All amounts in this news release are presented in United States dollars unless otherwise specified. All financial information contained within this news release has been prepared in accordance with U.S. GAAP. Production information, unless otherwise stated, is presented on a net basis (after deduction of royalty obligations). This news release includes forward-looking statements and information within the meaning of applicable securities laws. Readers are advised to review the “Forward-Looking Information and Statements” at the conclusion of this news release. Readers are also referred to “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 and “Notice Regarding Information Contained in this News Release”, “Non-GAAP Measures” in Enerplus’ second quarter 2023 MD&A for supplementary financial measures, which information is incorporated by reference to this news release. A copy of Enerplus’ 2023 interim and 2022 annual Financial Statements and associated MD&A are or will be available on our website at www.enerplus.com, under our profile on SEDAR+ at www.sedarplus.com and on the EDGAR website at www.sec.gov.
CALGARY, AB, Aug. 9, 2023 /CNW/ – Enerplus Corporation (“Enerplus” or the “Company”) (TSX: ERF) (NYSE: ERF) today announced second quarter of 2023 results, updated 2023 guidance and return of capital plans, and an increased dividend. The Company reported second quarter 2023 cash flow from operating activities and adjusted funds flow of $186.6 million and $196.6 million, respectively, compared to $250.9 million and $297.4 million, respectively, in the second quarter of 2022. Cash flow from operating activities and adjusted funds flow decreased from the prior year period primarily due to lower commodity prices.
HIGHLIGHTS
- Second quarter production averaged 95.6 MBOE per day, including 58.2 Mbbl per day of liquids
- Production per share increased by 14% in the second quarter of 2023 compared to the same period in 2022
- Total production guidance for full-year 2023 was increased to 94.5 – 98.5 MBOE per day (from 93.0 – 98.0 MBOE per day), with liquids production guidance increased to 58.5 – 61.5 Mbbl per day (from 57.0 – 61.0 Mbbl per day) due to strong well performance
- Robust oil production growth is anticipated in the second half of 2023: approximately 10% liquids production growth is expected in the third quarter compared to the second quarter
- Returned $66.5 million to shareholders in the second quarter through dividends and share repurchases. Through the first half of 2023, Enerplus returned $133.1 million to shareholders, representing 97% of free cash flow(1)
- Planning to return at least 60% of second half 2023 free cash flow to shareholders which is expected to result in over 70% of full-year 2023 free cash flow returned to shareholders, based on current commodity prices
- Increased quarterly dividend by 9% to $0.06 per share
- Normal course issuer bid (“NCIB”) was completed having repurchased the maximum 10% of the public float between August 2022 and July 2023. The Company plans to renew its NCIB in August 2023 for another 10% of the public float
- Capital spending guidance range for 2023 was narrowed to $510 – $550 million (from $500 – $550 million)
| (1) This is a non-GAAP financial measure. Refer to “Non-GAAP and Other Financial Measures” section for more information. |
“Enerplus’ second quarter results and updated 2023 outlook reflect our strong operating momentum,” said Ian C. Dundas, President and CEO. “Our setup for the second half of 2023 is compelling. We anticipate robust oil production growth and a free cash flow profile that is approximately double what we generated during the first half of the year. With this outlook and our strong financial position, we plan to continue to return a meaningful proportion of free cash flow to shareholders through the balance of the year.”
SECOND QUARTER SUMMARY
Production in the second quarter of 2023 was 95,572 BOE per day, a decrease of 2% compared to the first quarter of 2023 and 2% higher than the same period a year ago. Crude oil and natural gas liquids production in the second quarter of 2023 was 58,214 barrels per day, an increase of 3% and 2% compared to the prior quarter and the same period a year ago, respectively. The increased production compared to the same period in 2022 was primarily driven by new wells online in North Dakota, partially offset by lower natural gas production in the Marcellus due to limited capital activity in 2023, and was despite the sale of the Company’s Canadian assets in the fourth quarter of 2022.
Enerplus reported second quarter 2023 net income of $74.2 million, or $0.35 per share (basic), compared to net income of $244.4 million, or $1.01 per share (basic), in the same period in 2022. Adjusted net income(1) for the second quarter of 2023 was $84.4 million, or $0.39 per share (basic), compared to $172.3 million, or $0.72 per share (basic), during the same period in 2022. Net income and adjusted net income were lower compared to the prior year period primarily due to higher commodity prices during the second quarter of 2022.
