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|Continental Resources Reports First Quarter 2018 Results|
The Company's net income includes certain items typically excluded by the investment community in published estimates, the result of which is referred to as "adjusted net income." In first quarter 2018, these typically excluded items in aggregate represented
Net cash provided by operating activities for first quarter 2018 was
During first quarter 2018, the Company generated
Based on realizations without the effect of derivatives, the Company's first quarter 2018 crude oil differential was
"Our first quarter results show our 2018 breakout year is off to a strong start," said
First quarter 2018 production totaled 25.9 million barrels of oil equivalent (Boe), or 287,410 Boe per day, up 34% from first quarter 2017. Oil production grew 37% from first quarter 2017 to first quarter 2018. The Company expects second quarter 2018 production will be in a range of 285,000 to 290,000 Boe per day.
Total production for first quarter 2018 included 163,837 barrels of oil (Bo) per day (57% of production) and 741.4 million cubic feet (MMcf) of natural gas per day (43% of production). The Company expects to remain in the range of 57% - 60% oil as a percent of overall production in 2018, which is in line with prior guidance.
The following table provides the Company's average daily production by region for the periods presented.
Bakken: Record Well Performance and Improved Differentials
The Company's Bakken production averaged 161,356 Boe per day in first quarter 2018, up 48% versus first quarter 2017. Approximately 80% of the production was oil. The Company completed 31 gross (21 net) operated Bakken wells during the first quarter with an average 24-Hour IP of 2,079 Boe per day.
Three of the Company's top five all-time 30-day rate wells in the Bakken were completed in the first quarter, averaging 2,305 Boe per day. The top eight 30-day rate Bakken wells in the Company's history have now been completed in the past two quarters. These record rates are a result of the Company's optimized completion designs.
To date, the Company has completed 164 optimized Bakken wells in Dunn, McKenzie, Mountrail and Williams counties. On average, these wells are performing in line with the Company's current 1.1 MMBoe type curve, which delivers a rate of return of 140%, based on a
Bakken crude oil differentials averaged
"We are clearly seeing a structural uplift in well performance across the Bakken field," said
The Company's SCOOP production averaged 62,012 Boe per day (26% oil) in first quarter 2018. The Company had 18 gross (14 net) operated wells completed in first quarter 2018.
SCOOP: Project "SpringBoard" Announced with Phase 1 Springer Row Development Underway
The Company has initiated a multi-zone, oil development project within SCOOP named Project SpringBoard. The project covers 70-square miles and includes approximately 45,000 gross (31,000 net) contiguous acres. The Company anticipates approximately 100 Springer wells and up to 250 Woodford and/or Sycamore wells will be drilled in the project with gross unrisked reserve potential of over 400 MMBoe. The Company will operate these wells with an average working interest of approximately 75%. The Company currently plans to develop Project SpringBoard in two phases, with "Phase 1" focused on the Springer reservoir and "Phase 2" focused on
"Project SpringBoard is a massive oil project controlled and operated by
Before beginning row development of the Springer, the Company recently completed the four-well Triple H Springer unit within Project SpringBoard. The four Springer producers flowed at a maximum combined 24-hour IP rate of 6,065 Boe per day, with 88% of the production being high quality, sweet 46 gravity crude. The Triple H wells were drilled to test the productivity of thinner areas of the reservoir, using extended laterals that were 10,200 feet long. These extended laterals were drilled in approximately the same number of days (35 days) and at drilling costs comparable to one-mile laterals drilled approximately one year earlier.
SCOOP Woodford Oil: Updated Design Lowers Drilling Costs
Updated well designs and improved drilling performance have reduced completed well costs in the
In addition, the Company recently completed two optimized
STACK: Shifting Rigs to
The Company's STACK production increased 83% to 53,361 Boe per day in first quarter 2018, compared to first quarter 2017.
The Company is shifting three of five rigs drilling in the STACK gas window, as acreage in the STACK JDA is now essentially held by production. Two rigs will move to unit development in the STACK over-pressured oil window and one will move to the over-pressured condensate window in SCOOP. With this reallocation, approximately 90% of the Company's 16 rigs in Oklahoma will be focused on oil and liquids-rich assets.
