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CST: 16/07/2019 11:07:12   

Laredo Petroleum Announces 2018 Fourth-Quarter and Full-Year Financial and Operating Results

152 Days ago

TULSA, OK., Feb. 13, 2019 (GLOBE NEWSWIRE) -- Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or the "Company") today announced its 2018 fourth-quarter and full-year results. For the fourth quarter of 2018, the Company reported net income attributable to common stockholders of $149.6 million, or $0.65 per diluted share. Adjusted Net Income, a non-GAAP financial measure, for the fourth quarter of 2018 was $37.5 million, or $0.16 per adjusted diluted share. Adjusted EBITDA, a non-GAAP financial measure, for the fourth quarter of 2018, was $132.4 million.

For the year ended December 31, 2018, the Company reported net income attributable to common stockholders of $324.6 million, or $1.39 per diluted share. Adjusted Net Income for the year ended December 31, 2018 was $216.4 million, or $0.93 per adjusted diluted share, and Adjusted EBITDA was $588.9 million. Please see supplemental financial information at the end of this news release for reconciliation of the non-GAAP financial measures.

2018 Highlights

  • Produced a Company record average of 68,168 barrels of oil equivalent ("BOE") per day in full-year 2018, resulting in production growth of approximately 17% from full-year 2017
  • Grew the value of the Company's proved reserves by 19% from year-end 2017
  • Increased cash margin per BOE, a non-GAAP financial measure, to $23.85 in full-year 2018, an increase of 14% from full-year 2017
  • Reduced unit cash general and administrative ("G&A") expense by approximately 16% in full-year 2018
  • Recognized approximately $31.9 million of net cash benefits from Laredo Midstream Services, LLC ("LMS") field infrastructure investments through reduced capital and operating costs and increased revenue

"The Company's 2018 drilling program generated significant data on well spacing, furthering our subsurface understanding and driving a key strategic shift in our development plan," stated Randy A. Foutch, Chairman and Chief Executive Officer. "The resulting 2019 capital program is expected to produce a returns and capital efficiency inflection point for the Company, while also generating high-single digit production growth within operating cash flow. We have already begun to pivot our development plan to emphasize returns by moving to wider well spacing and expect a commensurate long-term improvement in well productivity. This strategic transition, coupled with our focus on controlling cash costs, is expected to position Laredo to take advantage of numerous opportunities to enhance value for our shareholders."

E&P Update

During the fourth quarter of 2018, Laredo continued the superior operational efficiency performance demonstrated in the previous three quarters of 2018. The Company completed 18 gross horizontal wells with an average completed lateral length of approximately 10,100 feet. Laredo continued to set Company records for drilling efficiency, averaging 8.3 drilling days per 10,000 feet from rig accept to rig release for wells drilled in fourth-quarter 2018. The combined benefit of these continued efficiency improvements resulted in Laredo completing 74 gross (71.2 net) horizontal wells in full-year 2018, exceeding the originally budgeted well completions expectations by approximately 14%.

Total production in fourth-quarter 2018 averaged 70,653 BOE per day, an increase of approximately 14% from the fourth quarter of 2017. Fourth-quarter 2018 oil production increased by approximately 5% from the fourth quarter of 2017. Full-year 2018 total production averaged a Company record 68,168 BOE per day, an increase of approximately 17% from full-year 2017 and exceeding initial 2018 guidance of total production growth of at least 10%. Oil production increased approximately 7% from full-year 2017, less than original 2018 oil production growth guidance of greater than 10%.

Laredo has taken action to address the reduced oil productivity experienced in 2018 that we believe was impacted by the tighter spacing of some wells drilled in 2017 and 2018. Responding to these results, the Company began widening spacing on wells spud in the first quarter of 2019. Laredo expects this shift in development strategy to drive higher returns and increased capital efficiency versus 2018, as widening spacing is anticipated to address one of the causes of higher oil decline rates.

In the first quarter of 2019, the Company expects to complete 15 gross (14.8 net) horizontal wells with an average completed lateral length of approximately 11,300 feet, all developed with Laredo's previous tight-spacing plan. The five remaining tightly-spaced wells are expected to be completed early in the second quarter of 2019. In the later part of the second quarter of 2019, the Company expects to begin completing wells that were developed on Laredo's wider-spaced development strategy that is expected to result in improved returns and capital efficiency versus 2018.