Enerplus’ second quarter 2023 realized Bakken oil price differential was $0.71 per barrel below WTI, compared to $0.85 per barrel above WTI in the second quarter of 2022. The weaker realized differential was due to lower prices for crude oil delivered to markets in both North Dakota and the U.S. Gulf Coast primarily due to weaker U.S. refinery margins early in the quarter. U.S. refinery utilization recovered later in the second quarter supported by resilient domestic product demand. Enerplus expects its annual realized Bakken crude oil price differential to be at par with WTI (prior guidance was $0.50 per barrel above WTI).
The Company’s realized Marcellus natural gas price differential was $0.68 per Mcf below NYMEX during the second quarter of 2023, compared to $0.59 per Mcf below NYMEX in the second quarter of 2022. Enerplus continues to expect its 2023 Marcellus natural gas price differential to average $0.75 per Mcf below NYMEX.
In the second quarter of 2023, Enerplus’ operating costs were $10.25 per BOE, compared to $9.74 per BOE during the second quarter of 2022. The increase in per unit operating expenses compared to the same period in 2022 was due to inflation adjusted contract pricing, increased gas processing volumes due to improved capture rates, higher planned well service activity and lower natural gas production in the Marcellus. Enerplus is updating its 2023 operating expense guidance to $10.75 – $11.50 per BOE (from $10.75 – $11.75 per BOE) to reflect lower operating expenses through the first half of the year, along with higher planned workover activity and an increased liquids production weighting in the second half of the year.
Capital spending totaled $180.9 million in the second quarter of 2023. In addition, Enerplus paid $11.8 million in dividends in the quarter and repurchased 3.8 million shares at an average price of $14.45 per share, for total consideration of $54.8 million. During July 2023, Enerplus repurchased the remaining 0.5 million shares under its NCIB at an average price of $14.63 per share, for total consideration of $7.9 million. This was the second consecutive year of repurchasing the maximum number of shares allowed under an NCIB.
Current tax expense was $3.5 million in the second quarter. Enerplus reduced its full-year 2023 current tax expense guidance to 3 – 4% of adjusted funds flow before tax (from 5 – 6%) due to lower than forecast realized commodity prices year to date.
Enerplus ended the second quarter of 2023 with net debt of $199.6 million and a net debt to adjusted funds flow ratio of 0.2 times.
| (1) This is a non-GAAP financial measure. Refer to “Non-GAAP and Other Financial Measures” section for more information. |
OPERATIONS
North Dakota production averaged 68,938 BOE per day during the second quarter of 2023, an increase of 18% compared to the same period a year ago and 3% higher compared to the previous quarter. During the second quarter, Enerplus drilled 17 gross operated wells (92% average working interest) and brought 23 gross operated wells (86% average working interest) on production. In addition, the Company completed 4 refracs (75% average working interest) in the quarter.
The wells brought on production in the second quarter included Enerplus’ first two operated pads in the Little Knife area. Early time performance has been strong — nine of these wells have had at least 30 days on production and have averaged a gross peak 30-day rate per well of 1,900 barrels of oil per day (2,900 BOE per day on a three-stream basis).
Enerplus expects to bring approximately 14 – 17 net operated wells on production in North Dakota in the third quarter.
RETURN OF CAPITAL TO SHAREHOLDERS
During the first six months of 2023, Enerplus returned $133.1 million to shareholders through share repurchases and dividends representing 97% of free cash flow. Given the Company’s strong balance sheet and the robust free cash flow profile expected during the second half of the year, Enerplus plans to return at least 60% of its second half 2023 free cash flow to shareholders, which is expected to result in over 70% of full year 2023 free cash flow returned.
Based on current market conditions, Enerplus plans to continue to prioritize share repurchases for the majority of its return of capital through 2023. In connection with this plan, the Board of Directors approved the renewal of the Company’s NCIB to repurchase another 10% of the public float in the next 12-month period.
Additionally, the Board of Directors approved a 9% increase to the quarterly dividend to $0.06 per share to be paid in September 2023, for shareholders of record on August 31, 2023.
Remaining free cash flow not allocated to shareholder returns is expected to be directed to reinforcing the balance sheet.
