All financial information contained within this news release has been prepared in accordance with U.S. GAAP and is presented in U.S. dollars. This news release includes forward-looking statements and information within the meaning of applicable securities laws. Production information, unless otherwise stated, is presented on a net basis (after deduction of royalty obligations). Readers are advised to review the “Forward-Looking Information and Statements” at the conclusion of this news release. Readers are also referred to “Notice Regarding Information Contained in this News Release” and “Non-GAAP and Other Financial Measures” at the end of this news release for information regarding the presentation of the financial and operational information in this news release, as well as the use of certain financial measures that do not have standard meaning under U.S. GAAP. A copy of Enerplus’ 2023 Financial Statements and MD&A is available on our website at www.enerplus.com, under our profile on SEDAR+ at www.sedarplus.ca and on the EDGAR website at www.sec.gov. All amounts in this news release are stated in United States dollars unless otherwise specified.
CALGARY, AB, Feb. 21, 2024 /CNW/ – Enerplus Corporation (“Enerplus” or the “Company”) (TSX: ERF) (NYSE: ERF) today reported fourth quarter 2023 cash flow from operating activities and adjusted funds flow(1) of $297.9 million and $240.5 million, respectively, compared to $316.6 million and $315.4 million, respectively, in the fourth quarter of 2022. Full year 2023 cash flow from operating activities and adjusted funds flow(1) was $938.2 million and $961.2 million, respectively, compared to $1,173.4 million and $1,230.3 million, in 2022.
On February 21, 2024, Enerplus entered into an arrangement agreement with Chord Energy Corporation (“Chord”), pursuant to which, upon completion of the transaction, Enerplus shareholders will receive 0.10125 shares of Chord common stock and $1.84 in cash for each share of Enerplus (90% stock and 10% cash consideration). The transaction is subject to various approvals and conditions to close and is expected to be completed mid-2024. For more information refer to the joint press release of Enerplus and Chord regarding this transaction.
HIGHLIGHTS – FULL YEAR 2023
- Exceeded 2023 total and liquids production guidance:
- Total production averaged 100,015 BOE per day (guidance of 98,000 to 99,000 BOE per day).
- Liquids production averaged 62,208 barrels per day (guidance of 60,500 to 61,500 barrels per day).
- Generated adjusted funds flow(1)Â of $961.2 million in 2023, which exceeded capital spending of $532.5 million, generating free cash flow(1)Â of $428.7 million.
- Returned $306.9 million to shareholders through dividends and share repurchases, representing 72% of 2023 free cash flow(1).
- Reduced shares outstanding by 7% since year-end 2022 and 17% since year-end 2021.
- Reduced net debt(1)Â by 46% from year-end 2022, ending 2023 with net debt(1)Â of $119.3 million.
- Reduced 2023 methane emissions intensity by 45% and Scope 1 and Scope 2 greenhouse gas (“GHG”) emissions intensity by 40%, compared to 2021, based on preliminary estimates.
“2023 marked another year of solid operational and financial performance, further demonstrating the quality of our team and North Dakota Bakken position,” said Ian C. Dundas, President and CEO. “We exceeded production targets within a disciplined capital allocation framework, helping to drive free cash flow of over $400 million. Consistent with our track record, we returned significant cash to shareholders — over 70% of free cash flow in 2023 — through dividends and share repurchases, while also reducing net debt by 46%.”
| (1) | This is a non-GAAP financial measure. Refer to “Non-GAAP and Other Financial Measures” section for more information. |
FOURTH QUARTER 2023 SUMMARY
Total production for the fourth quarter of 2023 was 103,543 BOE per day, a decrease of 3% compared to the same period in 2022. Liquids production in the fourth quarter was 67,097 barrels per day, an increase of 3% compared to the same period in 2022. Strong well performance in North Dakota supported fourth quarter 2023 liquids production, while lower activity levels in the Marcellus throughout 2023 and the impact from the sale of Canadian assets during the fourth quarter of 2022 led to the decrease in total production year-over-year. The Company’s fourth quarter production exceeded the top end of the total and liquids production guidance ranges of 95,000 to 99,000 BOE per day and 60,500 to 64,500 barrels per day, respectively.
In North Dakota, Enerplus drilled 19Â operated wells (79% average working interest) during the quarter, with no operated wells brought on production. North Dakota production averaged 78,222 BOE per day in the quarter. Marcellus production averaged 143 MMcf per day in the quarter.
Enerplus reported fourth quarter 2023 net income of $116.7 million, or $0.57 per share (basic), compared to net income of $330.7 million, or $1.49 per share (basic), in the fourth quarter of 2022. Excluding certain non-cash or non-recurring items, fourth quarter 2023 adjusted net income(1)Â was $115.3 million, or $0.56 per share (basic), compared to $181.1 million, or $0.81 per share (basic), during the same period in 2022. The reduction in net income was due to the gain on the sale of the Canadian assets recorded during the fourth quarter of 2022, as well as lower production and commodity prices, which also decreased adjusted net income, relative to the prior year period.
Enerplus’ realized fourth quarter 2023 Bakken crude oil price differential was $1.26 per barrel below WTI, compared to $1.05 per barrel above WTI for the same period in 2022. Bakken crude oil prices were weaker than the prior year period due to elevated local production growth driven predominantly by an acceleration in well completion activity resulting in less spare pipeline capacity in 2023, while refinery demand deteriorated in the fourth quarter of 2023 due to a decline in global refinery margins. Enerplus’ fourth quarter 2023 Marcellus natural gas price differential was $1.20 per Mcf below NYMEX, compared to $1.18 per Mcf below NYMEX for the same period in 2022.