Throughout 2018, the Company maintained a strong focus on controllable cash costs, reducing combined unit lease operating expenses ("LOE") and unit cash G&A expense approximately 5% to $6.07 per BOE for full-year 2018 versus $6.38 per BOE for full-year 2017. Laredo's prior strategic investments in field infrastructure continue to drive unit operational costs that are among the lowest in the Midland Basin, reducing unit LOE by an estimated $0.55 per BOE in the fourth quarter of 2018 to $3.51 per BOE. Additionally, Laredo's management team held the line on total G&A expense, reducing total cash G&A by approximately 1% compared to 2017.

2018 Capital Program

During the fourth quarter of 2018, the Company invested approximately $132 million in exploration and development activities. Other expenditures incurred during the quarter included approximately $2 million in bolt-on leasing, lease extensions and data, approximately $5 million in infrastructure, including LMS investments, and approximately $9 million in other capitalized costs. Additionally, the Company completed property acquisitions of approximately $1 million that were not previously budgeted.

For full-year 2018, Laredo invested approximately $575 million in exploration and development activities. Other expenditures incurred during the year included approximately $12 million in bolt-on leasing, lease extensions and data, approximately $23 million in infrastructure, including LMS investments, and approximately $34 million in other capitalized costs. Additionally, the Company completed property acquisitions of approximately $17 million that were not previously budgeted.

2019 Capital Program

Laredo expects 2019 to be a transitional year as the Company tailors operational cadence and corporate cost structure, including G&A expense, to balance capital expenditures and cash flow from operations. The evolution of Laredo’s development plan to focus on more widely spaced wells is expected to drive long-term capital efficiency improvements and higher returns versus 2018 results, enabling Laredo to hold oil production relatively flat within cash flow in 2020 compared to 2019’s exit rate.

Responding to the current commodity price environment of WTI strip pricing of approximately $54 per barrel, Laredo expects to invest approximately $365 million in 2019, excluding non-budgeted acquisitions. This budget includes approximately $300 million for drilling and completion activities and approximately $65 million for production facilities, land and other capitalized costs. Laredo anticipates adjusting capital spending levels to match operating cash flow if operating cash flow does not meet budgeted expectations. Should operating cash flow exceed budget expectations, free cash flow could be used to complete additional wells, repurchase stock or pay down debt.

By the third quarter of 2019, enabled by the Company’s operational flexibility, Laredo anticipates reducing activity from the current three horizontal rigs and two completion crews to operating one horizontal rig and utilizing a single completion crew, as needed. The front-loaded completion schedule and disciplined reduction in activity should drive free cash flow generation in the second half of 2019 that is expected to balance capital expenditures with cash flow from operations for full-year 2019.

The Company's 2019 budget is underpinned by a robust hedge position. Approximately 90% of 2019 forecasted oil production is hedged with a combination of puts and swaps at a weighted-average floor price of approximately $48 per barrel. Importantly, Laredo retains unlimited upside to oil prices on almost all of the Company's oil hedges since puts have no price ceiling.

Total production for 2019 is expected to grow approximately 9% versus full-year 2018 and oil production is expected to decline approximately 5% versus 2018. The Company expects to replace both total and oil production organically through development drilling in 2019. Under current conditions, beyond 2019, Laredo expects to hold annual oil production relatively flat within cash flow, compared to a fourth-quarter 2019 exit rate of approximately 23.0 MBOPD. Additionally, the Company's future corporate oil decline rates are expected to be lower, commensurate with reduced activity levels and wider well spacing, improving future capital efficiency.

Reserves

Beginning with the first horizontal well Laredo drilled in the Midland Basin in 2008, the Company's primary goal has been the execution of the most efficient and value-enhancing development program for its acreage position. Laredo fully embraced the challenge of replicating stand-alone well performance in tighter-spaced, full-field development, minimizing parent-child performance degradation and maximizing premium well inventory. Utilizing extensive pre-drill forward modeling that integrated Laredo's broad dataset and third-party technologies, the Company began drilling a majority of its wells in dense, multi-zone packages in mid-2017.

