Continental Resources Reports Third Quarter 2019 Results
Focused on Disciplined, Oil-Weighted Growth and Building Shareholder Value
$158.2 Million in Net Income in 3Q19, or $0.43 per Diluted Share
- $199.4 Million Adjusted Net Income in 3Q19, or $0.54 per Diluted Share (Non-GAAP)
198,074 Average Daily 3Q19 Oil Production up 20% over 3Q18
- 332,315 Boepd Average Daily 3Q19 Production up 12% over 3Q18
Bakken: 145,436 Average Daily 3Q19 Oil Production up 13% over 3Q18
- 57 Gross Operated Wells Deliver 2,313 Boepd Average/Well Initial Rate
South: 44,854 Average Daily 3Q19 Oil Production up 62% over 3Q18
- SpringBoard Exceeded 3Q19 Target by 31%: 23,641 Bopd; 4Q19 Target Raised to ~24,000 Bopd
- CLR STACK: Two, 7-Well Oil Units Deliver Exceptional Results: 38,320 Bopd Combined Initial Rate
$187 Million of Share Repurchases Executed through October 29, 2019
Quarterly Dividend of $0.05 per Share in November 2019
OKLAHOMA CITY, Oct. 30, 2019 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the Company) today announced third quarter 2019 operating and financial results.
The Company reported net income of $158.2 million, or $0.43 per diluted share, for the quarter ended September 30, 2019. 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 third quarter 2019, these typically excluded items in aggregate represented $41.2 million, or $0.11 per diluted share, of Continental's reported net income. Adjusted net income for third quarter 2019 was $199.4 million, or $0.54 per diluted share (non-GAAP). Net cash provided by operating activities for third quarter 2019 was $807.0 million and EBITDAX was $828.7 million (non-GAAP).
Adjusted net income, adjusted net income per share, EBITDAX, net debt, net sales prices and cash general and administrative (G&A) expenses per barrel of oil equivalent (Boe) presented herein are non-GAAP financial measures. Definitions and explanations for how these measures relate to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures are provided at the conclusion of this press release.
"Continental teams continue to operate at a high performance level across the Bakken and Oklahoma. With an oil-weighted portfolio, investment grade level debt and a total shareholder return strategy, no other E&P company is more aligned with shareholders," said Harold Hamm, Chairman and Chief Executive Officer.
Production Update: 3Q19 Average Daily Oil Production up 20% over 3Q18
Third quarter 2019 oil production increased 20% over third quarter 2018, averaging 198,074 barrels of oil per day (Bopd). Third quarter 2019 total production increased 12% over third quarter 2018, averaging 332,315 Boe per day (Boepd). Third quarter 2019 natural gas production increased 1% over third quarter 2018, averaging 805.4 million cubic feet per day (MMcfpd). The following table provides the Company's average daily production by region for the periods presented.
"Approximately 50% of Continental's third quarter oil production growth, year-over-year, came from our Oklahoma assets," said Jack Stark, President. "This growth was driven by the outstanding results being realized from our ongoing development of SCOOP SpringBoard and STACK."
Bakken: 145,436 Average Daily 3Q19 Oil Production up 13% over 3Q18
In third quarter 2019, average daily Bakken oil production increased 13% over third quarter 2018, averaging 145,436 Bopd. The Company's third quarter 2019 total Bakken production increased 14% over third quarter 2018, averaging 191,268 Boepd. During the quarter, the Company completed 57 gross (37 net) operated wells with first production flowing at an average initial 24-hour rate per well of 2,313 Boepd.
The Company moved into manufacturing mode in the Bakken in 2017. Since then, the Company has focused almost exclusively on the multi-zone unit development of the Middle Bakken, Three Forks 1 and Three Forks 2 reservoirs. During this time, the Company has completed 440 gross operated unit wells with an average initial 24-hour rate per well of approximately 2,300 Boepd, with an average 80% oil. Both the 2017 and 2018 Bakken programs have paid out in approximately one year.
"We are more than two years into manufacturing mode and our Bakken assets are delivering remarkably consistent results with some of the best returns in the industry," said Jack Stark, President. "These results provide a great snapshot of the quality of our Bakken assets and reinforce the confidence we have in the Bakken as a key driver of Continental's growth for years to come."
South: 44,854 Average Daily 3Q19 Oil Production up 62% over 3Q18
In third quarter 2019, average daily South oil production increased 62% over third quarter 2018, averaging 44,854 Bopd. The Company's third quarter 2019 total South production increased 11% over third quarter 2018, averaging 133,266 Boepd. In third quarter 2019, the Company completed 80 gross (56 net) operated wells with first production in the South.
The Company exceeded its SCOOP Project SpringBoard oil production target for third quarter 2019 by 31%, averaging 23,641 Bopd. This outperformance was driven by operational efficiencies that brought wells on line ahead of schedule, as well as the outstanding Springer well performance in Rows 2 and 3. These wells flowed at an average initial 24-hour rate of 1,650 Boepd per well, with approximately 80% being oil. As expected, the 52 Springer wells combined in Rows 1, 2 and 3 are performing on average, in line with the blended 1.3 MMBoe unit type curve provided during the January SpringBoard conference call. The Company has raised its SpringBoard oil production target for fourth quarter 2019 from 22,000 Bopd to approximately 24,000 Bopd. To date, approximately 8.7 million gross barrels of oil have been produced from Project SpringBoard alone.