Operating expenses in the fourth quarter of 2023 were $11.67 per BOE, compared to $9.68 per BOE in the same period in 2022. The increase in per unit operating expenses was primarily due to inflation adjusted contract pricing and higher gas facility and fluid handling charges due to the increase in North Dakota production. Cash general and administrative (“G&A”) expenses were $1.41 per BOE in the fourth quarter of 2023, compared to $1.15 per BOE in the prior year period due to inflationary pressures on labour and services.
Capital spending totaled $91.5 million in the fourth quarter. The Company paid $12.2 million in dividends during the quarter and repurchased 5.8 million shares at an average price of $16.09 per share for a total cost of $93.8 million.
Current tax expense was $0.2 million in the fourth quarter.
Enerplus ended the fourth quarter with net debt(1)Â of $119.3 million and had a net debt to adjusted funds flow ratio(1)Â of 0.1 times.
| (1) | This is a non-GAAP financial measure. Refer to “Non-GAAP and Other Financial Measures” section for more information. |
FULL YEAR 2023 SUMMARY
Total production for 2023 was 100,015 BOE per day, broadly flat compared to 2022. Liquids production in 2023 was 62,208, an increase of 1% compared to 2022. Liquids production increased by 9% year-over-year when adjusted for the Canadian asset divestments completed in 2022. The Company’s 2023 production exceeded the top end of the total and liquids production guidance ranges of 98,000 to 99,000 BOE per day and 60,500 to 61,500 barrels per day, respectively.
Enerplus reported full year 2023 net income of $456.1 million, or $2.16 per share (basic), compared to net income of $914.3 million, or $3.91 per share (basic), in 2022. Excluding certain non-cash or non-recurring items, 2023 adjusted net income(1)Â was $477.6 million, or $2.26 per share (basic), compared to $707.1 million, or $3.02 per share (basic), in 2022. The lower net income in 2023 was due to the gain on the sale of the Canadian assets recorded during 2022, as well as lower production and commodity prices, which also decreased adjusted net income, relative to the prior year period.
Enerplus’ 2023 realized Bakken crude oil price differential was $0.45 per barrel below WTI, compared to $1.09 per barrel above WTI in 2022. Bakken differentials weakened through the second half of 2023 due to local production growth driven by an acceleration in well completion activity resulting in less spare pipeline capacity in 2023, while refinery demand deteriorated in the fourth quarter of 2023 due to a decline in global refinery margins. Enerplus’ 2023 Marcellus natural gas price differential was $0.92 per Mcf below NYMEX, compared to $0.72 per Mcf below NYMEX in 2022.
Operating expenses in 2023 were $10.67 per BOE, compared to $9.99 per BOE in 2022. The increase in per BOE operating expenses was primarily due to inflation adjusted contract pricing and higher gas facility and fluid handling charges as a result of increased production in North Dakota. Cash G&A expenses in 2023 were $1.33 per BOE, compared to $1.17 per BOE in 2022 due to inflationary pressures on labour and services.
Current tax expense was $27.2 million in 2023.
Capital spending totaled $532.5 million in 2023, approximately the midpoint of the Company’s guidance range of $520 to $540 million. The Company paid $48.6 million in dividends in 2023 and repurchased 16.4 million shares at an average price of $15.71 per share for a total of $258.3 million. In total, Enerplus returned $306.9 million to shareholders in 2023.
| (1) | This is a non-GAAP financial measure. Refer to “Non-GAAP and Other Financial Measures” section for more information. |
ENVIRONMENTAL, SOCIAL AND GOVERNANCE (ESG) UPDATE
Enerplus continues to make progress on its ESG initiatives in 2023. Based on preliminary estimates and relative to its 2021 baseline, the Company reduced 2023 methane emissions intensity by 45% and Scope 1 and Scope 2 GHG emissions intensity by 40%.
The Company continues to work towards its longer-term emissions reduction targets, including a methane emissions intensity of 0.02 kg CH4/BOE by 2030, and a Scope 1 and Scope 2 GHG emissions intensity of 13 kg CO2e/BOE by 2030, which equates to an approximate intensity reduction of 45% and 30%, respectively, from Enerplus’ preliminary 2023 estimates.
As previously disclosed, as part of its emissions reduction strategy Enerplus is endorsing the World Bank Zero Routine Flaring by 2030 initiative and has established a flare intensity target of less than 2% per thousand cubic feet of natural gas produced by 2026.
2024 OUTLOOK
As previously announced, Enerplus expects 2024 capital spending of approximately $550 million and annual average liquids production of approximately 64,000 barrels per day. The Company expects 2024 annual average total production of approximately 99,000 BOE per day(1). The Company’s 2024 outlook is subject to changes as a result of completion of the transaction with Chord, which is currently expected to close mid-2024.