In general, production performance for tighter-spaced packages was very encouraging for the first year, but subsequent data began to exhibit more rapid oil decline rates than anticipated, leading to longer-term results that underperformed expectations, primarily related to the tighter spacing. Additionally, as wells were more tightly spaced in 2018, oil declines became evident earlier in the wells’ life than more widely spaced wells.

For the Company's year-end 2018 reserves estimation, Laredo incorporated additional production data to reflect the higher natural gas content and steeper oil declines on its historical wells and the related negative impact on oil production from tighter well spacing during the last two years. These process enhancements have led to more specific forecasts for estimated reserves as the Company takes into account well spacing's impact on estimated oil reserves.

The value of Laredo’s proved reserves increased to approximately $2.1 billion at year-end 2018, an increase of approximately 19% from year-end 2017. Total proved reserve volumes increased by approximately 10% to 238 MMBOE, including an approximately 13% increase in proved developed reserves to 217 MMBOE and increasing proved developed reserves to 91% of total proved reserves. Proved oil reserves decreased by approximately 22%, driven primarily by longer-term performance revisions associated with tighter well spacing.

Changes in total proved reserves for 2018 are summarized in the following table:

    Year ended December 31, 2018
    Oil
(MMBbl)
  NGL
(MMBbl)
  Natural gas
(Bcf)
  Oil equivalents(1)
 (MMBOE)
Beginning of year   79.4     67.4     414.6     215.9  
Revisions of previous estimates   (20.9 )   11.1     72.0     2.2  
Extensions, discoveries and other additions   13.3     15.1     93.8     44.1  
Acquisitions and divestitures of reserves, net   0.2     0.3     2.1     0.9  
Production   (10.2 )   (7.3 )   (44.7 )   (24.9 )
End of year(1)   61.9     86.6     537.8     238.2  
 
Standardized measure of discounted future net cash flows, end of year - ($ millions)   $ 2,114  

_______________________________________________________________________________

(1) Figures may not add due to rounding.

The most recent results from tighter well spacing have been incorporated into year-end 2018 proved reserves and Laredo believes that the shift in future development to wider spacing will mitigate the negative impact to oil production seen in tightly spaced wells. Expectations for future drilling, which take into account all landing points and both horizontal and vertical spacing and the related interference, are reflected in Laredo’s updated type curve for Upper/Middle Wolfcamp 10,000-foot lateral horizontal wells. Total production expectations for the updated type curve are 1.3 MMBOE for the life of the well, comprised of approximately 31% oil, with more than 50% of expected oil production recovered in the first five years of production.

Rate of return expectations for the Company's updated type curve are commensurate with those for the previous type curve. Increased expectations for natural gas and natural gas liquids recoveries early in the life of well offset reduced expectations for oil recoveries late in the life of the well. Further, estimated ultimate recovery for oil reflected in the Company's updated type curve is approximately 55% higher than current expectations for tightly spaced wells drilled in 2017 and 2018.

Liquidity

At December 31, 2018, the Company had cash and cash equivalents of approximately $45 million and available capacity under the senior secured credit facility of $995 million. At February 12, 2019, the Company had cash and cash equivalents of approximately $30 million and available capacity under the senior secured credit facility of $945 million, resulting in total liquidity of approximately $975 million.

Commodity Derivatives

Laredo maintains a disciplined hedging program to reduce the variability in its anticipated cash flow due to fluctuations in commodity prices. The Company utilizes a combination of puts, swaps and collars, entering into hedges solely with banks that are part of its senior secured credit facility. Laredo currently has hedges in place for approximately 90% of anticipated oil production in 2019 and has oil hedges in place through 2021. The Company has also entered into NGL hedges through 2021, natural gas hedges through 2019 and various product basis hedges through 2021. Details of the Company's hedge positions are included in the current Corporate Presentation available on the Company's website at www.laredopetro.com.

Guidance

The Company anticipates total production growth of approximately 9% and an oil production decline of approximately 5% for full-year 2019 as compared to full-year 2018. The table below reflects the Company's guidance for the first quarter of 2019.

