Attached files
| file | filename |
|---|---|
| 8-K - 8-K - Laredo Petroleum, Inc. | a3q14erpr8-k.htm |
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 2014 THIRD-QUARTER
FINANCIAL AND OPERATING RESULTS
TULSA, OK - November 6, 2014 - Laredo Petroleum, Inc. (NYSE: LPI) (“Laredo” or “Company”), today announced its 2014 third-quarter results, reporting net income attributable to common stockholders of $83.4 million, or $0.58 per diluted share. Adjusted Net Income, a non-GAAP financial measure, for the third quarter of 2014 was $27.5 million, or $0.19 per diluted share. Adjusted EBITDA, a non-GAAP financial measure, for the third quarter of 2014 was $142.0 million. (Please see supplemental financial information at the end of this news release for reconciliations of these non-GAAP financial measures.)
2014 Third-Quarter Highlights
• | Produced a Company Permian Basin record of 32,970 barrels of oil equivalent (“BOE”) per day, on a two-stream basis, up approximately 36% from the third quarter of 2013 and up approximately 15% from second-quarter 2014 |
• | Increased Adjusted EBITDA to $142.0 million, up approximately 19% from the third quarter of 2013 and up approximately 20% from second-quarter 2014 |
• | Increased Permian oil and natural gas sales to $199.5 million, up approximately 25% from third-quarter 2013 and up approximately 9% from second-quarter 2014 |
• | Completed a Company record 26 horizontal wells during the third quarter, for a total of 52 horizontal wells completed during the first nine months of 2014 |
• | Completed Laredo Midstream Services’ (“LMS”) expansion of the Company’s crude gathering system into the southern portion of the Company’s Reagan County leasehold, which will enable the Company to transport approximately 50% of its oil production through the crude gathering system by the end of 2014, significantly reducing Laredo’s dependence on trucking activities |
• | Commenced line-fill on a joint venture oil pipeline (49% owned by LMS) from Laredo’s acreage to Colorado City, Texas, which will enable nearly 100% of the Company’s oil production to bypass the congested Midland market by the first quarter of 2015 |
• | Commenced analysis of potential transaction opportunities involving a portion of Laredo’s northern Permian-Garden City acreage and subsequently engaged an adviser to assist in such analysis |
“Third-quarter production volumes increased substantially, as anticipated, showing the impact of the numerous multi-well pads that are now online,” said Randy A. Foutch, Laredo Chairman and Chief Executive Officer. “Additionally, we are gaining efficiencies by focusing these pads along our four production corridors that we are constructing to take advantage of our contiguous acreage position. As a result, we expect to realize reduced capital and operating costs and enhanced price realizations as operations are concentrated around centralized infrastructure.”
“Our strategy of aggressively hedging our commodity price exposure and insistence on short-term service contracts gives us added flexibility to withstand the recent oil price weakness. These measures, coupled with our improving operational efficiencies, enable us to take a methodical approach to assessing current market conditions and to quickly implement appropriate adjustments to our capital plan, as warranted.”
Operational Update
In the third quarter of 2014, Laredo produced a record 32,970 BOE per day, on a two-stream basis, from the Permian Basin, up approximately 36% from the prior-year quarter. The Company also completed a record 26 horizontal wells in the third quarter, bringing the total horizontal completions for the year to 52. Eighteen of the third-quarter 2014 completions achieved at least a full month of peak production in the quarter. During the fourth quarter of 2014, the Company expects to complete 12 additional horizontal wells that could achieve a full month of peak production before year end.
Drilling stacked lateral wells on multi-well pads along production corridors is the backbone of Laredo’s full-scale development program. The initial four production corridors that the Company is currently building provide the necessary infrastructure to accommodate handling the large volumes of water, oil and natural gas associated with concentrated, multi-zone development drilling. During the third quarter, the Company completed 14 horizontal wells on five multi-well pads on the production corridors. In aggregate, these wells were performing at 96% of their respective type curves based on their peak 30-day initial production rate per 1,000 feet of lateral.