On February 21, 2024, the Board approved a dividend increase of 8% to the quarterly dividend to $0.065 per share beginning with the March 15, 2024 dividend. It is anticipated that the quarterly dividend payments made by Enerplus until closing of the transaction will be equalized to those made by Chord, after giving effect to the exchange ratio, through an additional Enerplus dividend declared shortly prior to the closing.
| (1) | See “Notice Regarding Information Contained in This News Release – Forward-Looking Information and Statements” in this news release. |
PRICE RISK MANAGEMENT UPDATE
The following is a summary of Enerplus’ financial contracts in place at February 20, 2024:
| WTI Crude Oil ($/bbl)(1) | Leidy Basis ($/Mcf) | |||
| Jan 1, 2024 – Jun 30, 2024 | Feb 1, 2024 – Feb 29, 2024 | |||
| Swaps | ||||
| Volume (Mcf/day) | – | 40,000 | ||
| Swap Strike | – | ($ 0.45) | ||
| 3 Way Collars | ||||
| Volume (bbls/day) | 5,000 | – | ||
| Sold Puts | $ 65.00 | – | ||
| Purchased Puts | $ 77.00 | – | ||
| Sold Calls | $ 95.00 | – |
| (1) | The total average deferred premium spent on our outstanding crude oil contracts is $1.25/bbl from January 1, 2024 – June 30, 2024. |
FOURTH QUARTER AND FULL YEAR 2023 PRODUCTION AND OPERATIONAL SUMMARY TABLES
Summary of Average Daily Production(1)
| Three months ended December 31, 2023 | Twelve months ended December 31, 2023 | |||||||||
| Williston Basin | Marcellus | Other(2) | Total | Williston Basin | Marcellus | Other(2) | Total | |||
| Light & medium oil (bbl/d) | – | – | – | – | – | – | – | – | ||
| Heavy oil (bbl/d) | – | – | – | – | – | – | – | – | ||
| Tight oil (bbl/d) | 52,831 | – | 1,181 | 54,011 | 49,827 | – | 951 | 50,779 | ||
| Total crude oil (bbl/d) | 52,831 | – | 1,181 | 54,011 | 49,827 | – | 951 | 50,779 | ||
| Natural gas liquids (bbl/d) | 12,952 | – | 134 | 13,086 | 11,323 | – | 106 | 11,429 | ||
| Conventional natural gas (Mcf/d) | – | – | – | – | – | – | – | – | ||
| Shale gas (Mcf/d) | 74,637 | 142,926 | 1,112 | 218,675 | 70,645 | 155,329 | 866 | 226,840 | ||
| Total natural gas (Mcf/d) | 74,637 | 142,926 | 1,112 | 218,675 | 70,645 | 155,329 | 866 | 226,840 | ||
| Total production (BOE/d) | 78,222 | 23,821 | 1,500 | 103,543 | 72,925 | 25,888 | 1,202 | 100,015 | ||
| (1) | Table may not add due to rounding. |
| (2) | Largely comprises the DJ Basin. |
Summary of Wells Drilled(1)
| Three months ended December 31, 2023 |
Twelve months ended December 31, 2023 |
||||||||||
| Operated | Non-Operated | Operated | Non-Operated | ||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||
| Williston Basin | 19 | 15.1 | 7 | 0.3 | 65 | 54.7 | 73 | 7.1 | |||
| Marcellus | – | – | 16 | 0.4 | – | – | 56 | 1.2 | |||
| DJ Basin | – | – | – | – | 3 | 2.9 | – | – | |||
| Total | 19 | 15.1 | 23 | 0.7 | 68 | 57.6 | 129 | 8.3 | |||
| (1) | Table may not add due to rounding. |
Summary of Wells Brought On-Stream(1)
| Three months ended December 31, 2023 |
Twelve months ended December 31, 2023 |
||||||||||
| Operated | Non-Operated | Operated | Non-Operated | ||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||
| Williston Basin | – | – | 36 | 3.0 | 46 | 40.0 | 77 | 9.4 | |||
| Marcellus | – | – | 30 | 0.6 | – | – | 52 | 0.9 | |||
| DJ Basin | – | – | – | – | 3 | 2.9 | 10 | 0.2 | |||
| Total | – | – | 66 | 3.6 | 49 | 43.0 | 139 | 10.5 | |||
| (1) | Table may not add due to rounding. |
SUMMARY FINANCIAL AND OPERATING RESULTS
| Three months ended | Twelve months ended | |||||||||||
| SELECTED FINANCIAL RESULTS | December 31, | December 31, | ||||||||||
| 2023 | 2022 | 2023 | 2022 | |||||||||
| Financial (US$, thousands, except ratios) | ||||||||||||
| Net Income/(Loss) | $ | 116,702 | $ | 330,708 | $ | 456,076 | $ | 914,302 | ||||
| Adjusted Net Income(1) | 115,253 | 181,069 | 477,570 | 707,061 | ||||||||
| Cash Flow from Operating Activities | 297,946 | 316,584 | 938,190 | 1,173,382 | ||||||||
| Adjusted Funds Flow(1) | 240,526 | 315,379 | 961,243 | 1,230,289 | ||||||||
| Dividends to Shareholders – Declared | 12,242 | 12,223 | 48,603 | 41,597 | ||||||||
| Net Debt(1) | 119,298 | 221,516 | 119,298 | 221,516 | ||||||||
| Capital Spending | 91,507 | 85,647 | 532,450 | 432,004 | ||||||||
| Property and Land Acquisitions | 1,681 | 2,853 | 7,342 | 22,515 | ||||||||
| Property and Land Divestments | 1,267 | 211,987 | 2,969 | 231,373 | ||||||||
| Net Debt to Adjusted Funds Flow Ratio(1) | 0.1x | 0.2x | 0.1x | 0.2x | ||||||||
| Financial per Weighted Average Shares Outstanding | ||||||||||||
| Net Income/(Loss) – Basic | $ | 0.57 | $ | 1.49 | $ | 2.16 | $ | 3.91 | ||||
| Net Income/(Loss) – Diluted | 0.55 | 1.43 | 2.09 | 3.77 | ||||||||
| Weighted Average Number of Shares Outstanding (000’s) – Basic | 204,624 | 222,404 | 211,353 | 233,946 | ||||||||