In the Continental STACK, the Reba Jo and Schulte oil units flowed at a combined initial 24-hour rate of 57,292 Boepd, of which 67% was oil, or 38,320 Bopd. Combined, the two units contained 14 unit wells that flowed at an average initial 24-hour rate of 4,092 Boepd per well. Since second quarter 2018, the Company has completed 8 units in the over-pressured window that have outperformed expectations and unit type curves for the STACK.
"Continental's South assets in the SCOOP and over-pressured STACK window continue to deliver outstanding results driven by our geologically superior acreage position, proper unit density design and excellent execution from our operational teams," said Pat Bent, Senior Vice President, Operations.
Total Shareholder Return Strategy Update: Share Repurchases and Quarterly Dividend
The Company has executed $187 million of share repurchases for 5.5 million shares, as of October 29, 2019. As previously announced, an initial share repurchase of up to $1 billion has been authorized by the Board of Directors, which is expected to continue through 2020. Share repurchases will be made at times and levels deemed appropriate by Company management and the Company intends to purchase shares opportunistically using available funds while maintaining sufficient liquidity to fund operating needs, capital program, and dividend payments.
The Company will be distributing its first quarterly dividend of $0.05 per share on the Company's outstanding common stock to stockholders of record on November 7, 2019. This will be payable on November 21, 2019.
"During 2019, Continental has strategically focused on building shareholder value by balancing significant cash flow generation with strong production growth. This has enabled the Company to repurchase $187 million in shares and complete strategic bolt-on acquisitions that add to our deep, oil-focused inventory," said John Hart, Chief Financial Officer.
As of September 30, 2019, the Company's balance sheet included approximately $35.3 million in cash and cash equivalents, $5.57 billion in total debt and $5.54 billion in net debt (non-GAAP).
In third quarter 2019, the Company's average net sales prices excluding the effects of derivative positions were $51.28 per barrel of oil and $1.12 per Mcf of gas, or $33.30 per Boe. Production expense per Boe was $3.73 for third quarter 2019. Total G&A expenses per Boe were $1.54 for third quarter 2019.
The Company's third quarter 2019 crude oil differential was $5.15 per barrel below the NYMEX daily average for the period. The wellhead natural gas price for third quarter 2019 was $1.11 per Mcf below the average NYMEX Henry Hub benchmark price.
Through September 30, 2019, the Company has realized approximately $52 million of cash gains from its natural gas hedges. As of September 30, 2019, the Company's unrealized non-cash mark-to-market gain on its natural gas hedges totaled approximately $17 million.
Non-acquisition capital expenditures for third quarter 2019 totaled approximately $681.5 million, including $578.1 million in exploration and development drilling and completion, $31.4 million in leasehold, $24.5 million in minerals, of which 80% was recouped from Franco-Nevada, and $47.5 million in workovers, recompletions and other.
The Company's full 2019 guidance can be found at the conclusion of this press release.
The following table provides the Company's production results, 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.
Third Quarter Earnings Conference Call
The Company plans to host a conference call to discuss third quarter 2019 results on Thursday, October 31, 2019 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
A replay of the call will be available for 14 days on the Company's website or by dialing:
The Company plans to publish a third quarter 2019 summary presentation to its website at www.CLR.com prior to the start of its conference call on October 31, 2019.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 independent oil producer in the U.S. Lower 48 and a leader in America's energy renaissance. Based in Oklahoma City, Continental is the largest leaseholder and the largest producer in the nation's premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP Woodford and SCOOP Springer discoveries and the STACK plays. With a focus on the exploration and production of oil, Continental has unlocked the technology and resources vital to American energy independence and our nation's leadership in the new world oil market. In 2019, the Company will celebrate 52 years of operations. For more information, please visit www.CLR.com.
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," "target," "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; our ability to pay future dividends or complete share repurchases; 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 December 31, 2018, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
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 net income and adjusted net income per share attributable to Continental
Our presentation of adjusted net income and adjusted net income per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted net income and adjusted net income per share represent net income and diluted net income 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 as applicable. 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 net income and adjusted net income per share should not be considered in isolation or as an alternative to, or more meaningful than, net income or diluted net income 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 tables reconcile net income and diluted net income per share as determined under U.S. GAAP to adjusted net income and adjusted diluted net income 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, total debt, the most directly 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. This metric is sometimes presented as a ratio with EBITDAX in order to provide investors with another means of evaluating the Company's ability to service its existing debt obligations as well as any future increase in the amount of such obligations. At September 30, 2019, the Company's total debt was $5.57 billion and its net debt amounted to $5.54 billion, representing total debt of $5.57 billion less cash and cash equivalents of $35.3 million. From time to time the Company provides forward-looking net debt forecasts; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measure to the most directly comparable forward-looking GAAP measure of total debt 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.
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX, a non-GAAP measure. 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 as applicable. 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/loss 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/loss 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.
Net Sales Prices
Revenues and transportation expenses associated with production from our operated properties are reported separately. 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. As a result, the separate presentation of revenues and transportation expenses from our operated properties differs from the net presentation from non-operated properties. This impacts the comparability of certain operating metrics, such as per-unit sales prices, when such metrics are prepared in accordance with U.S. GAAP using gross presentation for some revenues and net presentation for others.
In order to provide metrics prepared in a manner consistent with how management assesses the Company's operating results and to achieve comparability between operated and non-operated revenues, 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 tables present 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 periods presented.
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.
The following table reconciles total G&A per Boe as determined under U.S. GAAP to cash G&A per Boe for the periods presented.
SOURCE Continental Resources