TULSA, OK, May 04, 2016 (GLOBE NEWSWIRE) -- Laredo Petroleum, Inc. LPI ("Laredo" or "the Company") today announced its 2016 first-quarter results, reporting a net loss attributable to common stockholders of $180.4 million, or $0.85 per diluted share, which includes a pre-tax, non-cash full cost ceiling impairment charge of $161.1 million. Adjusted Net Income, a non-GAAP financial measure, for the first quarter of 2016 was $17.3 million, or $0.08 per diluted share. Adjusted EBITDA, a non-GAAP financial measure, for the first quarter of 2016 was $96.1 million.
2016 First-Quarter Highlights
- Produced 46,202 barrels of oil equivalent ("BOE") per day, approximately 48% of which was oil, and increased anticipated production for full-year 2016 from a range midpoint of 15.5 million BOE to 15.95 million BOE
- Completed nine horizontal wells with an average completed lateral length of approximately 9,600 feet and peak 30-day initial production ("IP") rates averaging 1,192 BOE per day, or 129% of type curve
- Reduced unit lease operating expenses ("LOE") to $4.88 per BOE, down approximately 36% from the first-quarter 2015 rate of $7.58 per BOE
- Recognized more than $6.2 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 83,251 barrels of oil per day ("BOPD"), increasing from 10,681 BOPD in the approximately 60 days during the first quarter of 2015 in which the system was operational
- Received approximately $64.1 million of net cash settlements on commodity derivatives that matured, net of premiums paid, during first-quarter 2016, increasing the average sales price for oil by $29.33 per barrel and for natural gas by $0.77 per thousand cubic feet compared to pre-hedged average sales prices
Please see supplemental financial information at the end of this news release for reconciliations of non-GAAP financial measures.
"Our impressive operating results in the first quarter of 2016 are a continued validation of the Laredo model of strategically investing in data and infrastructure to fundamentally improve results," commented Randy A. Foutch, Chairman and Chief Executive Officer. "The uplift in well results we are seeing from utilizing our Earth Model, optimizing completions and investments in field infrastructure are having a meaningful positive impact on the capital efficiency of the Company. Additional capital efficiency benefits are derived from our long-range planning to structure our drilling obligations so that they are met with horizontal drilling, replacing the need to drill less profitable vertical wells."
"Our 49% ownership of the Medallion pipeline system continues to increase in value as volumes on the system grow and the Midland Basin affirms its distinction as the premier oil producing basin in the United States. Transported volumes in the first quarter of 2016 topped 80,000 barrels per day and in the second quarter of 2016 are expected to average approximately 105,000 barrels per day."
"We are raising the mid-point of our annual production guidance by 450,000 BOE to reflect both the well results in the first quarter as well as the benefits of our infrastructure investments that have reduced downtime in our wells and the lost production that results from it. Based on our increased guidance, operational and capital cost reductions and the recent increase in NGL prices, we now expect cash flow from operations to fund approximately 90% of our budgeted capital expenditures. With all of our expected oil production for the remainder of 2016 hedged with floors at about $67 per barrel, we are extremely well-positioned for a variable commodity price environment."
Operational Update
In the first quarter of 2016, Laredo produced 46,202 BOE per day, of which approximately 73% was oil and natural gas liquids ("NGL"). The Company completed nine horizontal wells during the first quarter of 2016 with an average lateral length of approximately 9,600 feet and an average working interest of 99%. The Company's proprietary Earth Model was used in all of these wells to land and steer the lateral and aid in optimizing completions, resulting in the average of the wells' 30-day peak IP rates performing 29% above type curve.
In the first quarter of 2016, LOE was $4.88 per BOE, a decrease of approximately 36% from the first quarter of 2015. Among other factors, previous investments in field infrastructure, primarily in the Company's four production corridors, such as water takeaway and recycle facilities, centralized compression and SCADA systems, lowered costs and reduced well downtime. The Company also continues to focus on the usage and procurement of products and services related to direct operating costs.
