Press Release
Laredo Petroleum Announces 2018 First-Quarter Financial and Operating Results
2018 First-Quarter Highlights
- Produced a Company record 63,314 barrels of oil equivalent ("BOE") per day and increased anticipated production growth for full-year 2018 to greater than 12%
- Reduced unit cash costs to
$8.74 per BOE, a decrease of approximately 4% from the first quarter of 2017
- Increased Adjusted EBITDA to
$143.4 million , up 33% from the first quarter of 2017
- Repurchased 6,727,901 shares of common stock at a weighted-average price of
$8.69 per share for$58.5 million under the Company's share repurchase program
"Operational results in the first quarter were in-line with expectations as we overcame delays from adverse weather at the beginning of the quarter," stated
"We are increasing our production expectations for 2018 as our work to optimize contract areas on our contiguous acreage is increasing both the working interest and lateral lengths of our wells. Additionally, the longer-term results from well packages designed to test tighter spacing are encouraging. We are aggressively moving forward with our development utilizing 32 Upper/Middle Wolfcamp wells per drilling spacing unit which, coupled with shorter cycle times and an accelerated pace of drilling, is expected to drive improved capital efficiency. We now anticipate adding a fifth horizontal drilling rig around the end of 2018 or beginning of 2019."
E&P Update
In the first quarter of 2018, Laredo produced a Company record 63,314 BOE per day, completing 20 gross (20 net) horizontal wells with an average completed lateral length of approximately 9,700 feet. The number of completions in first-quarter 2018 was positively impacted by shortened cycle times, reflecting efficiency improvements related to contracting a second dedicated completions crew and completion design modifications.
Laredo continued to utilize various completion designs during the first quarter with the goal of improving productivity, reducing capital costs and driving improved capital efficiency. Design refinements included lengthening stages, reducing fluid concentrations and utilizing PerfExtra, the
Unit lease operating expenses ("LOE") were
Laredo expects to complete 17 gross horizontal wells (16.5 net) in the second quarter of 2018 with an average completed lateral length of approximately 10,800 feet. Eleven of these wells are being developed as a package and are not expected to begin flowback until the end of second-quarter 2018. The Company is currently operating three horizontal drilling rigs and is in the process of adding a fourth rig at the beginning of the third quarter. Laredo also expects to add a fifth horizontal rig around the end of 2018 or beginning of 2019 as completion efficiency gains and the current commodity price environment drive increasing operating cash flow.
The Company expects average completed lateral length to increase throughout 2018. Laredo's first three 15,000-foot horizontal wells have continued to improve since they were completed in the third quarter of 2017 and their average cumulative production is now performing in-line with the Company's Upper/Middle Wolfcamp type curve, adjusted for their lateral length. Laredo's contiguous acreage currently supports more than 500 land-ready Upper/Middle Wolfcamp locations of at least 15,000 feet.
Positive results from previously drilled co-developed packages support Laredo's transition to a 32 Upper/Middle Wolfcamp wells per drilling spacing unit ("DSU") development plan. The Sugg-A 157/158 five-well package, developed on 32 Upper/Middle Wolfcamp wells per DSU spacing and completed in the second and third quarters of 2017, is performing above type curve after approximately nine months. The nine-well
The Company is increasing its anticipated full-year 2018 total production growth guidance to greater than 12% and reiterating previously-issued oil production growth guidance of greater than 10% as compared to 2017. Quarterly production growth is expected to be uneven as three packages of at least eight wells are scheduled to be brought on production throughout the last seven months of 2018.
Crude Marketing
Laredo crude marketing has focused on achieving the ability to sell crude in multiple markets and protecting the Company's oil pricing from basin differentials. The Company entered into a crude oil purchase agreement with
As previously reported, on
Although not reflective of the total damages caused by Shell's wrongful termination, the estimated current net impact to Laredo's crude oil price realization as a result of the Shell breach is the reduction of aggregate second-quarter 2018 forecasted crude oil price realizations from 95% of West Texas Intermediate ("WTI") to 91% of WTI. The Company estimates that approximately 70% of its anticipated crude oil production for the remainder of 2018 is still protected from the
Further discussion regarding the litigation will be included in the Company's Quarterly Report on Form 10-Q.
Natural Gas Marketing
The Company, through
In addition to the Company's focus on field-level flow assurance, Laredo makes substantial efforts to protect anticipated cash flows generated from the sales of the Company's produced natural gas. For 2018, the Company has hedged approximately 75% of anticipated natural gas production to protect from a widening Waha basis. For the second quarter of 2018, resulting from a severe widening of the Waha basis, Laredo anticipates the Company's realized price for natural gas will be approximately 36% of Henry Hub. If the Company's natural gas hedges and basis swaps were included in realized pricing, the anticipated realized price would rise to 62% of Henry Hub.