| Weighted Average Number of Shares Outstanding (000’s) – Diluted | 211,176 | 231,149 | 217,896 | 242,673 | ||||||||
| Selected Financial Results per BOE(2)(3) | ||||||||||||
| Crude Oil & Natural Gas Sales(4) | $ | 45.88 | $ | 55.78 | $ | 45.56 | $ | 64.27 | ||||
| Commodity Derivative Instruments | 0.33 | (4.83) | 1.56 | (9.48) | ||||||||
| Operating Expenses | (11.67) | (9.68) | (10.67) | (9.99) | ||||||||
| Transportation Costs | (3.84) | (4.04) | (3.99) | (4.22) | ||||||||
| Production Taxes | (3.81) | (4.03) | (3.70) | (4.56) | ||||||||
| General and Administrative Expenses | (1.41) | (1.15) | (1.33) | (1.17) | ||||||||
| Cash Share-Based Compensation Recovery/(Expense) | 0.15 | (0.21) | 0.01 | (0.16) | ||||||||
| Interest, Foreign Exchange and Other Expenses | (0.36) | 0.56 | (0.36) | (0.32) | ||||||||
| Current Income Tax Recovery/(Expense) | (0.02) | (0.34) | (0.75) | (0.77) | ||||||||
| Adjusted Funds Flow(1) | $ | 25.25 | $ | 32.06 | $ | 26.33 | $ | 33.60 | ||||
| Three months ended | Twelve months ended | |||||||||||
| SELECTED OPERATING RESULTS | December 31, | December 31, | ||||||||||
| 2023 | 2022 | 2023 | 2022 | |||||||||
| Average Daily Production(3) | ||||||||||||
| Crude Oil (bbls/day) | 54,011 | 54,601 | 50,779 | 52,017 | ||||||||
| Natural Gas Liquids (bbls/day) | 13,086 | 10,755 | 11,429 | 9,681 | ||||||||
| Natural Gas (Mcf/day) | 218,675 | 249,351 | 226,840 | 231,770 | ||||||||
| Total (BOE/day) | 103,543 | 106,915 | 100,015 | 100,326 | ||||||||
| % Crude Oil and Natural Gas Liquids | 65Â % | 61Â % | 62Â % | 61Â % | ||||||||
| Average Selling Price(3)(4) | ||||||||||||
| Crude Oil (per bbl) | $ | 77.21 | $ | 83.06 | $ | 77.42 | $ | 93.63 | ||||
| Natural Gas Liquids (per bbl) | 16.86 | 21.88 | 17.93 | 30.70 | ||||||||
| Natural Gas (per Mcf) | 1.65 | 4.76 | 1.85 | 5.51 | ||||||||
| Net Wells Drilled | 15.8 | 9.9 | 65.8 | 51.7 | ||||||||
| (1) | This financial measure is a non-GAAP financial measure. See “Non-GAAP and Other Financial Measures” section in this news release. |
| (2) | Non‑cash amounts have been excluded. |
| (3) | Represents net production volumes. See “Presentation of Production and Reserves Information” section in this news release. |
| (4) | Before transportation costs and commodity derivative instruments. |
Condensed Consolidated Balance Sheets
| (US$ thousands) | December 31, 2023 | December 31, 2022 | |||||
| Assets | |||||||
| Current assets | |||||||
| Cash and cash equivalents | $ | 66,731 | $ | 38,000 | |||
| Accounts receivable, net of allowance for doubtful accounts | 268,433 | 276,590 | |||||
| Other current assets | 44,959 | 56,552 | |||||
| Derivative financial assets | 3,161 | 36,542 | |||||
| 383,284 | 407,684 | ||||||
| Property, plant and equipment: | |||||||
| Crude oil and natural gas properties (full cost method) | 1,511,682 | 1,322,904 | |||||
| Other capital assets | 9,546 | 10,685 | |||||
| Property, plant and equipment | 1,521,228 | 1,333,589 | |||||
| Other long-term assets | 5,945 | 21,154 | |||||
| Right-of-use assets | 24,996 | 20,556 | |||||
| Deferred income tax asset | 133,023 | 154,998 | |||||
| Total Assets | $ | 2,068,476 | $ | 1,937,981 | |||
| Liabilities | |||||||
| Current liabilities | |||||||
| Accounts payable | $ | 385,670 | $ | 398,482 | |||
| Current portion of long-term debt | 80,600 | 80,600 | |||||
| Derivative financial liabilities | — | 10,421 | |||||
| Current portion of lease liabilities | 12,087 | 13,664 | |||||
| 478,357 | 503,167 | ||||||
| Long-term debt | 105,429 | 178,916 | |||||
| Asset retirement obligation | 125,452 | 114,662 | |||||
| Lease liabilities | 14,333 | 9,262 | |||||
| Deferred income tax liability | 117,556 | 55,361 | |||||
| Total Liabilities | 841,127 | 861,368 | |||||
| Shareholders’ Equity | |||||||
| Share capital – authorized unlimited common shares, no par value | |||||||
| Issued and outstanding: December 31, 2023 – 202 million shares | |||||||
|   December 31, 2022 – 217 million shares | 2,692,053 | 2,837,329 | |||||
| Paid-in capital | 44,499 | 50,457 | |||||
| Accumulated deficit | (1,207,862) | (1,509,832) | |||||
| Accumulated other comprehensive loss | (301,341) | (301,341) | |||||
| 1,227,349 | 1,076,613 | ||||||
| Total Liabilities & Shareholders’ Equity | $ | 2,068,476 | $ | 1,937,981 | |||
Condensed Consolidated Statements of Income/(Loss) and Comprehensive Income/(Loss)
| For the year ended December 31 (US$ thousands) | 2023 | 2022 | 2021 | |||||||
| Revenues | ||||||||||
| Crude oil and natural gas sales | $ | 1,663,016 | $ | 2,353,374 | $ | 1,482,575 | ||||
| Commodity derivative instruments gain/(loss) | 31,317 | (197,686) | (274,432) | |||||||