During the quarter, the Company completed wells in the Upper and Middle Wolfcamp and Cline zones. They are, on average, performing well above their respective type curves, further affirming the highly productive potential of Laredo's multi-zone, stacked resource. The results for the nine horizontal 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-208-209-8SU | Upper WC | 7,304 | 1,041 | 144 | % | |||||
| SUGG-A-171-5SU | Upper WC | 9,939 | 1,034 | 109 | % | |||||
| SUGG-E-197-195-2SU | Upper WC | 10,029 | 1,203 | 126 | % | |||||
| SUGG-E-197-195-1SU | Upper WC | 10,029 | 1,329 | 140 | % | |||||
| SUGG-A-197-195-5SU | Upper WC | 9,937 | 770 | 81 | % | |||||
| SUGG-E-197-195-3SU | Upper WC | 9,937 | 1,119 | 118 | % | |||||
| SUGG-A-197-195-4SU | Upper WC | 10,029 | 903 | 95 | % | |||||
| BODINE-A-174-173-2RM | Middle WC | 9,757 | 1,872 | 226 | % | |||||
| BODINE-A-174-173-2RC | Cline | 9,381 | 1,456 | 123 | % | |||||
| 1Q-16 Average | 9,594 | 1,192 | 129 | % | ||||||
(1) Adjusted for lateral length.
Early in the first quarter of 2016, the Company completed the Sugg-A-171-5SU, the final well of an 11-well package that was started in the third quarter of 2015 and drilled along the largest of the Company's four production corridors. The 11 wells, on average, are performing in-line with their type curves and were drilled and completed below AFE cost.
The Gas Technology Institute ("GTI") selected Laredo to host an $18 million research study within the 11-well package. GTI chose Laredo for the Company's operating expertise and the unique nature of the package, which leveraged Laredo's acreage position to drill a large number of wells at high density in multiple zones. The GTI consortium fully funded the collection of a comprehensive hydraulic fracturing dataset that provides a first-ever look at how induced underground fractures spread, at no direct cost to Laredo. According to GTI, this is the most comprehensive fracturing dataset ever captured in unconventional shale, and was gathered in the heart of Laredo's acreage. Laredo's operations team planned and executed the data collection portion of the project on-time and within budget, without impacting ongoing field operations. The data is being used to improve the understanding of how fractures propagate in reservoirs, specifically within Laredo's core acreage block in the Midland Basin. The dataset is providing unique insights into the behavior of the Company's reservoirs, with early proprietary analysis being integrated into Laredo's operations.
The Company is continuing to drive capital efficiency with peer-leading drilling operations. In the first quarter of 2016, Laredo further improved its drilling efficiency by approximately 9% from the fourth quarter of 2015, drilling on average 917 feet per day from rig acceptance to rig release. Two wells spud during the first quarter were each drilled with lateral lengths of 11,200 feet in 15 days, from rig acceptance to rig release.
In the first quarter, the Company continued to have success utilizing optimized completions in tandem with its proprietary Earth Model. Reservoir data that helps identify where to land the lateral incorporates attributes that are directly correlated to positive completion outcomes. When combined with higher sand concentrations and varying stage and cluster spacing the Company has to date realized an average uplift on oil production of greater than 30% of the oil type curve on the 18 horizontal wells drilled, to date, in the Upper and Middle Wolfcamp and Cline zones.
Laredo is currently operating three horizontal rigs and anticipates completing 11 horizontal wells during the second quarter of 2016, with a Laredo working interest of 100%. Six of the wells target the Upper Wolfcamp and five target the Middle Wolfcamp and have an expected average completed lateral length of approximately 9,500 feet. The Company is able to meet all drilling obligations with horizontal wells and does not have plans to drill vertical wells in 2016.