ENVIRONMENTAL, SOCIAL AND GOVERNANCE UPDATE
As highlighted with the release of its 2023 ESG report in June 2023, Enerplus is delivering meaningful reductions to its greenhouse gas (“GHG”) emissions profile through its flaring reduction and engine and power initiatives. The Company anticipates a reduction to its 2023 scope 1 and 2 GHG emissions intensity of approximately 30% compared to 2021 (representing an approximate 50% reduction compared to 2019). Given this performance, the Company anticipates achieving its 2030 GHG emissions intensity reduction target as early as 2024 and plans to provide an updated long-term target in due course.
2023 GUIDANCE UPDATE AND THIRD QUARTER OUTLOOK
Enerplus’ updated 2023 guidance is provided in the tables below.
Enerplus increased its total production guidance to 94,500 – 98,500 BOE per day, from the prior guidance of 93,000 – 98,000 BOE per day. Liquids production guidance was increased to 58,500 – 61,500 barrels per day, from the prior guidance of 57,000 – 61,000 barrels per day. The increase to production guidance reflects strong well performance in North Dakota.
The execution of the Company’s capital program remains on schedule and budget. Capital spending guidance has been narrowed to $510 – $550 million, from $500 – $550 million.
Enerplus is anticipating strong oil production growth in the second half of 2023. Third quarter liquids production is expected to be approximately 10% higher than the second quarter, with an oil weighting of approximately 82%. Natural gas production is anticipated to be modestly lower in the third quarter, compared to the second quarter, due to lower production from the Marcellus.
2023 Guidance Summary
| Updated Guidance | Previous Guidance | |||
| Capital spending | $510 – 550 million | $500 – 550 million | ||
| Average total production | 94,500 – 98,500 BOE/day | 93,000 – 98,000 BOE/day | ||
| Average liquids production | 58,500 – 61,500 bbls/day | 57,000 – 61,000 bbls/day | ||
| Average production tax rate
(% of net sales, before transportation) |
8 % | 7-8% | ||
| Operating expense | $10.75 – 11.50/BOE | $10.75 – 11.75/BOE | ||
| Transportation expense | $4.20/BOE (No change) | $4.20/BOE | ||
| Cash G&A expense | $1.35/BOE (No change) | $1.35/BOE | ||
| Current tax expense | 3-4% of adjusted funds flow, before tax | 5-6% of adjusted funds flow, before tax |
2023 Differential/Basis Outlook(1)
| Updated Guidance | Previous Guidance | |
| U.S. Bakken crude oil differential
(compared to WTI crude oil) |
Par with WTI | +$0.50/bbl |
| Marcellus natural gas sales price differential
(compared to last day NYMEX natural gas) |
$(0.75)/Mcf (No change) | $(0.75)/Mcf |
| (1) | Excluding transportation costs. |
Q2 2023 Conference Call Details
A conference call hosted by Ian C. Dundas, President and CEO will be held at 9:00 AM MT (11:00 AM ET) on Thursday, August 10, 2023, to discuss these results. Details of the conference call are as follows:
To immediately join the conference call by phone, without operator assistance, please use the following URL to register and be connected into the conference call by automated call back: https://emportal.ink/3XaahvI.
To join the call from a live operator managed queue, please dial 1-888-390-0546 (Toll Free) using conference ID 32077979.
To ensure timely participation in the conference call, callers are encouraged to join 15 minutes prior to the start time to register for the event. A telephone replay will be available for 30 days following the conference call and can be accessed at the following numbers:
Replay Dial-In: 1-888-390-0541 (Toll Free)
Replay Passcode: 077979 #
PRICE RISK MANAGEMENT
The following is a summary of Enerplus’ financial commodity hedging contracts at August 8, 2023.