Through the third quarter of 2014, Laredo has completed 150 horizontal wells in the Permian-Garden City area, primarily on the southern portion of its acreage. In mid-2012, the Company began drilling long lateral horizontal wells and stimulating them with more densely spaced completion stages. Ninety-eight of the Company’s horizontal wells have been drilled and completed in this manner, including 56 with at least 180 days of production history and 37 with at least one year of production history. The performance of these wells, over an extended time frame, supports Laredo’s type curves in each of its four delineated zones and the resource potential identified in the de-risked portion of the Company’s Permian-Garden City acreage.
2
Wells with 180 days of Production | Wells with 365 days of Production | ||||||||||||
Zone | No. of Wells | Avg. Cumulative Production per Well | % of Type Curve | No. of Wells | Avg. Cumulative Production per Well | % of Type Curve | |||||||
(long laterals) | (Two-stream MBOE) | (long laterals) | (Two-stream MBOE) | ||||||||||
Upper Wolfcamp | 32 | 82.2 | 98% | 23 | 134.3 | 104% | |||||||
Middle Wolfcamp | 12 | 79.0 | 109% | 4 | 136.7 | 123% | |||||||
Lower Wolfcamp | 6 | 79.2 | 106% | 5 | 124.1 | 108% | |||||||
Cline | 6 | 75.9 | 98% | 5 | 108.4 | 94% | |||||||
Table includes horizontal wells with completed lateral lengths >6,000 feet and at least 24 stages. Excludes four exploratory wells.
“We are now beginning to realize the benefits of our concentrated multi-well pad development along the initial production corridors that we believe enhance the value of the southern portion of our Permian-Garden City acreage,” added Foutch. “To further accelerate this value enhancement, we have engaged an adviser to assist with structuring a potential transaction on a portion of our northern Permian-Garden City leasehold.”
Laredo Midstream Services Update
The Company’s wholly-owned subsidiary, Laredo Midstream Services, continued to invest in the infrastructure needed to efficiently develop Laredo’s contiguous acreage position and provide appropriate takeaway capacity to multiple sales points. Build-out of the Company’s initial four production corridors continued during the third quarter and three of these corridors are expected to be substantially complete during the first quarter of 2015. The expansion of LMS’s crude gathering system in the southern portion of the Reagan County leasehold was completed in the third quarter and began operations early in the fourth quarter. This crude gathering system, which has the capacity to handle approximately 30,000 barrels of oil per day (“BOPD”), is currently handling approximately 10,000 gross BOPD, up from approximately 6,000 gross BOPD in the third quarter. Oil gathered on the LMS system benefits from a $0.95 per barrel uplift to wellhead realizations due to reduced transportation costs. Additionally, oil transported on the system generates gathering service revenue for LMS of approximately $0.75 per barrel.
LMS holds a 49% equity ownership in the 88-mile Medallion Pipeline that links Laredo’s Glasscock and Reagan Oil Stations with Colorado City, Texas. The pipeline, which has an initial capacity of approximately 65,000 BOPD and is expandable to 130,000 BOPD, was completed during the third quarter and began line-fill. Line-fill has now been completed and the Company is currently delivering approximately 10,000 gross BOPD into the pipeline. Additional infrastructure, expected to be completed by the end of the year, will facilitate the delivery of nearly all of the Company’s oil production to the Medallion Pipeline, effectively eliminating the Company’s exposure to the often congested Midland market, if desired, by the first quarter of 2015.
3
Capital Program
During the third quarter of 2014, Laredo invested approximately $325 million in drilling and completion activities and approximately $24 million in pipelines and related infrastructure assets held by LMS. Additionally, approximately $201 million was invested in the previously announced leasehold acquisitions. This new acreage is primarily contiguous to the Company’s existing Permian-Garden City acreage and increases the Company’s working interest in existing leasehold, expands its ability to more efficiently develop and utilize production corridors and minimizes future drilling requirements.