| 1,694,333 | 2,155,688 | 1,208,143 | ||||||||
| Expenses | ||||||||||
| Operating | 389,677 | 365,701 | 292,433 | |||||||
| Transportation | 145,576 | 154,658 | 128,309 | |||||||
| Production taxes | 135,131 | 166,995 | 101,953 | |||||||
| General and administrative | 65,664 | 69,954 | 56,807 | |||||||
| Depletion, depreciation, accretion and impairment | 377,495 | 309,367 | 274,756 | |||||||
| Interest | 17,597 | 24,553 | 27,395 | |||||||
| Foreign exchange (gain)/loss | 60 | 10,159 | (6,908) | |||||||
| Gain on divestment of assets | — | (151,937) | — | |||||||
| Transaction costs and other expense/(income) | (4,297) | (1,360) | (2,487) | |||||||
| 1,126,903 | 948,090 | 872,258 | ||||||||
| Income/(Loss) Before Taxes | 567,430 | 1,207,598 | 335,885 | |||||||
| Current income tax expense/(recovery) | 27,183 | 28,063 | 2,689 | |||||||
| Deferred income tax expense/(recovery) | 84,171 | 265,233 | 98,755 | |||||||
| Net Income/(Loss) | $ | 456,076 | $ | 914,302 | $ | 234,441 | ||||
| Other Comprehensive Income/(Loss) | ||||||||||
| Unrealized gain/(loss) on foreign currency translation | — | 22,507 | (6,893) | |||||||
| Foreign exchange gain/(loss) on net investment hedge, net of tax | — | (26,541) | 4,097 | |||||||
| Total Comprehensive Income/(Loss) | $ | 456,076 | $ | 910,268 | $ | 231,645 | ||||
| Net Income/(Loss) per Share | ||||||||||
| Basic | $ | 2.16 | $ | 3.91 | $ | 0.93 | ||||
| Diluted | $ | 2.09 | $ | 3.77 | $ | 0.90 | ||||
Condensed Consolidated Statements of Cash Flows
| For the year ended December 31 (US$ thousands) | 2023 | 2022 | 2021 | |||||||
| Operating Activities | ||||||||||
| Net income/(loss) | $ | 456,076 | $ | 914,302 | $ | 234,441 | ||||
| Non-cash items add/(deduct): | ||||||||||
| Depletion, depreciation, accretion and impairment | 377,495 | 309,367 | 274,756 | |||||||
| Unrealized (gain)/loss on derivative instruments | 25,621 | (150,526) | 109,536 | |||||||
| Deferred income tax expense/(recovery) | 84,171 | 265,233 | 98,755 | |||||||
| Unrealized foreign exchange (gain)/loss on working capital | 363 | 11,217 | (8,055) | |||||||
| Share-based compensation and general and administrative | 17,320 | 22,529 | 13,424 | |||||||
| Other expense/(income) | 2,125 | (4,137) | (4,594) | |||||||
| Amortization of debt issuance costs | 1,556 | 1,476 | 1,093 | |||||||
| Translation of U.S. dollar cash held in parent company | — | (937) | (2,330) | |||||||
| Gain on divestment of assets | — | (151,937) | — | |||||||
| Investing activities in Other income | (3,484) | 13,702 | (4,593) | |||||||
| Asset retirement obligation settlements | (14,999) | (17,401) | (12,951) | |||||||
| Changes in non-cash operating working capital | (8,054) | (39,506) | (94,643) | |||||||
| Cash flow from/(used in) operating activities | 938,190 | 1,173,382 | 604,839 | |||||||
| Financing Activities | ||||||||||
| Drawings from/(repayment of) bank credit facilities | 5,900 | (341,655) | 395,379 | |||||||
| Repayment of senior notes | (80,600) | (100,600) | (81,600) | |||||||
| Purchase of common shares under Normal Course Issuer Bid | (258,276) | (410,906) | (123,182) | |||||||
| Proceeds from the issuance of shares | — | — | 98,339 | |||||||
| Share-based compensation – tax withholdings settled in cash | (16,720) | (13,386) | (3,551) | |||||||
| Dividends | (48,603) | (41,597) | (32,284) | |||||||
| Cash flow from/(used in) financing activities | (398,299) | (908,144) | 253,101 | |||||||
| Investing Activities | ||||||||||
| Capital and office expenditures | (544,771) | (429,873) | (271,131) | |||||||
| Bruin acquisition | — | — | (420,249) | |||||||
| Dunn County acquisition | — | — | (305,076) | |||||||
| Canadian divestments | 35,847 | 158,033 | — | |||||||
| Property and land acquisitions | (7,342) | (22,515) | (9,846) | |||||||
| Property and land divestments | 5,469 | 18,385 | 108,193 | |||||||
| Other (expense)/income | — | (13,702) | 4,593 | |||||||
| Cash flow from/(used in) investing activities | (510,797) | (289,672) | (893,516) | |||||||
| Effect of exchange rate changes on cash and cash equivalents | (363) | 1,086 | 6,979 | |||||||
| Change in cash and cash equivalents | 28,731 | (23,348) | (28,597) | |||||||
| Cash and cash equivalents, beginning of year | 38,000 | 61,348 | 89,945 | |||||||
| Cash and cash equivalents, end of year | $ | 66,731 | $ | 38,000 | $ | 61,348 | ||||
About Enerplus
Enerplus is an independent North American oil and gas exploration and production company focused on creating long-term value for its shareholders through a disciplined, returns-based capital allocation strategy and a commitment to safe, responsible operations. For more information, visit the Company’s website at www.enerplus.com.
