Press Release
Laredo Petroleum Announces 2018 Fourth-Quarter and Full-Year Financial and Operating Results
For the year ended
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 fromLaredo 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
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
2018 Capital Program
During the fourth quarter of 2018, the Company invested approximately
For full-year 2018, Laredo invested approximately
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
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
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
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
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
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
About Laredo
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
The
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
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.
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.
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 | ||||||||
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 |
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(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
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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Source: Laredo Petroleum, Inc.