Liquidity
At September 30, 2014, the Company had $75 million drawn on its senior secured credit facility, which had $825 million available for borrowings. On October 27, 2014, lenders in the Company’s senior secured credit facility increased the borrowing base to $1.15 billion, which now has an aggregate elected commitment amount of $900 million. As of November 5, 2014, the outstanding balance under the Company’s senior secured credit facility was $150 million.
Commodity Derivatives
Laredo actively monitors its hedging program to mitigate the variability in its anticipated cash flow due to fluctuations in commodity prices. At November 5, 2014, the Company had hedges in place for the fourth quarter of 2014 for 1,557,499 barrels of oil at a weighted-average floor price of $89.45 per barrel, representing approximately 80% of anticipated oil production for the fourth quarter of 2014. Additionally, the Company had natural gas hedges in place for the fourth quarter of 2014 for 5,482,000 million British thermal units (“MMBtu”) of natural gas at a weighted-average floor price of $3.66 per MMBtu, representing approximately 50% of anticipated natural gas production for the fourth quarter of 2014.
For 2015, the Company has hedged 7,685,020 barrels of oil at a weighted-average floor price of $80.99 per barrel, representing more than 90% of anticipated oil production for 2015. The Company also has hedged 28,600,000 MMBtu of natural gas at a weighted-average floor price of $3.00 per MMBtu, representing more than 60% of anticipated natural gas production for 2015.
Potential Transaction
Laredo has engaged an adviser to assist with structuring potential transaction opportunities involving a portion of the Company’s northern Permian-Garden City proved and unproved oil and natural gas properties. There can be no assurance that any transaction will be completed.
4
Guidance
The table below reflects the Company’s guidance for fourth-quarter 2014:
4Q-2014 | ||
Production (MMBOE) | 3.2 - 3.5 | |
Crude Oil % of production | 58% | |
Price Realizations (pre-hedge, two-stream basis, % of NYMEX): | ||
Crude oil | 90% - 95% | |
Natural gas, including natural gas liquids | 135% - 145% | |
Operating Costs & Expenses: | ||
Lease operating expenses ($/BOE) | $7.30 - $7.80 | |
Midstream expenses ($/BOE) | $0.50 - $0.60 | |
Production and ad valorem taxes (% of oil and gas revenue) | 7.25% | |
General and administrative expenses ($/BOE) | $8.75 - $9.25 | |
Depletion, depreciation and amortization ($/BOE) | $20.00 - $21.00 | |
Conference Call Details
Laredo has scheduled a conference call today at 9:00 a.m. CT to discuss its third-quarter 2014 financial and operating results and management’s outlook for the future, the content of which is not part of this earnings release. Participants may listen to the call via the Company’s website at www.laredopetro.com, under the tab for “Investor Relations.” The conference call may also be accessed by dialing 1-866-713-8563, using the conference code 63108621. International participants may access the call by dialing 1-617-597-5311, also using conference code 63108621. It is recommended that participants dial in approximately 10 minutes prior to the start of the conference call. A telephonic replay will be available approximately two hours after the call on November 6, 2014 through Thursday, November 13, 2014. Participants may access this replay by dialing 1-888-286-8010, using conference code 50262757.
About Laredo
Laredo Petroleum, Inc. is an independent energy company with headquarters in Tulsa, Oklahoma. Laredo's business strategy is focused on the exploration, development and acquisition of oil and natural gas properties primarily in the Permian region of the United States.
Additional information about Laredo may be found on its website at www.laredopetro.com.
Forward-Looking Statements
This press release (and oral statements made regarding the subjects of this release, including any statements made on the conference call announced 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
5
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, including statements as to the expected timing, completion and effects of any proposed transactions 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 risks described in its Annual Report on Form 10-K for the year ended December 31, 2013, its Quarterly Report on Form 10-Q for the period ended September 30, 2014, and those set forth from time to time in other filings with the Securities and 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 (“EDGAR”) 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 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. The Company may use the term “resource potential” which the SEC guidelines restrict from being included in filings with the SEC without strict compliance with SEC definitions or “recoverable resource” which refers to the Company’s internal estimates of booked reserves plus resource potential.“Resource potential” refers 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, which, when compared to a conventional play, typically has a lower geological and/or commercial development risk. Unbooked resource potential does not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules and does not include any proved reserves. Actual quantities that may be ultimately recovered from the Company’s interests will differ substantially. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and 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, the Company’s 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.