Laredo Midstream Services Update
The Company's oil and gas gathering, water infrastructure and centralized compression investments, primarily in the Company's four production corridors, continue to drive efficiency and cost improvements. In the first quarter of 2016 these investments provided a combined cash benefit to Laredo of approximately $6.2 million. Approximately 54% of the Company's gross operated oil production was transported on LMS' crude gathering system, reducing the cost and inconsistency of trucking. Barrels that are transported on the gathering system instead of being trucked benefit from a $0.95 per barrel price uplift and generate $0.75 per barrel in revenue that the buyer pays to transport the oil on the system. Additionally, Laredo transported approximately 55% of flowback and produced water by pipe in the first quarter of 2016, saving on average more than $1.00 per barrel versus water hauled by truck. Approximately 57% of the water transported by pipe was delivered to LMS' water recycling facility, saving $0.40 per barrel against average disposal costs. Approximately 15% of Laredo's water usage was supplied by recycled water from the LMS facility, at a savings of $0.30 per barrel versus fresh water.
The Medallion Gathering & Processing, LLC ("Medallion-Midland Basin") pipeline system, in which LMS owns a 49% interest, grew transported volumes by more than 20% in the first quarter of 2016 compared to the fourth quarter of 2015 as additional operators dedicated acreage to the system. The system transported an average of 83,251 BOPD in the first quarter of 2016 and is expected to transport approximately 105,000 BOPD in the second quarter of 2016. By the end of 2016, the system expects to be transporting between 140,000 and 150,000 BOPD to multiple delivery points. The potential growth of oil volumes transported by the Medallion pipeline system is reflected in the permitting activity in the system's operational area. In the first quarter of 2016, approximately 58% of all Permian Basin horizontal drilling permits issued by the State of Texas were in the six county area in which Medallion operates and nearly 40% of those permits were issued to operators that have dedicated acreage to the system.
2016 Capital Program
During the first quarter of 2016, Laredo invested approximately $89 million in exploration and development activities and approximately $0.7 million in infrastructure held by LMS. Approximately $46 million of the $89 million invested in exploration and development activities was related to drilling activities begun in 2015.
Liquidity
On May 2, 2016, in connection with the regular semi-annual redetermination of the Company's senior secured credit facility, lenders set the Company's borrowing base at $815 million, which, as in the past, does not include the Company's interest in the Medallion pipeline system. At May 3, 2016, the Company had approximately $7 million in cash and equivalents and an outstanding balance of $210 million under the senior secured credit facility, resulting in total liquidity of approximately $612 million.
Commodity Derivatives
Laredo maintains an active hedging program to reduce the variability in its anticipated cash flow due to fluctuations in commodity prices. At March 31, 2016, the Company had hedges in place for the remaining three quarters of 2016 for 4,898,250 barrels of oil at a weighted-average floor price of $70.85 per barrel. Subsequently, the Company hedged an additional 600,000 barrels of oil and currently has 5,498,250 barrels of oil hedged at a weighted-average floor price of $67.48 per barrel, representing approximately 100% of anticipated oil production for the remainder of 2016. At March 31, 2016, the Company had also hedged 14,025,000 million British thermal units ("MMBtu") of natural gas for 2016 at a weighted-average floor price of $3.00 per MMBtu, representing approximately 75% of anticipated natural gas production for 2016.
At March 31, 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 13,515,000 MMBtu of natural gas at a weighted-average floor price of $2.70 per MMBtu. Subsequently, the Company hedged an additional 5,256,000 MMBtu of natural gas for 2017 and currently has 18,771,000 MMBtu of natural gas hedged at a weighted-average floor price of $2.65 per MMBtu for 2017.
At March 31, 2016, for 2018, the Company had hedged 1,049,375 barrels of oil at a weighted-average floor price of $60.00 per barrel and 8,220,000 MMBtu of natural gas at a weighted-average floor price of $2.50 per MMBtu. Subsequently, the Company hedged an additional 4,635,500 MMBtu of natural gas for 2018 and currently has 12,855,500 MMBtu of natural gas hedged at a weighted-average floor price of $2.50 per MMBtu for 2018.