NOTICE REGARDING INFORMATION CONTAINED IN THIS NEWS RELEASE
Currency and Accounting Principles
All amounts in this news release are stated in U.S. dollars unless otherwise specified. All financial information in this news release has been prepared and presented in accordance with U.S. GAAP, except as noted below under “Non-GAAP and Other Financial Measures”.
Barrels of Oil Equivalent
This news release contains references to “BOE” (barrels of oil equivalent), “MBOE” (one thousand barrels of oil equivalent), and “MMBOE” (one million barrels of oil equivalent). Enerplus has adopted the standard of six thousand cubic feet of gas to one barrel of oil (6 Mcf: 1 bbl) when converting natural gas to BOEs. BOE, MBOE and MMBOE may be misleading, particularly if used in isolation. The foregoing conversion ratios are based on an energy equivalency conversion method primarily applicable at the burner tip and do not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading.
Presentation of Production and Reserves Information
All production volumes presented in this news release are reported on a “net” basis (the Company’s working interest share after deduction of royalty obligations, plus the Company’s royalty interests), unless expressly indicated that it is being presented on a “gross” basis.
All reserves information presented herein are reported in accordance with Canadian reserve evaluation standards under National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“Canadian NI 51-101 Standards”), except certain reserves information effective December 31, 2023 in accordance with the provisions of the Financial Accounting Standards Board’s ASC Topic 932 Extractive Activities – Oil and Gas, which generally utilize definitions and estimations of proved reserves that are consistent with Rule 4-10 of Regulation S-X promulgated by the U.S. Securities and Exchange Commission (collectively, the “U.S. Rules”), but does not necessarily include all of the disclosure required by the SEC disclosure standards set forth in Subpart 1200 of Regulation S-K (the “U.S. Standards”). The practice of preparing production and reserves data under the Canadian NI 51-101 Standards differs from the U.S. Rules and the presentation of production and reserves data under the Canadian Standards differs from presentation under the U.S. Standards. Please refer to our reserves news release dated as of the date hereof for further information.
All references to “liquids” in this news release include light and medium crude oil, heavy oil and tight oil (all together referred to as “crude oil”) and NGLs on a combined basis. All references to “natural gas” in this news release include conventional natural gas and shale gas on a combined basis.
Enerplus’ oil and gas reserves statement for the year ended December 31, 2023, which will include complete disclosure of our oil and gas reserves and other oil and gas information prepared under the Canadian NI 51-101 Standards and also certain information about our oil and gas reserves prepared in accordance with the U.S. Rules, is contained within our Annual Information Form (AIF) for the year ended December 31, 2023 which is available on our website at www.enerplus.com and under our SEDAR+ profile at www.sedarplus.ca. Additionally, our AIF forms part of our Form 40-F that is filed with the U.S. Securities and Exchange Commission and is available on EDGAR at www.sec.gov. Readers are also urged to review the Management’s Discussion & Analysis and financial statements filed on SEDAR+ and as part of our Form 40-F on EDGAR concurrently with this news release for more complete disclosure on our operations.
FORWARD-LOOKING INFORMATION AND STATEMENTS
This news release contains certain forward-looking information and statements (“forward-looking information”) within the meaning of applicable securities laws. The use of any of the words “expect”, “anticipate”, “continue”, “estimate”, “guidance”, “ongoing”, “may”, “will”, “project”, “intend”, “plans”, “budget”, “strategy” and similar expressions are intended to identify forward-looking information. In particular, but without limiting the foregoing, this news release contains forward-looking information pertaining to the following: expected transaction with Chord, including timing for completion thereof and its effect on Enerplus; expected 2024 capital spending and average production volumes, the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting our cash flow from operating activities and adjusted funds flow; the results from our drilling program and the timing of related production and ultimate well recoveries; our ESG initiatives, including Scope 1 and Scope 2 GHG emissions and methane emissions intensity, gas flare reduction targets and health and safety targets; our anticipated progress towards our ESG initiatives, including timing and expected capital expenditures needed to achieve such targets; future environmental expenses; future debt and working capital levels and net debt to adjusted funds flow ratio and adjusted payout ratio, financial capacity, liquidity and capital resources to fund capital spending and working capital requirements; and our future acquisitions and dispositions.