# # #
Contact:
Ron Hagood: (918) 858-5504 - RHagood@laredopetro.com
14-16
6
Laredo Petroleum, Inc.
Condensed consolidated statements of operations
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||
(in thousands, except per share data) | 2014 | 2013 | 2014 | 2013 | ||||||||||||
(unaudited) | (unaudited) | |||||||||||||||
Revenues: | ||||||||||||||||
Oil and natural gas sales | $ | 199,490 | $ | 170,840 | $ | 555,576 | $ | 511,513 | ||||||||
Midstream service revenue | 751 | — | 1,019 | 328 | ||||||||||||
Total revenues | 200,241 | 170,840 | 556,595 | 511,841 | ||||||||||||
Costs and expenses: | ||||||||||||||||
Lease operating expenses | 25,165 | 19,565 | 67,129 | 64,192 | ||||||||||||
Midstream service expense | 1,225 | 1,090 | 3,596 | 2,569 | ||||||||||||
Production and ad valorem taxes | 12,550 | 11,723 | 38,160 | 32,890 | ||||||||||||
Natural gas volume commitment - affiliates | 675 | 305 | 1,779 | 444 | ||||||||||||
General and administrative | 20,884 | 18,529 | 67,365 | 50,978 | ||||||||||||
Stock-based compensation | 6,194 | 5,876 | 16,919 | 13,556 | ||||||||||||
Accretion of asset retirement obligations | 442 | 350 | 1,279 | 1,154 | ||||||||||||
Depletion, depreciation and amortization | 63,942 | 55,982 | 166,605 | 186,719 | ||||||||||||
Total costs and expenses | 131,077 | 113,420 | 362,832 | 352,502 | ||||||||||||
Operating income | 69,164 | 57,420 | 193,763 | 159,339 | ||||||||||||
Non-operating income (expense): | ||||||||||||||||
Gain (loss) on derivatives: | ||||||||||||||||
Commodity derivatives, net | 92,790 | (9,830 | ) | (1,447 | ) | (2,709 | ) | |||||||||
Interest rate derivatives, net | — | (8 | ) | — | (23 | ) | ||||||||||
Income (loss) from equity method investee | (61 | ) | 48 | (86 | ) | (65 | ) | |||||||||
Interest expense | (30,549 | ) | (24,929 | ) | (90,192 | ) | (76,221 | ) | ||||||||
Other | (2,159 | ) | (836 | ) | (2,232 | ) | (868 | ) | ||||||||
Non-operating income (expense), net | 60,021 | (35,555 | ) | (93,957 | ) | (79,886 | ) | |||||||||
Income from continuing operations before income taxes | 129,185 | 21,865 | 99,806 | 79,453 | ||||||||||||
Income tax expense: | ||||||||||||||||
Deferred | (45,778 | ) | (10,048 | ) | (35,511 | ) | (31,205 | ) | ||||||||
Total income tax expense | (45,778 | ) | (10,048 | ) | (35,511 | ) | (31,205 | ) | ||||||||
Income from continuing operations | 83,407 | 11,817 | 64,295 | 48,248 | ||||||||||||
Income from discontinued operations, net of tax | — | 726 | — | 1,516 | ||||||||||||
Net income | $ | 83,407 | $ | 12,543 | $ | 64,295 | $ | 49,764 | ||||||||
Net income per common share: | ||||||||||||||||
Basic: | ||||||||||||||||
Income from continuing operations | $ | 0.59 | $ | 0.09 | $ | 0.46 | $ | 0.37 | ||||||||
Income from discontinued operations, net of tax | — | — | — | 0.01 | ||||||||||||
Net income per share | $ | 0.59 | $ | 0.09 | $ | 0.46 | $ | 0.38 | ||||||||
Diluted: | ||||||||||||||||
Income from continuing operations | $ | 0.58 | $ | 0.09 | $ | 0.45 | $ | 0.37 | ||||||||
Income from discontinued operations, net of tax | — | — | — | 0.01 | ||||||||||||
Net income per share | $ | 0.58 | $ | 0.09 | $ | 0.45 | $ | 0.38 | ||||||||
Weighted-average common shares outstanding: | ||||||||||||||||
Basic | 141,413 | 134,461 | 141,261 | 129,701 | ||||||||||||
Diluted | 143,813 | 136,460 | 143,583 | 131,589 | ||||||||||||
7
Laredo Petroleum, Inc.