| WTI Crude Oil ($/bbl) (1)(2) | NYMEX Natural Gas ($/Mcf)(2) | ||||
| Jul 1, 2023 – | Jul 1, 2023 – | ||||
| Dec 31, 2023 | Oct 31, 2023 | ||||
| Swaps | |||||
| Volume (bbls/day) | 10,000 | – | |||
| Brent – WTI Spread | $ 5.47 | – | |||
| 3 Way Collars | |||||
| Volume (bbls/day) | 5,000 | – | |||
| Sold Puts | $ 65.00 | – | |||
| Purchased Puts | $ 85.00 | – | |||
| Sold Calls | $ 128.16 | – | |||
| Collars | |||||
| Volume (Mcf/day) | – | 50,000 | |||
| Volume (bbls/day)(3) | 2,000 | – | |||
| Purchased Puts | $ 5.00 | $ 4.05 | |||
| Sold Calls | $ 75.00 | $ 7.00 |
| (1) | The total average deferred premium spent on outstanding hedges is $1.07/bbl from July 1, 2023 – December 31, 2023. |
| (2) | Transactions with a common term have been aggregated and presented at weighted average prices and volumes. |
| (3) | Outstanding commodity derivative instruments acquired as part of the Company’s acquisition of Bruin E&P Holdco, LLC completed in 2021. |
SECOND QUARTER 2023 PRODUCTION AND OPERATIONAL SUMMARY TABLES
Summary of Average Daily Production(1)
| Three months ended June 30, 2023 | Six months ended June 30, 2023 | |||||||||
| Williston Basin | Marcellus | Other(2) | Total | Williston Basin | Marcellus | Other(2) | Total | |||
| Tight oil (bbl/d) | 46,749 | – | 680 | 47,430 | 46,687 | – | 712 | 47,399 | ||
| Total crude oil (bbl/d) | 46,749 | – | 680 | 47,430 | 46,687 | – | 712 | 47,399 | ||
| Natural gas liquids (bbl/d) | 10,666 | – | 118 | 10,784 | 9,975 | – | 104 | 10,079 | ||
| Shale gas (Mcf/d) | 69,142 | 154,211 | 797 | 224,149 | 66,849 | 167,126 | 795 | 234,770 | ||
| Total natural gas (Mcf/d) | 69,142 | 154,211 | 797 | 224,149 | 66,849 | 167,126 | 795 | 234,770 | ||
| Total production (BOE/d) | 68,938 | 25,702 | 931 | 95,572 | 67,804 | 27,854 | 949 | 96,606 | ||
| (1) | Table may not add due to rounding. |
| (2) | Comprises DJ Basin. |
Summary of Wells Drilled(1)
| Three months ended June 30, 2023 |
Six months ended June 30, 2023 |
||||||||||
| Operated | Non-Operated | Operated | Non-Operated | ||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||
| Williston Basin | 17 | 15.6 | 36 | 5.0 | 31 | 27.6 | 54 | 6.5 | |||
| Marcellus | – | – | 14 | 0.2 | – | – | 26 | 0.4 | |||
| DJ Basin | 1 | 1.0 | – | – | 3 | 2.9 | – | – | |||
| Total | 18 | 16.6 | 50 | 5.2 | 34 | 30.5 | 80 | 6.9 | |||
| (1) | Table may not add due to rounding. |
Summary of Wells Brought On-Stream(1)
| Three months ended June 30, 2023 |
Six months ended June 30, 2023 |
||||||||||
| Operated | Non-Operated | Operated | Non-Operated | ||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||
| Williston Basin | 23 | 19.8 | 11 | 3.1 | 27 | 22.8 | 14 | 3.2 | |||
| Marcellus | – | – | 8 | 0.1 | – | – | 21 | 0.3 | |||
| DJ Basin | – | – | 10 | 0.2 | – | – | 10 | 0.2 | |||
| Total | 23 | 19.8 | 29 | 3.4 | 27 | 22.8 | 45 | 3.7 | |||
| (1) | Table may not add due to rounding. |
| Three months ended | Six months ended | |||||||||||
| SELECTED FINANCIAL RESULTS | June 30, | June 30, | ||||||||||
| 2023 | 2022 | 2023 | 2022 | |||||||||
| Financial (US$, thousands, except ratios) | ||||||||||||
| Net Income/(Loss) | $ | 74,233 | $ | 244,406 | $ | 211,719 | $ | 277,649 | ||||
| Adjusted Net Income(1) | 84,405 | 172,251 | 225,151 | 318,079 | ||||||||
| Cash Flow from Operating Activities | 186,598 | 250,860 | 427,999 | 446,852 | ||||||||