The forward-looking information contained in this news release reflects several material factors and expectations and assumptions of Enerplus including, without limitation: the ability to fund our return of capital plans, including dividends at the current level, from free cash flow as expected; changes in strategies regarding our return of capital plans; that we will conduct our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; that lack of adequate infrastructure will not result in curtailment of production and/or reduced realized prices beyond our current expectations; current and anticipated commodity prices, differentials and cost assumptions; expectations regarding inflation; the general continuance of current or, where applicable, assumed industry conditions; the impact of inflation, weather conditions, storage fundamentals and expectations regarding the duration and overall impact of the continued conflicts in Ukraine and the Middle East; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve and contingent resource volumes; expectations regarding our share price; the continued availability of adequate debt and/or equity financing and adjusted funds flow to fund our capital, operating and working capital requirements, and dividend payments as needed; the continued availability and sufficiency of our adjusted funds flow and availability under our bank credit facility to fund our non-cash working capital deficit; our ability to comply with our debt covenants; our ability to meet the targets associated with our bank credit facilities; the availability of third party services; the extent of our liabilities; estimates relating to our methane and GHG emissions intensity; and the availability of technology and process to achieve environmental targets; In addition, our 2024 outlook contained in this news release is based on the following: a WTI price of $75.00/bbl, a NYMEX price of $2.50/Mcf and a CDN/US exchange rate of 0.75. Enerplus believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.
The forward-looking information included in this news release is not a guarantee of future performance and should not be unduly relied upon. Such information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information including, without limitation: failure to complete the proposed transaction with Chord; continued instability, or further deterioration, in global economic and market conditions, including from inflation and/or Ukraine/Russia conflict, the Middle East conflict and heightened geopolitical risk; decreases in commodity prices or volatility in commodity prices; changes in realized prices of Enerplus’ products from those currently anticipated; changes in the demand for or supply of our products, including global energy demand and including as a result of ongoing disruptions to global supply chains; volatility in our share trading price and free cash flow that could impact our planned dividend levels; unanticipated operating results, results from our capital spending activities or production declines; curtailment of our production due to low realized prices or lack of adequate infrastructure; changes in tax or environmental laws, royalty rates or other regulatory matters and increased capital and operating costs resulting therefrom; inability to comply with applicable environmental government regulations or regulatory approvals and resulting compliance and enforcement actions; changes in our capital plans or by third party operators of our properties; increased debt levels or debt service requirements; inability to comply with debt covenants under our bank credit facilities and outstanding senior notes; inaccurate estimation of our oil and gas reserve and contingent resource volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors, reliance on industry partners and third party service providers; failure to realize the anticipated benefits of the divestment of the Canadian assets; changes in law or government programs or policies in Canada or the United States; and certain other risks detailed from time to time in our public disclosure documents (including, without limitation, those risks identified in our Management’s Discussion & Analysis and Annual Information Form and Form 40-F as at December 31, 2023).
The forward-looking information contained in this news release speaks only as of the date of this news release, and we do not assume any obligation to publicly update or revise such forward-looking information to reflect new events or circumstances, except as may be required pursuant to applicable laws.
NON-GAAP AND OTHER FINANCIAL MEASURESÂ
Non-GAAP Financial Measures
This news release includes references to certain non-GAAP financial measures and non-GAAP ratios used by the Company to evaluate its financial performance, financial position or cash flow. Non-GAAP financial measures are financial measures disclosed by a company that (a) depict historical or expected future financial performance, financial position or cash flow of a company, (b) with respect to their composition, exclude amounts that are included in, or include amounts that are excluded from, the composition of the most directly comparable financial measure disclosed in the primary financial statements of the company, (c) are not disclosed in the financial statements of the company and (d) are not a ratio, fraction, percentage or similar representation. Non-GAAP ratios are financial measures disclosed by a company that are in the form of a ratio, fraction, percentage or similar representation that has a non-GAAP financial measure as one or more of its components, and that are not disclosed in the financial statements of the company.
These non-GAAP financial measures and non-GAAP ratios do not have standardized meanings or definitions as prescribed by U.S. GAAP and may not be comparable with the calculation of similar financial measures by other entities. For each measure, we have: (a) indicated the composition of the measure; (b) identified the most directly comparable GAAP financial measure and provided comparative detail where appropriate; (c) indicated the reconciliation of the measure to the most directly comparable GAAP financial measure to the extent one exists; and (d) provided details on the usefulness of the measure for the reader. These non-GAAP financial measures and non-GAAP ratios should not be considered as a substitute for, or superior to, measures of financial performance prepared in accordance with GAAP.
“Adjusted funds flow” is used by Enerplus and is useful to investors and securities analysts in analyzing Enerplus’ ability to generate funds to repay debt, pay dividends, and fund future capital investment. The most directly comparable GAAP measure is cash flow from operating activities. Adjusted funds flow is calculated as cash flow from operating activities before asset retirement obligation expenditures and changes in non-cash operating working capital.
| Year ended December 31, | |||||||||
| ($Â millions) | 2023 | 2022 | 2021 | ||||||
| Cash flow from/(used in) operating activities | $ | 938.2 | $ | 1,173.4 | $ | 604.8 | |||
| Asset retirement obligation settlements | 15.0 | 17.4 | 13.0 | ||||||
| Changes in non-cash operating working capital | 8.0 | 39.5 | 94.6 | ||||||
| Adjusted funds flow | $ | 961.2 | $ | 1,230.3 | $ | 712.4 | |||
“Adjusted funds flow before tax” is used by Enerplus and is useful to investors and securities analysts in analyzing Enerplus’ current income tax expense as a percentage of adjusted funds flow before tax. The most directly comparable GAAP measure is cash flow from operating activities. Adjusted funds flow before tax is calculated as adjusted funds flow plus current income tax expense.