Project Wildcat: 400 MMcfd of Firm Transportation from SCOOP and STACK
The Company recently announced a firm transportation agreement on
"With the announcement of Project Wildcat,
"2018 is off to a great start with the generation of
In first quarter 2018, the Company's average net sales price excluding the effects of derivative positions was
Production expense per Boe was
Non-acquisition capital expenditures for first quarter 2018 totaled approximately
The following table provides the Company's production results, average net sales prices, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average net sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
First Quarter Earnings Conference Call
A replay of the call will be available for 14 days on the Company's website or by dialing:
About Continental Resources
Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995
This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. The risks and uncertainties include, but are not limited to, commodity price volatility; the geographic concentration of our operations; financial market and economic volatility; the inability to access needed capital; the risks and potential liabilities inherent in crude oil and natural gas drilling and production and the availability of insurance to cover any losses resulting therefrom; difficulties in estimating proved reserves and other reserves-based measures; declines in the values of our crude oil and natural gas properties resulting in impairment charges; our ability to replace proved reserves and sustain production; the availability or cost of equipment and oilfield services; leasehold terms expiring on undeveloped acreage before production can be established; our ability to project future production, achieve targeted results in drilling and well operations and predict the amount and timing of development expenditures; the availability and cost of transportation, processing and refining facilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; increased market and industry competition, including from alternative fuels and other energy sources; and the other risks described under Part I, Item 1A. Risk Factors and elsewhere in the Company's Annual Report on Form 10-K for the year ended
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
Readers are cautioned that initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to describe potentially recoverable oil and natural gas hydrocarbon quantities. We include these estimates to demonstrate what we believe to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and require substantial capital spending to implement recovery. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. EUR data included herein remain subject to change as more well data is analyzed.
Non-GAAP Financial Measures
Adjusted earnings (net income) and adjusted earnings (net income) per share
Our presentation of adjusted earnings and adjusted earnings per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted earnings and adjusted earnings per share represent earnings and diluted earnings per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, gains and losses on asset sales, and losses on extinguishment of debt. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted earnings and adjusted earnings per share should not be considered in isolation or as an alternative to, or more meaningful than, earnings or diluted earnings per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following table reconciles earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share for the periods presented.
Net debt is a non-GAAP measure. We define net debt as total debt less cash and cash equivalents as determined under U.S. GAAP. Net debt should not be considered an alternative to, or more meaningful than, the comparable GAAP measure. Management uses net debt to determine the Company's outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. We believe this metric is useful to analysts and investors in determining the Company's leverage position since the Company has the ability to, and may decide to, use a portion of its cash and cash equivalents to reduce debt. At
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt. EBITDAX is not a measure of net income or net cash provided by operating activities as determined by U.S. GAAP.
Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income and net cash provided by operating activities in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.
EBITDAX should not be considered as an alternative to, or more meaningful than, net income or net cash provided by operating activities as determined in accordance with U.S. GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.
The following table provides a reconciliation of our net income to EBITDAX for the periods presented.
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
Free cash flow
Our presentation of free cash flow is a non-GAAP measure. We define free cash flow as cash flows from operations before changes in working capital items less capital expenditures excluding acquisitions and divestitures. Free cash flow is not a measure of net income or cash flows as determined by U.S. GAAP and should not be considered an alternative to, or more meaningful than, the comparable GAAP measure. Management believes that these measures are useful to management and investors as a measure of a company's ability to internally fund its capital expenditures and to service or incur additional debt. These measures eliminate the impact of certain items that management does not consider to be indicative of the Company's performance from period to period. From time to time the Company provides forward-looking free cash flow estimates; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. The reconciling items in future periods could be significant.
The following table reconciles historical net cash provided by operating activities as determined under U.S. GAAP to free cash flow for the first quarter of 2018.
Net sales prices
Under the new rules, revenues and transportation expenses associated with the majority of production from our operated properties are now reported on a gross basis compared to net presentation in the prior year. For non-operated properties, we receive a net payment from the operator for our share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds received, consistent with our historical practice. As a result, beginning
In order to provide metrics prepared in a manner consistent with how management assesses the Company's operating results, and to achieve comparability with prior period metrics for analysis purposes, we may present crude oil and natural gas sales net of transportation expenses, which we refer to as "net crude oil and natural gas sales," a non-GAAP measure. Average sales prices calculated using net crude oil and natural gas sales are referred to as "net sales prices," a non-GAAP measure, and are calculated by taking revenues less transportation expenses divided by sales volumes, whether for crude oil or natural gas, as applicable. Management believes presenting our revenues and sales prices net of transportation expenses is useful because it normalizes the presentation differences between operated and non-operated revenues and allows for a useful comparison of net realized prices to NYMEX benchmark prices on a Company-wide basis.
The following table presents a reconciliation of crude oil and natural gas sales (GAAP) to net crude oil and natural gas sales and related net sales prices (non-GAAP) for the three months ended March 31, 2018. Information is also presented for the three months ended March 31, 2017 for comparative purposes.
Cash general and administrative expenses per Boe
Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies.
SOURCE Continental Resources