Increased 2016 Production Guidance and Second-Quarter 2016 Guidance
The Company is increasing full-year 2016 production guidance under its current budget from a range of 15.3-15.7 million BOE to 15.8-16.1 million BOE. The increase is primarily driven by the positive results of utilizing the Earth Model with enhanced completions and the benefits of infrastructure investments that have minimized downtime of wells in the Company's base production.
The table below reflects the Company's guidance for the second quarter of 2016:
| 2Q-2016 | ||||
| Production (MMBOE) | 3.8 - 4.1 | |||
| Product % of total production: | ||||
| Crude oil | 45% - 47% | |||
| Natural gas liquids | 26% - 27% | |||
| Natural gas | 27% - 28% | |||
| Price Realizations (pre-hedge): | ||||
| Crude oil (% of WTI) | ~82% | |||
| Natural gas liquids (% of WTI) | ~24% | |||
| Natural gas (% of Henry Hub) | ~67% | |||
| Operating Costs & Expenses: | ||||
| Lease operating expenses ($/BOE) | $4.75 - $5.75 | |||
| Midstream expenses ($/BOE) | $0.15 - $0.35 | |||
| Production and ad valorem taxes (% of oil, NGL and natural gas revenue) | 8.25 | % | ||
| General and administrative expenses ($/BOE) | $4.75 - $5.75 | |||
| Depletion, depreciation and amortization ($/BOE) | $8.50 - $9.50 | |||
Conference Call Details
On Thursday, May 5, 2016, at 7:00 a.m. CT, Laredo will host a conference call to discuss its first-quarter 2016 financial and operating results and management's outlook. 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 94358441, approximately 10 minutes prior to the scheduled conference time. International participants should dial 253.336.8309, also using conference code 94358441. A telephonic replay will be available approximately two hours after the call on May 5, 2016 through Thursday, May 12, 2016. Participants may access this replay by dialing 855.859.2056, using conference code 94358441.
Field Tour and Investor Meeting
The Company will host a field tour and investor meeting on June 13-14, 2016 in Midland, TX. The investor meeting will be held on Monday, June 13 at 4:00 p.m. CT. On Tuesday, June 14 the Company will provide a tour of key infrastructure projects within its Permian-Garden City operations. Participants may register via the Company's website at www.laredopetro.com on the home page link "Field Tour/Investor Meeting Registration."
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.
| Laredo Petroleum, Inc. | ||||||||
| Condensed consolidated statements of operations | ||||||||
| Three months ended March 31, | ||||||||
| (in thousands, except per share data) | 2016 | 2015 | ||||||
| (unaudited) | ||||||||
| Revenues: | ||||||||
| Oil, NGL and natural gas sales | $ | 73,142 | $ | 118,118 | ||||
| Midstream service revenues | 1,801 | 1,309 | ||||||
| Sales of purchased oil | 31,614 | 31,267 | ||||||
| Total revenues | 106,557 | 150,694 | ||||||
| Costs and expenses: | ||||||||
| Lease operating expenses | 20,518 | 32,380 | ||||||
| Production and ad valorem taxes | 6,435 | 9,086 | ||||||
| Midstream service expenses | 609 | 1,574 | ||||||
| Minimum volume commitments | — | 1,656 | ||||||
| Costs of purchased oil | 32,946 | 31,200 | ||||||
| General and administrative | 19,451 | 21,855 | ||||||
| Restructuring expenses | — | 6,042 | ||||||
| Accretion of asset retirement obligations | 844 | 579 | ||||||
| Depletion, depreciation and amortization | 41,478 | 71,942 | ||||||