  1Q-2019E
Total production (MBOE/d) 74.0
Oil production (MBO/d) 27.5
   
Average sales price realizations (without derivatives):  
Oil (% of WTI) 90%
NGL (% of WTI) 24%
Natural gas (% of Henry Hub) 34%
   
Operating costs & expenses:  
Lease operating expenses ($/BOE) $3.50
Production and ad valorem taxes (% of oil, NGL and natural gas revenues) 6.50%
Transportation and marketing expenses ($/BOE) $0.80
Midstream service expenses ($/BOE) $0.15
General and administrative:  
Cash ($/BOE) $2.25
Non-cash stock-based compensation, net ($/BOE) $1.25
Depletion, depreciation and amortization ($/BOE) $9.30

Fourth-Quarter and Full-Year 2018 Earnings Conference Call

Laredo will host a conference call on Thursday, February 14, 2019 at 7:30 a.m. CT (8:30 a.m. ET) to discuss its fourth-quarter and full-year 2018 financial and operating results and management's outlook. Individuals who would like to participate on the call should dial 877.930.8286 (international dial-in 253.336.8309), using conference code 9775779, or listen to the call via the Company's website at www.laredopetro.com, under the tab for "Investor Relations." A telephonic replay will be available approximately two hours after the call on February 14, 2019 through Thursday, February 21, 2019. Participants may access this replay by dialing 855.859.2056, using conference code 9775779.

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 midstream and marketing services, 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, including, but not limited to, the share repurchase program, which may be suspended or discontinued by the Company at any time, 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, 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, 2017, and those set forth from time to time in other filings with the Securities Exchange Commission ("SEC") including, but not limited to, its Annual Report on Form 10-K for the year ended December 31, 2018, to be filed with the 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," "type curve," 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, natural gas liquids 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 resources 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. "Type curve" refers to a production profile of a well, or a particular category of wells, for a specific play and/or area. 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. The "standardized measure" of discounted future new cash flows is calculated in accordance with SEC regulations and a discount rate of 10%. The actual results may vary considerably and should not be considered to represent the fair market value of the Company’s proved reserves.


Laredo Petroleum, Inc.
Condensed consolidated statements of operations

    Three months ended December 31,   Year ended December 31,
(in thousands, except per share data)   2018   2017   2018   2017
         
    (unaudited)   (unaudited)
Revenues:                
Oil, NGL and natural gas sales   $ 176,671     $ 183,376     $ 808,530     $ 621,507  
Midstream service revenues   2,397     2,369     8,987     10,517  
Sales of purchased oil   36,219     54,592     288,258     190,138  
Total revenues   215,287     240,337     1,105,775     822,162  
Costs and expenses:                
Lease operating expenses   22,823     18,359     91,289     75,049  
Production and ad valorem taxes   11,225     10,991     49,457     37,802  
Transportation and marketing expenses   5,134         11,704      
Midstream service expenses   1,048     1,113     2,872     4,099  
Costs of purchased oil   36,222     54,247     288,674     195,908  
General and administrative   21,182     23,707     96,138     96,312  
Depletion, depreciation and amortization   60,399     45,062     212,677     158,389  
Other operating expenses   1,131     1,025     4,472     4,931  
Total costs and expenses   159,164     154,504     757,283     572,490  
Operating income   56,123     85,833     348,492     249,672  
Non-operating income (expense):                
Gain (loss) on derivatives, net   112,195     (37,777 )   42,984     350  
Interest expense   (15,117 )   (19,787 )   (57,904 )   (89,377 )
Income from equity method investee(1)       575         8,485  
Gain on sale of investment in equity method investee(1)       405,906         405,906  
Loss on early redemption of debt       (23,761 )       (23,761 )
Other, net   (766 )   (628 )   (4,728 )   (501 )
Non-operating income (expense), net   96,312     324,528     (19,648 )   301,102  
Income before income taxes   152,435     410,361     328,844     550,774  
Income tax benefit (expense):                
Current   426     (1,800 )   807     (1,800 )
Deferred   (3,288 )       (5,056 )    
Total income tax expense   (2,862 )   (1,800 )   (4,249 )   (1,800 )
Net income   $ 149,573     $ 408,561     $ 324,595     $ 548,974  
Net income per common share:                
Basic   $ 0.65     $ 1.71     $ 1.40     $ 2.30  
Diluted   $ 0.65     $ 1.70     $ 1.39     $ 2.29  
Weighted-average common shares outstanding:                
Basic   229,700     239,332     232,339     239,096  
Diluted   230,190     240,289     233,172     240,122  

_______________________________________________________________________________

(1)  On October 30, 2017, LMS, together with Medallion Midstream Holdings, LLC, which is owned and controlled by an affiliate of the third-party interest holder, The Energy & Minerals Group, completed the sale of 100% of the ownership interests in Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, which, together with its wholly-owned subsidiaries (collectively, "Medallion"), to an affiliate of Global Infrastructure Partners ("GIP"), for cash consideration of $1.825 billion (the "Medallion Sale"). LMS' net cash proceeds for its 49% ownership interest in Medallion in 2017 were $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. On February 1, 2018, closing adjustments were finalized and LMS received additional net cash of $1.7 million for total net cash proceeds before taxes of $831.3 million. 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.