| Year ended December 31, | |||||||||
| ($Â millions) | 2023 | 2022 | 2021 | ||||||
| Adjusted funds flow(1) | $ | 961.2 | $ | 1,230.3 | $ | 712.4 | |||
| Current income tax expense | 27.2 | 28.1 | 2.7 | ||||||
| Adjusted funds flow before tax | $ | 988.4 | $ | 1,258.4 | $ | 715.1 | |||
| (1) | See adjusted funds flow reconciliation above for a breakdown of the adjustments made to cash flow from/(used in) operating activities. |
“Adjusted net income/(loss)” is used by Enerplus and is useful to investors and securities analysts in evaluating the financial performance of the company by adjusting for certain unrealized items and other items that the company considers appropriate to adjust given their irregular nature. The most directly comparable GAAP measure is net income/(loss).
| Year ended December 31, | |||||||||
| ($Â millions) | 2023 | 2022 | 2021 | ||||||
| Net income/(loss) | $ | 456.1 | $ | 914.3 | $ | 234.4 | |||
| Unrealized derivative instrument, foreign exchange and marketable securities (gain)/loss | 29.7 | (141.7) | 101.4 | ||||||
| Gain on divestment of assets | — | (151.9) | — | ||||||
| Other expense/(income) related to investing activities | (2.2) | 13.6 | (4.6) | ||||||
| Income tax rate adjustment on deferred taxes | — | 8.8 | 6.0 | ||||||
| Asset impairment | — | — | 3.4 | ||||||
| Tax effect on above items | (6.0) | 64.0 | (24.9) | ||||||
| Adjusted net income/(loss) | $ | 477.6 | $ | 707.1 | $ | 315.7 | |||
“Free cash flow” is used by Enerplus and is useful to investors and securities analysts in analyzing operating and financial performance, leverage and liquidity. Free cash flow is calculated as adjusted funds flow minus capital spending. The most directly comparable GAAP measure is cash flow from operating activities.
| Year ended December 31, | ||||||||||||||||||||||
| ($Â millions) | 2023 | 2022 | 2021 | |||||||||||||||||||
| Adjusted funds flow(1) | $ | 961.2 | $ | 1,230.3 | $ | 712.4 | ||||||||||||||||
| Capital spending | (532.5) | (432.0) | (302.3) | |||||||||||||||||||
| Free cash flow | $ | 428.7 | $ | 798.3 | $ | 410.1 | ||||||||||||||||
| (1) | See adjusted funds flow reconciliation above for a breakdown of the adjustments made to cash flow from/(used in) operating activities. |
“Net debt” is used by Enerplus and is useful to investors and securities analysts in analyzing overall leverage and financial position at the end of the period. Net debt is calculated as current and long-term debt associated with senior notes plus any outstanding Bank Credit Facilities balances, less cash and cash equivalents. There is no directly comparable GAAP equivalent.
| Year ended December 31, | ||||||
| ($Â millions) | 2023 | 2022 | ||||
| Current portion of long-term debt | $ | 80.6 | $ | 80.6 | ||
| Long-term debt | 105.4 | 178.9 | ||||
| Less: Cash and cash equivalents | (66.7) | (38.0) | ||||
| Net debt | $ | 119.3 | $ | 221.5 | ||
“Net debt to adjusted funds flow ratio” is used by Enerplus and is useful to investors and securities analysts in analyzing leverage and liquidity. The net debt to adjusted funds flow ratio is calculated as net debt divided by a trailing twelve months of adjusted funds flow. There is no directly comparable GAAP equivalent for this measure, and it is not equivalent to any of our debt covenants.
| Year ended December 31, | ||||||
| ($Â millions) | 2023 | 2022 | ||||
| Net debt(1) | $ | 119.3 | $ | 221.5 | ||
| Trailing adjusted funds flow | 961.2 | 1,230.3 | ||||
| Net debt to adjusted funds flow ratio | 0.1x | 0.2x | ||||
| (1) | See net debt reconciliation above. |
Other Financial Measures
SUPPLEMENTARY FINANCIAL MEASURES
Supplementary financial measures are financial measures disclosed by a company that (a) are, or are intended to be, disclosed on a periodic basis to depict the historical or expected future financial performance, financial position or cash flow of a company, (b) are not disclosed in the financial statements of the company, (c) are not non-GAAP financial measures, and (d) are not non-GAAP ratios. The following section provides an explanation of the composition of those supplementary financial measures if not previously provided:
“Capital spending” Capital and office expenditures, excluding other capital assets/office capital and property and land acquisitions and divestments and non-cash investing working capital.
“Cash general and administrative expenses” or “Cash G&A expenses” General and administrative expenses that are settled through cash payout, as opposed to expenses that relate to accretion or other non-cash allocations that are recorded as part of general and administrative expenses.
“Cash share-based compensation” or “Cash SBC expenses” Share-based compensation that is settled by way of cash payout, as opposed to equity settled.
Electronic copies of Enerplus’ 2023 MD&A and Financial Statements, along with other public information including investor presentations, are available on the Company’s website at www.enerplus.com. For further information, please contact Investor Relations at 1-800-319-6462 or email investorrelations@enerplus.com.
SOURCE Enerplus Corporation
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