| Impairment expense | 161,064 | 878 | ||||||
| Total costs and expenses | 283,345 | 177,192 | ||||||
| Operating loss | (176,788 | ) | (26,498 | ) | ||||
| Non-operating income (expense): | ||||||||
| Gain on derivatives, net | 17,885 | 63,155 | ||||||
| Income (loss) from equity method investee | 2,298 | (433 | ) | |||||
| Interest expense | (23,705 | ) | (32,414 | ) | ||||
| Other, net | (61 | ) | (639 | ) | ||||
| Non-operating income (expense), net | (3,583 | ) | 29,669 | |||||
| Income (loss) before income taxes | (180,371 | ) | 3,171 | |||||
| Income tax expense: | ||||||||
| Deferred | — | (3,643 | ) | |||||
| Total income tax expense | — | (3,643 | ) | |||||
| Net loss | $ | (180,371 | ) | $ | (472 | ) | ||
| Net loss per common share: | ||||||||
| Basic | $ | (0.85 | ) | $ | — | |||
| Diluted | $ | (0.85 | ) | $ | — | |||
| Weighted-average common shares outstanding: | ||||||||
| Basic | 211,560 | 162,426 | ||||||
| Diluted | 211,560 | 162,426 | ||||||
| Laredo Petroleum, Inc. | ||||||||
| Condensed consolidated balance sheets | ||||||||
| (in thousands) | March 31, 2016 | December 31, 2015 | ||||||
| Assets: | (unaudited) | (unaudited) | ||||||
| Current assets | $ | 280,858 | $ | 332,232 | ||||
| Net property and equipment | 1,087,733 | 1,200,255 | ||||||
| Other noncurrent assets | 268,573 | 280,800 | ||||||
| Total assets | $ | 1,637,164 | $ | 1,813,287 | ||||
| Liabilities and stockholders' (deficit) equity: | ||||||||
| Current liabilities | $ | 156,074 | $ | 216,815 | ||||
| Long-term debt, net | 1,476,890 | 1,416,226 | ||||||
| Other noncurrent liabilities | 49,916 | 48,799 | ||||||
| Stockholders' (deficit) equity | (45,716 | ) | 131,447 | |||||
| Total liabilities and stockholders' (deficit) equity | $ | 1,637,164 | $ | 1,813,287 | ||||
| Laredo Petroleum, Inc. | ||||||||
| Condensed consolidated statements of cash flows | ||||||||
| Three months ended March 31, | ||||||||
| (in thousands) | 2016 | 2015 | ||||||
| (unaudited) | ||||||||
| Cash flows from operating activities: | ||||||||
| Net loss | $ | (180,371 | ) | $ | (472 | ) | ||
| Adjustments to reconcile net loss to net cash provided by operating activities: | ||||||||
| Deferred income tax expense | — | 3,643 | ||||||
| Depletion, depreciation and amortization | 41,478 | 71,942 | ||||||
| Impairment expense | 161,064 | 878 | ||||||
| Non-cash stock-based compensation, net of amounts capitalized | 3,838 | 4,788 | ||||||
| Mark-to-market on derivatives: | ||||||||
| Gain on derivatives, net | (17,885 | ) | (63,155 | ) | ||||
| Cash settlements received for matured derivatives, net | 65,937 | 63,141 | ||||||
| Cash settlements received for early terminations of derivatives, net | 80,000 | — | ||||||
| Cash premiums paid for derivatives | (81,850 | ) | (1,421 | ) | ||||
| Amortization of debt issuance costs | 1,120 | 1,377 | ||||||
| Other, net | (7,614 | ) | (953 | ) | ||||
| Cash flows from operations before changes in working capital | 65,717 | 79,768 | ||||||
| Changes in working capital | (9,131 | ) | (54,086 | ) | ||||
| Changes in other noncurrent liabilities and fair value of performance unit awards | (69 | ) | 1,183 | |||||
| Net cash provided by operating activities | 56,517 | 26,865 | ||||||
| Cash flows from investing activities: | ||||||||
| Capital expenditures: | ||||||||
| Oil and natural gas properties | (105,155 | ) | (243,733 | ) | ||||
| Midstream service assets | (1,937 | ) | (20,434 | ) | ||||