2018 Capital Program
During the first quarter of 2018, Laredo invested approximately
The Company's expected working interest and lateral length for wells completed in 2018 has increased from original budget expectations to approximately 95% and 10,600 feet, respectively. Additionally, delayed implementation of in-basin sand is impacting well costs. Including these new expectations, drilling and completion capital for 2018 is expected to increase
Liquidity
At
On
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 contracts 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 2018 and has oil hedges through 2020. Laredo has also entered into NGL and natural gas hedges through 2018 and basis hedges through 2020. 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 is increasing its anticipated full-year 2018 total production growth guidance to greater than 12% and reiterating previously issued oil production growth guidance of greater than 10% as compared to 2017. The table below reflects the Company's guidance for the second quarter of 2018.
2Q-2018E | |||
Total production (MBOE/d) | 64.0 | ||
Oil production (MBO/d) | 27.4 | ||
Price Realizations (pre-hedge): | |||
Crude oil (% of WTI) | 91% | ||
Natural gas liquids (% of WTI) | 28% | ||
Natural gas (% of Henry Hub) | 36% | ||
Operating Costs & Expenses: | |||
Lease operating expenses ($/BOE) | $ 3.70 | ||
Midstream expenses ($/BOE) | $ 0.15 | ||
Production and ad valorem taxes (% of oil, NGL and natural gas revenue) | 6.25% | ||
General and administrative expenses: | |||
Cash ($/BOE) | $ 2.70 | ||
Non-cash stock-based compensation ($/BOE) | $ 1.85 | ||
Depletion, depreciation and amortization ($/BOE) | $ 8.00 | ||
Conference Call Details
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 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, the suspension or discontinuance of share repurchases at any time 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 March 31, | ||||||||
(in thousands, except per share data) | 2018 | 2017 | ||||||
(unaudited) | ||||||||
Revenues: | ||||||||
Oil, NGL and natural gas sales | $ | 197,434 | $ | 138,736 | ||||
Midstream service revenues | 2,359 | 2,999 | ||||||
Sales of purchased oil | 59,903 | 47,271 | ||||||
Total revenues | 259,696 | 189,006 | ||||||
Costs and expenses: | ||||||||
Lease operating expenses | 21,951 | 16,992 | ||||||
Production and ad valorem taxes | 11,812 | 8,781 | ||||||
Midstream service expenses | 693 | 916 | ||||||
Costs of purchased oil | 60,664 | 50,256 | ||||||
General and administrative | 24,725 | 25,597 | ||||||
Depletion, depreciation and amortization | 45,553 | 34,112 | ||||||
Other operating expenses | 1,106 | 1,026 | ||||||
Total costs and expenses | 166,504 | 137,680 | ||||||
Operating income | 93,192 | 51,326 | ||||||
Non-operating income (expense): | ||||||||
Gain on derivatives, net | 9,010 | 36,671 | ||||||
Income from equity method investee(1) | — | 3,068 | ||||||
Interest expense | (13,518 | ) | (22,720 | ) | ||||
Other, net | (2,164 | ) | (69 | ) | ||||
Non-operating income (expense), net | (6,672 | ) | 16,950 | |||||
Income before income taxes | 86,520 | 68,276 | ||||||
Income tax: | ||||||||
Deferred | — | — | ||||||
Total income tax | — | — | ||||||
Net income | $ | 86,520 | $ | 68,276 | ||||
Net income per common share: | ||||||||
Basic | $ | 0.36 | $ | 0.29 | ||||
Diluted | $ | 0.36 | $ | 0.28 | ||||
Weighted-average common shares outstanding: | ||||||||
Basic | 238,228 | 238,505 | ||||||
Diluted | 239,319 | 244,379 |
____________________________________________________________ | |
(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. |
Condensed consolidated balance sheets
(in thousands) | March 31, 2018 | December 31, 2017 | ||||||
(unaudited) | ||||||||
Assets: | ||||||||
Current assets | $ | 185,193 | $ | 235,382 | ||||
Property and equipment, net | 1,882,249 | 1,768,385 | ||||||
Noncurrent assets | 20,089 | 19,522 | ||||||
Total assets | $ | 2,087,531 | $ | 2,023,289 | ||||
Liabilities and stockholders' equity: | ||||||||
Current liabilities | $ | 239,666 | $ | 277,419 | ||||
Long-term debt, net | 847,300 | 791,855 | ||||||
Noncurrent liabilities | 58,735 | 188,436 | ||||||
Stockholders' equity | 941,830 | 765,579 | ||||||
Total liabilities and stockholders' equity | $ | 2,087,531 | $ | 2,023,289 | ||||
Condensed consolidated statements of cash flows
Three months ended March 31, | ||||||||
(in thousands) | 2018 | 2017 | ||||||
(unaudited) | ||||||||
Cash flows from operating activities: | ||||||||
Net income | $ | 86,520 | $ | 68,276 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Depletion, depreciation and amortization | 45,553 | 34,112 | ||||||