Condensed consolidated balance sheets
(in thousands) | September 30, 2014 | December 31, 2013 | ||||||
Assets: | (unaudited) | (unaudited) | ||||||
Current assets | $ | 190,461 | $ | 307,609 | ||||
Net property and equipment | 3,064,851 | 2,204,324 | ||||||
Other noncurrent assets | 77,597 | 111,827 | ||||||
Total assets | $ | 3,332,909 | $ | 2,623,760 | ||||
Liabilities and stockholders' equity: | ||||||||
Current liabilities | $ | 318,174 | $ | 253,969 | ||||
Long-term debt | 1,576,358 | 1,051,538 | ||||||
Other noncurrent liabilities | 83,682 | 45,997 | ||||||
Stockholders' equity | 1,354,695 | 1,272,256 | ||||||
Total liabilities and stockholders' equity | $ | 3,332,909 | $ | 2,623,760 | ||||
8
Laredo Petroleum, Inc.
Condensed consolidated statements of cash flows
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||
(in thousands) | 2014 | 2013 | 2014 | 2013 | ||||||||||||
(unaudited) | (unaudited) | |||||||||||||||
Cash flows from operating activities: | ||||||||||||||||
Net income | $ | 83,407 | $ | 12,543 | $ | 64,295 | $ | 49,764 | ||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||||||
Deferred income tax expense | 45,778 | 10,369 | 35,511 | 31,970 | ||||||||||||
Depletion, depreciation and amortization | 63,942 | 55,982 | 166,605 | 187,346 | ||||||||||||
Bad debt expense | — | 653 | — | 653 | ||||||||||||
Non-cash stock-based compensation, net of amount capitalized | 6,194 | 5,876 | 16,919 | 13,556 | ||||||||||||
Accretion of asset retirement obligations | 442 | 350 | 1,279 | 1,154 | ||||||||||||
Mark-to-market on derivatives: | ||||||||||||||||
(Gain) loss on derivatives, net | (92,790 | ) | 9,838 | 1,447 | 2,732 | |||||||||||
Cash settlements received (paid) for matured derivatives, net | 4,531 | (4,069 | ) | (1,320 | ) | 588 | ||||||||||
Cash settlements received for early terminations of derivatives, net | — | 5,366 | 76,660 | 5,366 | ||||||||||||
Change in net present value of deferred premiums paid for derivatives | 50 | 102 | 170 | 384 | ||||||||||||
Cash premiums paid for derivatives | (1,820 | ) | (2,671 | ) | (5,599 | ) | (7,920 | ) | ||||||||
Amortization of deferred loan costs | 1,311 | 1,278 | 3,823 | 3,905 | ||||||||||||
Write-off of deferred loan costs | — | 1,502 | 124 | 1,502 | ||||||||||||
Other | 2,589 | (736 | ) | 2,734 | (662 | ) | ||||||||||
Cash flows from operations before changes in working capital | 113,634 | 96,383 | 362,648 | 290,338 | ||||||||||||
Changes in working capital | 22,258 | (2,178 | ) | 10,548 | (20,420 | ) | ||||||||||
Changes in other noncurrent liabilities and fair value of performance unit awards | 345 | 2,943 | 3,140 | 5,520 | ||||||||||||
Net cash provided by operating activities | 136,237 | 97,148 | 376,336 | 275,438 | ||||||||||||
Cash flows from investing activities: | ||||||||||||||||
Capital expenditures: | ||||||||||||||||
Acquisition of oil and natural gas properties | — | (33,710 | ) | (6,493 | ) | (33,710 | ) | |||||||||
Acquisition of mineral interests | — | — | (7,305 | ) | — | |||||||||||
Oil and natural gas properties | (512,910 | ) | (162,494 | ) | (925,121 | ) | (538,395 | ) | ||||||||
Midstream service assets | (19,354 | ) | (7,092 | ) | (45,263 | ) | (15,394 | ) | ||||||||
Other fixed assets | (5,176 | ) | (5,071 | ) | (13,612 | ) | (13,874 | ) | ||||||||