| Other fixed assets | (630 | ) | (3,919 | ) | ||||
| Investment in equity method investee | (26,660 | ) | (14,495 | ) | ||||
| Proceeds from dispositions of capital assets, net of costs | 218 | 35 | ||||||
| Net cash used in investing activities | (134,164 | ) | (282,546 | ) | ||||
| Cash flows from financing activities: | ||||||||
| Borrowings on Senior Secured Credit Facility | 85,000 | 175,000 | ||||||
| Payments on Senior Secured Credit Facility | (25,000 | ) | (475,000 | ) | ||||
| Issuance of March 2023 Notes | — | 350,000 | ||||||
| Proceeds from issuance of common stock, net of offering costs | — | 754,163 | ||||||
| Other | (1,412 | ) | (8,710 | ) | ||||
| Net cash provided by financing activities | 58,588 | 795,453 | ||||||
| Net (decrease) increase in cash and cash equivalents | (19,059 | ) | 539,772 | |||||
| Cash and cash equivalents, beginning of period | 31,154 | 29,321 | ||||||
| Cash and cash equivalents, end of period | $ | 12,095 | $ | 569,093 | ||||
| Laredo Petroleum, Inc. | ||||||||
| Selected operating data | ||||||||
| Three months ended March 31, | ||||||||
| 2016 | 2015 | |||||||
| (unaudited) | ||||||||
| Sales volumes: | ||||||||
| Oil (MBbl) | 2,006 | 2,172 | ||||||
| NGL (MBbl) | 1,066 | 989 | ||||||
| Natural gas (MMcf) | 6,796 | 6,680 | ||||||
| Oil equivalents (MBOE)(1)(2) | 4,204 | 4,274 | ||||||
| Average daily sales volumes (BOE/D)(2) | 46,202 | 47,487 | ||||||
| % Oil | 48 | % | 51 | % | ||||
| Average sales prices: | ||||||||
| Oil, realized ($/Bbl)(3) | $ | 27.51 | $ | 41.73 | ||||
| NGL, realized ($/Bbl)(3) | $ | 8.50 | $ | 13.34 | ||||
| Natural gas, realized ($/Mcf)(3) | $ | 1.31 | $ | 2.14 | ||||
| Average price, realized ($/BOE)(3) | $ | 17.40 | $ | 27.64 | ||||
| Oil, hedged ($/Bbl)(4) | $ | 56.84 | $ | 69.51 | ||||
| NGL, hedged ($/Bbl)(4) | $ | 8.50 | $ | 13.34 | ||||
| Natural gas, hedged ($/Mcf)(4) | $ | 2.08 | $ | 2.35 | ||||
| Average price, hedged ($/BOE)(4) | $ | 32.64 | $ | 42.08 | ||||
| Average costs per BOE sold: | ||||||||
| Lease operating expenses | $ | 4.88 | $ | 7.58 | ||||
| Production and ad valorem taxes | 1.53 | 2.13 | ||||||
| Midstream service expenses | 0.14 | 0.37 | ||||||
| General and administrative(5) | 4.63 | 5.11 | ||||||
| Depletion, depreciation and amortization | 9.87 | 16.83 | ||||||
| Total | $ | 21.05 | $ | 32.02 | ||||
(1) BOE equivalents are calculated using a conversion rate of six Mcf per one Bbl.
(2) The volumes presented are based on actual results and are not calculated using the rounded numbers presented in the table above.
(3) Realized oil, 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 include 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 $3.8 million and $4.8 million for the three months ended March 31, 2016 and 2015, respectively.
Laredo Petroleum, Inc.
Costs incurred
Costs incurred in the acquisition, exploration and development of oil, NGL and natural gas assets are presented below:
| Three months ended March 31, | ||||||||
| (in thousands) | 2016 | 2015 | ||||||
| (unaudited) | ||||||||
| Property acquisition costs: | ||||||||
| Evaluated | $ | — | $ | — | ||||
| Unevaluated | — | — | ||||||
| Exploration | 7,263 | 4,513 | ||||||
| Development costs(1) | 81,886 | 206,672 | ||||||
| Total costs incurred | $ | 89,149 | $ | 211,185 | ||||
(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 March 31, 2016 and 2015, respectively.