Non-cash stock-based compensation, net | 9,339 | 9,224 | ||||||
Mark-to-market on derivatives: | ||||||||
Gain on derivatives, net | (9,010 | ) | (36,671 | ) | ||||
Settlements (paid) received for matured derivatives, net | (2,236 | ) | 7,451 | |||||
Premiums paid for derivatives | (4,024 | ) | (2,107 | ) | ||||
Other, net(1) | 5,308 | (762 | ) | |||||
Cash flows from operations before changes in assets and liabilities | 131,450 | 79,523 | ||||||
Decrease (increase) in current assets and liabilities, net | 15,495 | (15,695 | ) | |||||
Increase in other noncurrent assets and liabilities, net | (474 | ) | (44 | ) | ||||
Net cash provided by operating activities | 146,471 | 63,784 | ||||||
Cash flows from investing activities: | ||||||||
Capital expenditures: | ||||||||
Oil and natural gas properties | (195,025 | ) | (110,542 | ) | ||||
Midstream service assets | (3,362 | ) | (1,731 | ) | ||||
Other fixed assets | (3,963 | ) | (1,203 | ) | ||||
Proceeds from disposition of equity method investee, net of selling costs(1) | 1,655 | — | ||||||
Proceeds from dispositions of capital assets, net of selling costs | 1,021 | 59,515 | ||||||
Net cash used in investing activities | (199,674 | ) | (53,961 | ) | ||||
Cash flows from financing activities: | ||||||||
Borrowings on Senior Secured Credit Facility | 55,000 | 50,000 | ||||||
Payments on Senior Secured Credit Facility | — | (55,000 | ) | |||||
Share repurchases | (53,714 | ) | — | |||||
Other, net | (4,353 | ) | (7,143 | ) | ||||
Net cash used in financing activities | (3,067 | ) | (12,143 | ) | ||||
Net decrease in cash and cash equivalents | (56,270 | ) | (2,320 | ) | ||||
Cash and cash equivalents, beginning of period | 112,159 | 32,672 | ||||||
Cash and cash equivalents, end of period | $ | 55,889 | $ | 30,352 |
____________________________________________________________ | |
(1) | See footnote 1 to the condensed consolidated statements of operations. |
Selected operating data
Three months ended March 31, | ||||||||
2018 | 2017 | |||||||
(unaudited) | ||||||||
Sales volumes: | ||||||||
Oil (MBbl) | 2,439 | 2,120 | ||||||
NGL (MBbl) | 1,563 | 1,263 | ||||||
Natural gas (MMcf) | 10,173 | 8,000 | ||||||
Oil equivalents (MBOE)(1)(2) | 5,698 | 4,716 | ||||||
Average daily sales volumes (BOE/D)(2) | 63,314 | 52,405 | ||||||
% Oil(2) | 43 | % | 45 | % | ||||
Average sales prices(2): | ||||||||
Oil, realized ($/Bbl)(3) | $ | 61.87 | $ | 46.91 | ||||
NGL, realized ($/Bbl)(3) | $ | 18.14 | $ | 16.49 | ||||
Natural gas, realized ($/Mcf)(3) | $ | 1.79 | $ | 2.31 | ||||
Average price, realized ($/BOE)(3) | $ | 34.65 | $ | 29.42 | ||||
Oil, hedged ($/Bbl)(4) | $ | 58.53 | $ | 49.70 | ||||
NGL, hedged ($/Bbl)(4) | $ | 18.11 | $ | 16.04 | ||||
Natural gas, hedged ($/Mcf)(4) | $ | 1.85 | $ | 2.31 | ||||
Average price, hedged ($/BOE)(4) | $ | 33.34 | $ | 30.55 | ||||
Average costs per BOE sold(2): | ||||||||
Lease operating expenses | $ | 3.85 | $ | 3.60 | ||||
Production and ad valorem taxes | 2.07 | 1.86 | ||||||
Midstream service expenses | 0.12 | 0.19 | ||||||
General and administrative: | ||||||||
Cash | 2.70 | 3.47 | ||||||
Non-cash stock-based compensation, net | 1.64 | 1.96 | ||||||
Depletion, depreciation and amortization | 7.99 | 7.23 | ||||||
Total costs and expenses | $ | 18.37 | $ | 18.31 | ||||
Cash margins per BOE sold(2): | ||||||||
Realized | $ | 25.91 | $ | 20.30 | ||||
Hedged | $ | 24.60 | $ | 21.43 |
____________________________________________________________ | |
(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 realized at the wellhead adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. |
(4) | Hedged prices reflect the after-effects of our hedging transactions on our average sales prices. Our calculation of such after-effects includes current period settlements of matured derivatives in accordance with GAAP and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to instruments that settled in the period. |
Costs incurred
The following table presents costs incurred in the acquisition, exploration and development of oil and natural gas properties:
Three months ended March 31, | ||||||||
(in thousands) | 2018 | 2017 | ||||||
(unaudited) | ||||||||
Property acquisition costs: | ||||||||
Evaluated | $ | — | $ | — | ||||
Unevaluated | — | — | ||||||
Exploration costs | 6,137 | 15,543 | ||||||
Development costs | 149,038 | 111,158 | ||||||
Total costs incurred | $ | 155,175 | $ | 126,701 | ||||
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 and Adjusted EBITDA should not be considered in isolation or as a substitute for GAAP measures, such as net income or loss, operating income or loss or any other GAAP measure of liquidity or financial performance.