Investment in equity method investee | (18,110 | ) | — | (37,581 | ) | (3,287 | ) | |||||||||
Proceeds from dispositions of capital assets, net of costs | 1,030 | 429,702 | 1,627 | 429,702 | ||||||||||||
Net cash (used) provided by investing activities | (554,520 | ) | 221,335 | (1,033,748 | ) | (174,958 | ) | |||||||||
Cash flows from financing activities: | ||||||||||||||||
Borrowings on Senior Secured Credit Facility | 75,000 | — | 75,000 | 230,000 | ||||||||||||
Payments on Senior Secured Credit Facility | — | (395,000 | ) | — | (395,000 | ) | ||||||||||
Issuance of January 2022 Notes | — | — | 450,000 | — | ||||||||||||
Proceeds from issuance of common stock, net of offering costs | — | 298,104 | — | 298,104 | ||||||||||||
Other | (463 | ) | 95 | (9,981 | ) | (1,538 | ) | |||||||||
Net cash provided (used) by financing activities | 74,537 | (96,801 | ) | 515,019 | 131,566 | |||||||||||
Net (decrease) increase in cash and cash equivalents | (343,746 | ) | 221,682 | (142,393 | ) | 232,046 | ||||||||||
Cash and cash equivalents, beginning of period | 399,506 | 43,588 | 198,153 | 33,224 | ||||||||||||
Cash and cash equivalents, end of period | $ | 55,760 | $ | 265,270 | $ | 55,760 | $ | 265,270 | ||||||||
9
Laredo Petroleum, Inc.
Selected operating data
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
(unaudited) | (unaudited) | |||||||||||||||
Sales volumes: | ||||||||||||||||
Oil (MBbl) | 1,778 | 1,282 | 4,712 | 4,127 | ||||||||||||
Natural gas (MMcf)(1) | 7,533 | 7,965 | 20,176 | 29,025 | ||||||||||||
Oil equivalents (MBOE)(2)(3) | 3,033 | 2,609 | 8,074 | 8,964 | ||||||||||||
Average daily sales volumes (BOE/D)(3) | 32,970 | 28,361 | 29,577 | 32,836 | ||||||||||||
% Oil | 59 | % | 49 | % | 58 | % | 46 | % | ||||||||
Average sales prices: | ||||||||||||||||
Oil, realized ($/Bbl)(4) | $ | 87.65 | $ | 100.62 | $ | 91.09 | $ | 90.30 | ||||||||
Natural gas, realized ($/Mcf)(4) | $ | 5.80 | $ | 5.26 | $ | 6.26 | $ | 4.79 | ||||||||
Average price, realized ($/BOE)(4) | $ | 65.78 | $ | 65.48 | $ | 68.80 | $ | 57.08 | ||||||||
Oil, hedged ($/Bbl)(5) | $ | 88.86 | $ | 94.63 | $ | 89.73 | $ | 88.05 | ||||||||
Natural gas, hedged ($/Mcf)(5) | $ | 5.87 | $ | 5.35 | $ | 6.24 | $ | 4.84 | ||||||||
Average price, hedged ($/BOE)(5) | $ | 66.66 | $ | 62.82 | $ | 67.95 | $ | 56.21 | ||||||||
Average costs per BOE sold: | ||||||||||||||||
Lease operating expenses | $ | 8.30 | $ | 7.50 | $ | 8.31 | $ | 7.16 | ||||||||
Midstream service expense | 0.40 | 0.42 | 0.45 | 0.29 | ||||||||||||
Production and ad valorem taxes | 4.14 | 4.49 | 4.73 | 3.67 | ||||||||||||
General and administrative(6) | 8.93 | 9.35 | 10.44 | 7.20 | ||||||||||||
Depletion, depreciation and amortization | 21.08 | 21.46 | 20.63 | 20.83 | ||||||||||||
Total | $ | 42.85 | $ | 43.22 | $ | 44.56 | $ | 39.15 | ||||||||
_______________________________________________________________________________
(1) | Excludes gas produced and consumed in operations of 67 MMcf and 83 MMcf for the three and nine months ended September 30, 2014, respectively. There were no comparable amounts for the three and nine months ended September 30, 2013. |
(2) | Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl. |
(3) | The volumes presented are based on actual results and are not calculated using the rounded numbers presented in the table above. |