Laredo Petroleum, Inc.
Condensed consolidated statements of cash flows

    Three months ended December 31,   Year ended December 31,
(in thousands)   2018   2017   2018   2017
         
    (unaudited)   (unaudited)
Cash flows from operating activities:                
Net income   $ 149,573     $ 408,561     $ 324,595     $ 548,974  
Adjustments to reconcile net income to net cash provided by operating activities:                
Deferred income tax expense   3,288         5,056      
Depletion, depreciation and amortization   60,399     45,062     212,677     158,389  
Gain on sale of investment in equity method investee(1)       (405,906 )       (405,906 )
Loss on early redemption of debt       23,761         23,761  
Non-cash stock-based compensation, net   7,648     8,857     36,396     35,734  
Mark-to-market on derivatives:                
(Gain) loss on derivatives, net   (112,195 )   37,777     (42,984 )   (350 )
Settlements received for matured derivatives, net   12,033     2,792     6,090     37,583  
Settlements received for early terminations of derivatives, net               4,234  
Premiums paid for derivatives   (5,405 )   (12,311 )   (20,335 )   (25,853 )
Other, net(1)   3,544     3,196     15,882     2,062  
Cash flows from operations before changes in assets and liabilities   118,885     111,789     537,377     378,628  
Decrease (increase) in current assets and liabilities, net   10,842     (3,340 )   1,157     2,239  
(Increase) decrease in noncurrent assets and liabilities, net   (451 )   4,414     (730 )   4,047  
  Net cash provided by operating activities   129,276     112,863     537,804     384,914  
Cash flows from investing activities:                
Deposit utilized for sale of oil and natural gas properties       (3,000 )       (3,000 )
Acquisitions of oil and natural gas properties   (1,198 )       (17,538 )    
Capital expenditures:                
Oil and natural gas properties   (151,114 )   (156,957 )   (673,584 )   (538,122 )
Midstream service assets   (1,020 )   (9,207 )   (6,784 )   (20,887 )
Other fixed assets   (1,363 )   (1,301 )   (7,308 )   (4,905 )
Investment in equity method investee(1)       (7,236 )       (31,808 )
Proceeds from disposition of equity method investee, net of selling costs(1)       829,615     1,655     829,615  
Proceeds from dispositions of capital assets, net of selling costs   170     29     12,603     64,157  
  Net cash (used in) provided by investing activities   (154,525 )   651,943     (690,956 )   295,050  
Cash flows from financing activities:                
Borrowings on Senior Secured Credit Facility   20,000     35,000     210,000     190,000  
Payments on Senior Secured Credit Facility       (190,000 )   (20,000 )   (260,000 )
Early redemption of debt       (518,480 )       (518,480 )
Share repurchases           (97,055 )    
Other, net   (7 )   15     (6,801 )   (11,997 )
  Net cash provided (used in) by financing activities   19,993     (673,465 )   86,144     (600,477 )
Net (decrease) increase in cash and cash equivalents   (5,256 )   91,341     (67,008 )   79,487  
Cash and cash equivalents, beginning of period   50,407     20,818     112,159     32,672  
Cash and cash equivalents, end of period   $ 45,151     $ 112,159     $ 45,151     $ 112,159  

_______________________________________________________________________________

(1) See footnote 1 to the condensed consolidated statements of operations.