| Adjusted Funds Flow | 196,624 | 297,393 | 457,033 | 559,288 | ||||||||
| Dividends to Shareholders – Declared | 11,756 | 9,940 | 23,749 | 17,858 | ||||||||
| Net Debt | 199,630 | 545,983 | 199,630 | 545,983 | ||||||||
| Capital Spending | 180,942 | 132,884 | 319,590 | 231,898 | ||||||||
| Property and Land Acquisitions | 1,638 | 1,469 | 3,386 | 3,410 | ||||||||
| Property and Land Divestments | (94) | 8,591 | 139 | 15,172 | ||||||||
| Net Debt to Adjusted Funds Flow Ratio | 0.2x | 0.5x | 0.2x | 0.5x | ||||||||
| Financial per Weighted Average Shares Outstanding | ||||||||||||
| Net Income/(Loss) – Basic | $ | 0.35 | $ | 1.01 | $ | 0.98 | $ | 1.15 | ||||
| Net Income/(Loss) – Diluted | 0.34 | 0.99 | 0.96 | 1.12 | ||||||||
| Weighted Average Number of Shares Outstanding (000’s) – Basic | 213,790 | 239,277 | 215,289 | 241,022 | ||||||||
| Weighted Average Number of Shares Outstanding (000’s) – Diluted | 219,732 | 247,216 | 221,276 | 248,957 | ||||||||
| Selected Financial Results per BOE(2)(3) | ||||||||||||
| Crude Oil & Natural Gas Sales(4) | $ | 40.35 | $ | 73.31 | $ | 43.70 | $ | 67.67 | ||||
| Commodity Derivative Instruments | 1.63 | (16.13) | 2.77 | (12.53) | ||||||||
| Operating Expenses | (10.25) | (9.74) | (10.40) | (9.88) | ||||||||
| Transportation Costs | (3.96) | (4.41) | (4.13) | (4.36) | ||||||||
| Production Taxes | (3.31) | (5.11) | (3.37) | (4.70) | ||||||||
| General and Administrative Expenses | (1.20) | (1.10) | (1.34) | (1.22) | ||||||||
| Cash Share-Based Compensation | (0.01) | (0.04) | 0.05 | (0.14) | ||||||||
| Interest, Foreign Exchange and Other Expenses | (0.24) | (0.67) | (0.31) | (0.67) | ||||||||
| Current Income Tax Expense | (0.40) | (1.40) | (0.83) | (1.01) | ||||||||
| Adjusted Funds Flow | $ | 22.61 | $ | 34.71 | $ | 26.14 | $ | 33.16 | ||||
| Three months ended | Six months ended | |||||||||||
| SELECTED OPERATING RESULTS | June 30, | June 30, | ||||||||||
| 2023 | 2022 | 2023 | 2022 | |||||||||
| Average Daily Production(3) | ||||||||||||
| Crude Oil (bbls/day) | 47,430 | 48,213 | 47,399 | 47,925 | ||||||||
| Natural Gas Liquids (bbls/day) | 10,784 | 8,653 | 10,079 | 8,516 | ||||||||
| Natural Gas (Mcf/day) | 224,149 | 223,653 | 234,770 | 220,400 | ||||||||
| Total (BOE/day) | 95,572 | 94,142 | 96,606 | 93,174 | ||||||||
| % Crude Oil and Natural Gas Liquids | 61 % | 60 % | 59 % | 61 % | ||||||||
| Average Selling Price(3)(4) | ||||||||||||
| Crude Oil (per bbl) | $ | 72.69 | $ | 108.77 | $ | 74.50 | $ | 100.46 | ||||
| Natural Gas Liquids (per bbl) | 15.49 | 33.31 | 17.83 | 35.49 | ||||||||
| Natural Gas (per Mcf) | 1.08 | 6.11 | 2.17 | 5.38 | ||||||||
| Net Wells Drilled | 21.8 | 16.5 | 37.4 | 31.7 | ||||||||
| (1) | This non‑GAAP measure may not be directly comparable to similar measures presented by other entities. See “Non-GAAP and Other FinancialMeasures” section in this news release. |
| (2) | Non‑cash amounts have been excluded. |
| (3) | Based on net production volumes. See “Basis of Presentation” section in this news release. |
| (4) | Before transportation costs and commodity derivative instruments. |
Condensed Consolidated Balance Sheets
| (US$ thousands) unaudited | June 30, 2023 | December 31, 2022 | |||
| Assets | |||||
| Current assets | |||||
| Cash and cash equivalents | $ | 37,475 | $ | 38,000 | |
| Accounts receivable, net of allowance for doubtful accounts | 239,867 | 276,590 | |||
