for potential post-closing additional cash consideration that is structured based on GIP's realized profit at exit. There can be no assurance as to when and whether the additional consideration will be paid.
Contacts:
Ron Hagood: (918) 858-5504 - RHagood@laredopetro.com
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