(4) | Realized oil and natural gas prices are the actual prices realized at the wellhead after all adjustments for natural gas liquid content, quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price at the wellhead. The prices presented are based on actual results and are not calculated using the rounded numbers presented in the table above. |
(5) | Hedged prices reflect the after effect of our commodity hedging transactions on our average sales prices. Our calculation of such after effects include current period settlements of matured commodity derivatives in accordance with GAAP and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to instruments that settled in the period. The prices presented are based on actual results and are not calculated using the rounded numbers presented in the table above. |
(6) | General and administrative includes non-cash stock-based compensation, net of amount capitalized, of $6.2 million and $5.9 million for the three months ended September 30, 2014 and 2013, respectively, and $16.9 million and $13.6 million for the nine months ended September 30, 2014 and 2013, respectively. Excluding stock-based compensation, net of amount capitalized, from the above metric results in general and administrative cost per BOE sold of $6.89 and $7.10 for the three months ended September 30, 2014 and 2013, respectively, and $8.34 and $5.69 for the nine months ended September 30, 2014 and 2013, respectively. |
10
Laredo Petroleum, Inc.
Costs incurred
Costs incurred in the acquisition, exploration and development of oil and natural gas assets are presented below for the periods presented:
_______________________________________________________________________________
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||
(in thousands) | 2014 | 2013 | 2014 | 2013 | ||||||||||||
(unaudited) | (unaudited) | |||||||||||||||
Property acquisition costs: | ||||||||||||||||
Proved | $ | — | $ | 9,652 | $ | 3,873 | $ | 9,652 | ||||||||
Unproved | — | 27,087 | 9,925 | 27,087 | ||||||||||||
Exploration(1) | 200,711 | 8,317 | 217,353 | 29,245 | ||||||||||||
Development costs(2) | 325,118 | 148,877 | 733,671 | 471,609 | ||||||||||||
Total costs incurred | $ | 525,829 | $ | 193,933 | $ | 964,822 | $ | 537,593 | ||||||||
(1) | The Company acquired significant leasehold interests during the three months ended September 30, 2014. |
(2) | The costs incurred for oil and natural gas development activities include $1.6 million and $0.7 million in asset retirement obligations for the three months ended September 30, 2014 and 2013, respectively, and $3.1 million and $2.0 million for the nine months ended September 30, 2014 and 2013, respectively. |
11
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 and other performance measures prepared in accordance with GAAP, such as operating income 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 any other GAAP measure of liquidity or financial performance.
Adjusted Net Income
Adjusted Net Income is a non-GAAP financial measure used by the Company to evaluate performance, prior to impairment of long-lived assets, gains or losses on derivatives, cash settlements of matured commodity derivatives, cash settlements on early terminated commodity derivatives, gains or losses on sale of assets, write-off of deferred loan costs and bad debt expense.