| Other current assets | 56,360 | 56,552 | |||
| Derivative financial assets | 16,163 | 36,542 | |||
| 349,865 | 407,684 | ||||
| Property, plant and equipment: | |||||
| Crude oil and natural gas properties (full cost method) | 1,487,322 | 1,322,904 | |||
| Other capital assets | 9,837 | 10,685 | |||
| Property, plant and equipment | 1,497,159 | 1,333,589 | |||
| Other long-term assets | 10,561 | 21,154 | |||
| Right-of-use assets | 25,042 | 20,556 | |||
| Deferred income tax asset | 143,896 | 154,998 | |||
| Total Assets | $ | 2,026,523 | $ | 1,937,981 | |
| Liabilities | |||||
| Current liabilities | |||||
| Accounts payable | $ | 400,691 | $ | 398,482 | |
| Current portion of long-term debt | 80,600 | 80,600 | |||
| Derivative financial liabilities | 2,195 | 10,421 | |||
| Current portion of lease liabilities | 12,397 | 13,664 | |||
| 495,883 | 503,167 | ||||
| Long-term debt | 156,505 | 178,916 | |||
| Asset retirement obligation | 119,050 | 114,662 | |||
| Lease liabilities | 14,808 | 9,262 | |||
| Deferred income tax liability | 89,264 | 55,361 | |||
| Total Liabilities | 875,510 | 861,368 | |||
| Shareholders’ Equity | |||||
| Share capital – authorized unlimited common shares, no par value
Issued and outstanding: June 30, 2023 – 211 million shares December 31, 2022 – 217 million shares |
2,776,088 | 2,837,329 | |||
| Paid-in capital | 38,963 | 50,457 | |||
| Accumulated deficit | (1,362,697) | (1,509,832) | |||
| Accumulated other comprehensive loss | (301,341) | (301,341) | |||
| 1,151,013 | 1,076,613 | ||||
| Total Liabilities & Shareholders’ Equity | $ | 2,026,523 | $ | 1,937,981 | |
Condensed Consolidated Statements of Income/(Loss) and Comprehensive Income/(Loss)
| Three months ended | Six months ended | |||||||||||||
| June 30, | June 30, | |||||||||||||
| (US$ thousands, except per share amounts) unaudited | 2023 | 2022 | 2023 | 2022 | ||||||||||
| Revenues | ||||||||||||||
| Crude oil and natural gas sales | $ | 350,939 | $ | 628,017 | $ | 764,121 | $ | 1,141,169 | ||||||
| Commodity derivative instruments gain/(loss) | 6,961 | (47,553) | 34,926 | (254,363) | ||||||||||
| 357,900 | 580,464 | 799,047 | 886,806 | |||||||||||
| Expenses | ||||||||||||||
| Operating | 89,116 | 83,366 | 181,920 | 166,610 | ||||||||||
| Transportation | 34,433 | 37,830 | 72,201 | 73,637 | ||||||||||
| Production taxes | 28,765 | 43,827 | 58,888 | 79,182 | ||||||||||
| General and administrative | 15,074 | 14,687 | 34,506 | 32,268 | ||||||||||
| Depletion, depreciation and accretion | 85,117 | 70,090 | 172,226 | 136,781 | ||||||||||
| Interest | 3,592 | 6,098 | 7,910 | 12,153 | ||||||||||
| Foreign exchange (gain)/loss | (794) | (3,232) | (891) | (2,345) | ||||||||||
| Other expense/(income) | 3,728 | (309) | 1,062 | 12,388 | ||||||||||
| 259,031 | 252,357 | 527,822 | 510,674 | |||||||||||
| Income/(Loss) Before Taxes | 98,869 | 328,107 | 271,225 | 376,132 | ||||||||||
| Current income tax expense/(recovery) | 3,500 | 12,000 | 14,500 | 17,000 | ||||||||||
| Deferred income tax expense/(recovery) | 21,136 | 71,701 | 45,006 | 81,483 | ||||||||||
| Net Income/(Loss) | $ | 74,233 | $ | 244,406 | $ | 211,719 | $ | 277,649 | ||||||
| Other Comprehensive Income/(Loss) | ||||||||||||||
| Unrealized gain/(loss) on foreign currency translation | — | 1,977 | — | 1,357 | ||||||||||
| Foreign exchange gain/(loss) on net investment hedge, net of tax |