Laredo Petroleum, Inc.
Selected operating data

    Three months ended December 31,   Year ended December 31,
    2018   2017   2018   2017
         
    (unaudited)   (unaudited)
Sales volumes:                
Oil (MBbl)   2,571     2,448     10,175     9,475  
NGL (MBbl)   1,931     1,613     7,259     5,800  
Natural gas (MMcf)   11,983     9,818     44,680     35,972  
Oil equivalents (MBOE)(1)(2)   6,500     5,697     24,881     21,270  
Average daily sales volumes (BOE/D)(2)   70,653     61,922     68,168     58,273  
% Oil(2)   40 %   43 %   41 %   45 %
Average sales Realized Prices(2):                
Oil, without derivatives ($/Bbl)(3)   $ 52.59     $ 53.57     $ 59.48     $ 46.97  
NGL, without derivatives ($/Bbl)(3)   $ 17.53     $ 20.53     $ 20.64     $ 17.49  
Natural gas, without derivatives ($/Mcf)(3)   $ 0.63     $ 1.95     $ 1.20     $ 2.09  
Average price, without derivatives ($/BOE)(3)   $ 27.18     $ 32.19     $ 32.50     $ 29.22  
Oil, with derivatives ($/Bbl)(4)   $ 49.55     $ 54.38     $ 55.49     $ 50.45  
NGL, with derivatives ($/Bbl)(4)   $ 17.47     $ 19.53     $ 20.03     $ 16.91  
Natural gas, with derivatives ($/Mcf)(4)   $ 1.74     $ 2.08     $ 1.77     $ 2.15  
Average price, with derivatives ($/BOE)(4)   $ 28.01     $ 32.48     $ 31.72     $ 30.71  
Average costs and expenses per BOE sold(2):                
Lease operating expenses   $ 3.51     $ 3.22     $ 3.67     $ 3.53  
Production and ad valorem taxes   1.73     1.93     1.99     1.78  
Transportation and marketing expenses   0.79         0.47      
Midstream service expenses   0.16     0.20     0.12     0.19  
General and administrative:                
Cash   2.08     2.61     2.40     2.85  
Non-cash stock-based compensation, net   1.18     1.55     1.46     1.68  
Depletion, depreciation and amortization   9.29     7.91     8.55     7.45  
Total costs and expenses   $ 18.74     $ 17.42     $ 18.66     $ 17.48  
Cash margins per BOE(2)(5):                
Realized   $ 18.91     $ 24.23     $ 23.85     $ 20.87  
Hedged   $ 19.74     $ 24.52     $ 23.07     $ 22.36  

_______________________________________________________________________________

(1) BOE is calculated using a conversion rate of six Mcf per one Bbl.
(2) The numbers 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 received when control passes to the purchaser/customer adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
(4) Price reflects the after-effects of our derivative transactions on our average sales Realized Prices. Our calculation of such after-effects includes settlements of matured derivatives during the respective periods in accordance with GAAP and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to derivatives that settled during the respective periods.
(5) On a per BOE basis, cash margins are calculated as average price less, (i) lease operating expenses, (ii) production and ad valorem taxes, (iii) transportation and marketing expenses, (iv) midstream service expenses and (v) cash general and administrative.

Laredo Petroleum, Inc.
Costs incurred

The following table presents costs incurred in the acquisition, exploration and development of oil and natural gas properties, with asset retirement obligations included in evaluated property acquisition costs and development costs, for the periods presented:

    Three months ended December 31,   Year ended December 31,
(in thousands)   2018   2017   2018   2017
         
    (unaudited)   (unaudited)
Property acquisition costs:                
Evaluated   $ 1,225     $     $ 15,072     $  
Unevaluated           2,790      
Exploration costs   5,137     7,920     23,884     36,257  
Development costs   140,208     163,664     607,790     560,919  
Total costs incurred   $ 146,570     $ 171,584     $ 649,536     $ 597,176  
                                 

Laredo Petroleum, Inc.
Supplemental reconciliations 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 flows from operating activities. Adjusted Net Income, Adjusted EBITDA and proved developed Finding and Development Cost should not be considered in isolation or as a substitute for GAAP measures, such as net income or loss, operating income or loss, standardized measure of discounted future net cash flows 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 income tax taxes, mark-to-market on derivatives, premiums paid for derivatives, gains or losses on disposal of assets 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.