The following presents a reconciliation of net income to Adjusted Net Income:
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||
(in thousands, except for per share data, unaudited) | 2014 | 2013 | 2014 | 2013 | ||||||||||||
Net income | $ | 83,407 | $ | 12,543 | $ | 64,295 | $ | 49,764 | ||||||||
Plus: | ||||||||||||||||
(Gain) loss on derivatives, net | (92,790 | ) | 9,838 | 1,447 | 2,732 | |||||||||||
Cash settlements received (paid) for matured commodity derivatives, net | 4,531 | (3,975 | ) | (1,320 | ) | 888 | ||||||||||
Cash settlements received for early terminations of commodity derivatives, net | — | 5,366 | 76,660 | 5,366 | ||||||||||||
(Gain) loss on disposal of assets, net | 2,192 | (607 | ) | 2,418 | (548 | ) | ||||||||||
Write-off of deferred loan costs | — | 1,502 | 124 | 1,502 | ||||||||||||
Bad debt expense | — | 653 | — | 653 | ||||||||||||
(2,660 | ) | 25,320 | 143,624 | 60,357 | ||||||||||||
Income tax adjustment(1) | 30,124 | (4,600 | ) | (27,765 | ) | (3,813 | ) | |||||||||
Adjusted Net Income | $ | 27,464 | $ | 20,720 | $ | 115,859 | $ | 56,544 | ||||||||
Adjusted Net Income per common share: | ||||||||||||||||
Basic | $ | 0.19 | $ | 0.15 | $ | 0.82 | $ | 0.44 | ||||||||
Diluted | $ | 0.19 | $ | 0.15 | $ | 0.81 | $ | 0.43 | ||||||||
Weighted-average common shares outstanding: | ||||||||||||||||
Basic | 141,413 | 134,461 | 141,261 | 129,701 | ||||||||||||
Diluted | 143,813 | 136,460 | 143,583 | 131,589 | ||||||||||||
(1) | The income tax adjustment is calculated by applying the estimated annual effective tax rates, without regard to discrete items, of 35% for the three and nine months ended September 30, 2014, and 36% for the three and nine months ended September 30, 2013. |
12
Adjusted EBITDA
Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss plus adjustments for interest expense, depletion, depreciation and amortization, impairment of long-lived assets, write-off of deferred loan costs, bad debt expense, gains or losses on disposal of assets, gains or losses on derivatives, cash settlements of matured commodity derivatives, cash settlements on early terminated commodity derivatives, premiums paid for derivatives that matured during the period, non-cash stock-based compensation and income tax expense or benefit. 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 if directors, 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 from continuing and discontinued operations to Adjusted EBITDA:
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||
(in thousands, unaudited) | 2014 | 2013 | 2014 | 2013 | ||||||||||||
Net income | $ | 83,407 | $ | 12,543 | $ | 64,295 | $ | 49,764 | ||||||||
Plus: | ||||||||||||||||
Interest expense | 30,549 | 24,929 | 90,192 | 76,221 | ||||||||||||
Depletion, depreciation and amortization | 63,942 | 55,982 | 166,605 | 187,346 | ||||||||||||
Write-off of deferred loan costs | — | 1,502 | 124 | 1,502 | ||||||||||||
Bad debt expense | — | 653 | — | 653 | ||||||||||||
(Gain) loss on disposal of assets, net | 2,192 | (607 | ) | 2,418 | (548 | ) | ||||||||||
(Gain) loss on derivatives, net | (92,790 | ) | 9,838 | 1,447 | 2,732 | |||||||||||
Cash settlements received (paid) for matured commodity derivatives, net | 4,531 | (3,975 | ) | (1,320 | ) | 888 | ||||||||||
Cash settlements received for early terminations of commodity derivatives, net | — | 5,366 | 76,660 | 5,366 | ||||||||||||
Premiums paid for derivatives that matured during the period(1) | (1,820 | ) | (2,925 | ) | (5,599 | ) | (8,681 | ) | ||||||||
Non-cash stock-based compensation, net of amount capitalized | 6,194 | 5,876 | 16,919 | 13,556 | ||||||||||||
Deferred income tax expense | 45,778 | 10,369 | 35,511 | 31,970 | ||||||||||||
Adjusted EBITDA | $ | 141,983 | $ | 119,551 | $ | 447,252 | $ | 360,769 | ||||||||
_______________________________________________________________________________
(1) | Reflects premiums incurred previously or upon settlement that are attributable to instruments settled in the respective periods presented. |
13