Adjusted Net Income
Adjusted Net Income is a non-GAAP financial measure we use to evaluate performance, prior to income tax expense or benefit, 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 March 31, | ||||||||
(in thousands, except per share data) | 2018 | 2017 | ||||||
(unaudited) | ||||||||
Income before income taxes | $ | 86,520 | $ | 68,276 | ||||
Plus: | ||||||||
Mark-to-market on derivatives: | ||||||||
Gain on derivatives, net | (9,010 | ) | (36,671 | ) | ||||
Settlements (paid) received for matured derivatives, net | (2,236 | ) | 7,451 | |||||
Premiums paid for derivatives | (4,024 | ) | (2,107 | ) | ||||
Loss on disposal of assets, net | 2,617 | 214 | ||||||
Adjusted income before adjusted income tax expense | 73,867 | 37,163 | ||||||
Adjusted income tax expense(1) | (16,251 | ) | (13,379 | ) | ||||
Adjusted Net Income | $ | 57,616 | $ | 23,784 | ||||
Net income per common share: | ||||||||
Basic | $ | 0.36 | $ | 0.29 | ||||
Diluted | $ | 0.36 | $ | 0.28 | ||||
Adjusted Net Income per common share: | ||||||||
Basic | $ | 0.24 | $ | 0.10 | ||||
Diluted | $ | 0.24 | $ | 0.10 | ||||
Weighted-average common shares outstanding: | ||||||||
Basic | 238,228 | 238,505 | ||||||
Diluted | 239,319 | 244,379 |
____________________________________________________________ | |
(1) | Adjusted income tax expense is calculated by applying a statutory tax rate of 22% for the three months ended March 31, 2018, in response to recent changes in the tax code, and 36% for the three months ended March 31, 2017. |
Adjusted EBITDA
Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss plus adjustments for 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 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 March 31, | ||||||||
(in thousands) | 2018 | 2017 | ||||||
(unaudited) | ||||||||
Net income | $ | 86,520 | $ | 68,276 | ||||
Plus: | ||||||||
Depletion, depreciation and amortization | 45,553 | 34,112 | ||||||
Non-cash stock-based compensation, net | 9,339 | 9,224 | ||||||
Accretion expense | 1,106 | 928 | ||||||
Mark-to-market on derivatives: | ||||||||
Gain on derivatives, net | (9,010 | ) | (36,671 | ) | ||||
Settlements (paid) received for matured derivatives, net | (2,236 | ) | 7,451 | |||||
Premiums paid for derivatives | (4,024 | ) | (2,107 | ) | ||||
Interest expense | 13,518 | 22,720 | ||||||
Loss on disposal of assets, net | 2,617 | 214 | ||||||
Income from equity method investee(1) | — | (3,068 | ) | |||||
Proportionate Adjusted EBITDA of equity method investee(1)(2) | — | 6,365 | ||||||
Adjusted EBITDA | $ | 143,383 | $ | 107,444 |
____________________________________________________________ | |
(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 March 31, | ||||||||
(in thousands) | 2018 | 2017 | ||||||
(unaudited) | ||||||||
Income from equity method investee | $ | — | $ | 3,068 | ||||
Adjusted for proportionate share of depreciation and amortization | — | 3,297 | ||||||
Proportionate Adjusted EBITDA of equity method investee | $ | — | $ | 6,365 | ||||
Contacts:
Ron Hagood: (918) 858-5504 -RHagood@laredopetro.com
18-6
Source: Laredo Petroleum, Inc.