— | (14,094) | — | (8,719) | ||||||||||
| Total Comprehensive Income/(Loss) | $ | 74,233 | $ | 232,289 | $ | 211,719 | $ | 270,287 | ||||||
| Net Income/(Loss) per Share | ||||||||||||||
| Basic | $ | 0.35 | $ | 1.01 | $ | 0.98 | $ | 1.15 | ||||||
| Diluted | $ | 0.34 | $ | 0.99 | $ | 0.96 | $ | 1.12 | ||||||
Condensed Consolidated Statements of Cash Flows
| Three months ended | Six months ended | ||||||||||
| June 30, | June 30, | ||||||||||
| (US$ thousands) unaudited | 2023 | 2022 | 2023 | 2022 | |||||||
| Operating Activities | |||||||||||
| Net income/(loss) | $ | 74,233 | $ | 244,406 | $ | 211,719 | $ | 277,649 | |||
| Non-cash items add/(deduct): | |||||||||||
| Depletion, depreciation and accretion | 85,117 | 70,090 | 172,226 | 136,781 | |||||||
| Changes in fair value of derivative instruments | 7,247 | (91,275) | 13,591 | 42,057 | |||||||
| Deferred income tax expense/(recovery) | 21,136 | 71,701 | 45,006 | 81,483 | |||||||
| Unrealized foreign exchange (gain)/loss on working capital | (527) | (3,292) | (712) | (2,121) | |||||||
| Share-based compensation and general and administrative | 4,625 | 5,634 | 11,988 | 10,294 | |||||||
| Other expense/(income) | 4,739 | (97) | 3,089 | 12,556 | |||||||
| Amortization of debt issuance costs | 394 | 351 | 788 | 704 | |||||||
| Translation of U.S. dollar cash held in parent company | — | (125) | — | (115) | |||||||
| Investing activities in Other income | (340) | — | (662) | — | |||||||
| Asset retirement obligation settlements | (2,088) | (2,349) | (8,870) | (11,144) | |||||||
| Changes in non-cash operating working capital | (7,938) | (44,184) | (20,164) | (101,292) | |||||||
| Cash flow from/(used in) operating activities | 186,598 | 250,860 | 427,999 | 446,852 | |||||||
| Financing Activities | |||||||||||
| Drawings from/(repayment of) bank credit facilities | 93,505 | 48,709 | 37,189 | (55,700) | |||||||
| Repayment of senior notes | (59,600) | (79,600) | (59,600) | (79,600) | |||||||
| Purchase of common shares under Normal Course Issuer Bid | (54,778) | (92,928) | (109,338) | (130,135) | |||||||
| Share-based compensation – tax withholdings settled in cash | (28) | — | (16,420) | (11,567) | |||||||
| Dividends | (11,756) | (9,940) | (23,749) | (17,858) | |||||||
| Cash flow from/(used in) financing activities | (32,657) | (133,759) | (171,918) | (294,860) | |||||||
| Investing Activities | |||||||||||
| Capital and office expenditures | (174,882) | (115,040) | (268,805) | (190,067) | |||||||
| Canadian divestments | 7,043 | — | 12,234 | — | |||||||
| Property and land acquisitions | (1,638) | (1,469) | (3,386) | (3,410) | |||||||
| Property and land divestments | (94) | (4,462) | 2,639 | 2,119 | |||||||
| Cash flow from/(used in) investing activities | (169,571) | (120,971) | (257,318) | (191,358) | |||||||
| Effect of exchange rate changes on cash and cash equivalents | 527 | 6,545 | 712 | 3,424 | |||||||
| Change in cash and cash equivalents | (15,103) | 2,675 | (525) | (35,942) | |||||||
| Cash and cash equivalents, beginning of period | 52,578 | 22,731 | 38,000 | 61,348 | |||||||
| Cash and cash equivalents, end of period | $ | 37,475 | $ | 25,406 | $ | 37,475 | $ | 25,406 | |||
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.
Basis of Presentation
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 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.