Laredo Petroleum, Inc.
Supplemental reconciliation of GAAP to non-GAAP financial measures
(Unaudited)
Non-GAAP financial measures
The non-GAAP financial measures of Adjusted Net Income and Adjusted EBITDA, as defined by us, may not be comparable to similarly titled measures used by other companies. Therefore, these non-GAAP measures should be considered in conjunction with net income or loss and other performance measures prepared in accordance with GAAP, such as operating income or 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
Adjusted Net Income is a non-GAAP financial measure we use to evaluate performance, prior to gains or losses on derivatives, cash settlements of matured derivatives, net of premiums paid, cash settlements on early terminated derivatives, impairment expense, restructuring expenses, loss on early redemption of debt, buyout of minimum volume commitment, gains or losses on disposal of assets, write-off of debt issuance costs, bad debt expense and after applying adjusted income tax expense. We believe Adjusted Net Income helps investors compare our results with other oil and natural gas companies. During the three months ended March 31, 2016, we changed the methodology for calculating Adjusted Net Income. As such, the prior periods' Adjusted Net Income has been modified for comparability.
The following presents a reconciliation of income (loss) before income taxes to Adjusted Net Income:
| Three months ended March 31, | ||||||||
| (in thousands, except for per share data, unaudited) | 2016 | 2015 | ||||||
| Income (loss) before income taxes | $ | (180,371 | ) | $ | 3,171 | |||
| Plus: | ||||||||
| Mark-to-market on derivatives: | ||||||||
| Gain on derivatives, net | (17,885 | ) | (63,155 | ) | ||||
| Cash settlements received for matured derivatives, net | 65,937 | 63,141 | ||||||
| Cash settlements received for early terminations of derivatives, net | 80,000 | — | ||||||
| Cash premiums paid for derivatives | (81,850 | ) | (1,421 | ) | ||||
| Impairment expense | 161,064 | 878 | ||||||
| Restructuring expenses. | — | 6,042 | ||||||
| Loss on disposal of assets, net | 160 | 762 | ||||||
| 27,055 | 9,418 | |||||||
| Adjusted income tax expense(1) | (9,740 | ) | (3,390 | ) | ||||
| Adjusted Net Income | $ | 17,315 | $ | 6,028 | ||||
| Adjusted Net Income per common share: | ||||||||
| Basic | $ | 0.08 | $ | 0.04 | ||||
| Diluted | $ | 0.08 | $ | 0.04 | ||||
| Weighted-average common shares outstanding: | ||||||||
| Basic | 211,560 | 162,426 | ||||||
| Diluted | 211,560 | 162,426 | ||||||
(1) Adjusted income tax expense is calculated by applying the tax rate of 36% for both the three months ended March 31, 2016 and 2015.
Adjusted EBITDA
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 received for early terminations of 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 to Adjusted EBITDA:
| Three months ended March 31, | ||||||||
| (in thousands, unaudited) | 2016 | 2015 | ||||||
| Net loss | $ | (180,371 | ) | $ | (472 | ) | ||
| Plus: | ||||||||
| Deferred income tax expense | — | 3,643 | ||||||
| Depletion, depreciation and amortization | 41,478 | 71,942 | ||||||
| Impairment expense | 161,064 | 878 | ||||||
| Non-cash stock-based compensation, net of amounts capitalized | 3,838 | 4,788 | ||||||
| Restructuring expenses | — | 6,042 | ||||||
| Gain on derivatives, net | (17,885 | ) | (63,155 | ) | ||||
| Cash settlements received for matured derivatives, net | 65,937 | 63,141 | ||||||
| Cash settlements received for early terminations of derivatives, net | 80,000 | — | ||||||
| Premiums paid for derivatives | (81,850 | ) | (1,421 | ) | ||||
| Interest expense | 23,705 | 32,414 | ||||||
| Loss on disposal of assets, net | 160 | 762 | ||||||
| Adjusted EBITDA | $ | 96,076 | $ | 118,562 | ||||
16-6
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