The following table presents a reconciliation of income before income taxes (GAAP) to Adjusted Net Income (non-GAAP):

    Three months ended December 31,   Year ended December 31,
(in thousands, except for per share data, unaudited)   2018   2017   2018   2017
Income before income taxes   $ 152,435     $ 410,361     $ 328,844     $ 550,774  
Plus:                
Mark-to-market on derivatives:                
(Gain) loss on derivatives, net   (112,195 )   37,777     (42,984 )   (350 )
Settlements received for matured derivatives, net   12,033     2,792     6,090     37,583  
Settlements received for early terminations of derivatives, net               4,234  
Premiums paid for derivatives   (5,405 )   (12,311 )   (20,335 )   (25,853 )
Gain on sale of investment in equity method investee(1)       (405,906 )       (405,906 )
Loss on disposal of assets, net   1,207     906     5,798     1,306  
Loss on early redemption of debt       23,761         23,761  
Adjusted net income before adjusted income tax expense   48,075     57,380     277,413     185,549  
Adjusted income tax expense(2)   (10,577 )   (12,624 )   (61,031 )   (40,821 )
Adjusted Net Income   $ 37,498     $ 44,756     $ 216,382     $ 144,728  
Net income per common share:                
Basic   $ 0.65     $ 1.71     $ 1.40     $ 2.30  
Diluted   $ 0.65     $ 1.70     $ 1.39     $ 2.29  
Adjusted Net Income per common share:                
Basic   $ 0.16     $ 0.19     $ 0.93     $ 0.61  
Diluted   $ 0.16     $ 0.19     $ 0.93     $ 0.60  
Weighted-average common shares outstanding:                
Basic   229,700     239,332     232,339     239,096  
Diluted   230,190     240,289     233,172     240,122  

_______________________________________________________________________________

(1) See footnote 1 to the condensed consolidated statements of operations.
(2) Adjusted income tax expense is calculated by applying a statutory tax rate of 22% for the each of the periods ended December 31, 2018 and 2017.

Adjusted EBITDA (Unaudited)

Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss plus adjustments for income tax expense or benefit, depletion, depreciation and amortization, non-cash stock-based compensation, net, accretion expense, mark-to-market on derivatives, premiums paid for derivatives, interest expense, gains or losses on disposal of assets, income or loss from equity method investee, proportionate Adjusted EBITDA of our 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, 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, the 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 table presents a reconciliation of net income (GAAP) to Adjusted EBITDA (non-GAAP):        

    Three months ended December 31,   Year ended December 31,
(in thousands, unaudited)   2018   2017   2018   2017
Net income   $ 149,573     $ 408,561     $ 324,595     $ 548,974  
Plus:                
Income tax expense   2,862     1,800     4,249     1,800  
Depletion, depreciation and amortization   60,399     45,062     212,677     158,389  
Non-cash stock-based compensation, net   7,648     8,857     36,396     35,734  
Accretion expense   1,131     969     4,472     3,791  
Mark-to-market on derivatives:                
(Gain) loss on derivatives, net   (112,195 )   37,777     (42,984 )   (350 )
Settlements received for matured derivatives, net   12,033     2,792     6,090     37,583  
Settlements received for early terminations of derivatives, net               4,234  
Premiums paid for derivatives   (5,405 )   (12,311 )   (20,335 )   (25,853 )
Interest expense   15,117     19,787     57,904     89,377  
Gain on sale of investment in equity method investee(1)       (405,906 )       (405,906 )
Loss on disposal of assets, net   1,207     906     5,798     1,306  
Loss on early redemption of debt       23,761         23,761  
Income from equity method investee(1)       (575 )       (8,485 )
Proportionate Adjusted EBITDA of equity method investee(1)(2)       2,326         22,081  
Adjusted EBITDA   $ 132,370     $ 133,806     $ 588,862     $ 486,436  

_______________________________________________________________________________

(1) See footnote 1 to the condensed consolidated statements of operations.
(2) Proportionate Adjusted EBITDA of Medallion, our equity method investee until its sale on October 30, 2017, is calculated as follows:

    Three months ended December 31,   Year ended December 31,
(in thousands, unaudited)   2018   2017   2018   2017
Income from equity method investee   $     $ 575     $     $ 8,485  
Adjusted for proportionate share of depreciation and amortization       1,751         13,596  
Proportionate Adjusted EBITDA of equity method investee   $     $ 2,326     $     $ 22,081  


Contacts:
Ron Hagood:  (918) 858-5504 - RHagood@laredopetro.com

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