Readers are urged to review the 2023 interim Management’s Discussion & Analysis (MD&A) and financial statements, and 2022 MD&A and financial statements filed on SEDAR+ and as part of our Form 6-K and Form 40-F, respectively, 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”, “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: 2023 production and capital spending guidance; Enerplus’ return of capital plans, including expectations regarding payment of dividends and the source of funds related thereto; the funding of dividends and the share repurchase program from free cash flow; the anticipated percentage of free cash flow planned to be returned to shareholders, based on current commodity prices; expectations regarding Enerplus’ share purchase program, anticipated renewal of the Company’s NCIB based on current market conditions, including the timing and size thereof; expectations regarding the number of net operated wells brought on production in the third quarter of 2023; expected operating strategy in 2023 and expectations regarding our drilling program; expectations regarding oil production growth and free cash flow profile for the remainder of 2023; anticipated reduction levels of Enerplus’ scope 1 and 2 GHG emissions intensities and the timing thereof; oil and natural gas prices and differentials and expectations regarding the market environment and our commodity risk management program in 2023; 2023 Bakken and Marcellus differential guidance; expectations regarding realized oil and natural gas prices; and expected operating, transportation and cash G&A expenses and production taxes and 2023 guidance with respect thereto.
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 both dividends at the current level and the share repurchase program, from free cash flow as expected; that our common share trading price will be at levels, and that there will be no other alternatives, that, in each case, make share repurchases an appropriate and best strategic use of our free cash flows; our ability to achieve, in a timely manner, all necessary regulatory approvals for the renewal of the Company’s NCIB; that we will conduct our operations and achieve results of operations as anticipated; the continued operation of the Dakota Access Pipeline; 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; the general continuance of current or, where applicable, assumed industry conditions, the impact of inflation, weather conditions and storage fundamentals; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve and contingent resource volumes; 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; our ability to comply with our debt covenants; our ability to meet the targets associated with our credit facilities; the availability of third party services; expected transportation expenses; the extent of our liabilities; and the availability of technology and process to achieve environmental targets.
In addition, our 2023 guidance described in this news release is based on rest of year commodity prices of: a WTI price of $80.00/bbl, a NYMEX price of $3.00/Mcf and a CDN/USD 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. Current conditions, economic and otherwise, render assumptions, although reasonable when made, subject to greater uncertainty.
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: continued instability, or further deterioration, in global economic and market environment, including from inflation and/or the Ukraine/Russia conflict and heightened geopolitical risks; 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; volatility in our common share trading price and free cash flow that could impact our planned share repurchases and dividend levels; unanticipated operating results, results from our capital spending activities or production declines; legal proceedings or other events inhibiting or preventing operation of the Dakota Access Pipeline; 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; 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 credit facilities and/or 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; 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 second quarter 2023 MD&A, our annual information form for the year ended December 31, 2022, our 2022 annual MD&A and Form 40-F as at December 31, 2022).
The forward-looking information contained in this news release speaks only as of the date of this news release. Enerplus does not undertake any obligation to publicly update or revise any forward-looking information contained herein, except as required by applicable laws. Any forward-looking information contained herein are expressly qualified by this cautionary statement.
NON-GAAP AND OTHER FINANCIAL MEASURES
Readers are referred to “Non-GAAP Measures” in Enerplus’ second quarter 2023 MD&A for supplementary financial measures, which information is incorporated by reference to this new release.
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 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).
| Three months ended June 30, | Six months ended June 30, | |||||||||||
| ($ millions) | 2023 | 2022 | 2023 | 2022 | ||||||||
| Net income/(loss) | $ | 74.2 | $ | 244.4 | $ | 211.7 | $ | 277.6 | ||||
| Unrealized derivative instrument, foreign exchange and marketable securities (gain)/loss |
11.7 | (94.6) | 16.4 | 40.0 | ||||||||
| Other expense related to investing activities | — | — | — | 13.1 | ||||||||
| Tax effect | (1.5) | 22.5 | (3.0) | (12.6) | ||||||||
| Adjusted net income/(loss) | $ | 84.4 | $ | 172.3 | $ | 225.1 | $ | 318.1 | ||||
“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.
| Three months ended June 30, | Six months ended June 30, | |||||||||||
| ($ millions) | 2023 | 2022 | 2023 | 2022 | ||||||||
| Cash flow from/(used in) operating activities | $ | 186.6 | $ | 250.9 | $ | 428.0 | $ | 446.9 | ||||
| Asset retirement obligation settlements | 2.1 | 2.3 | 8.9 | 11.1 | ||||||||
| Changes in non-cash operating working capital | 7.9 | 44.2 | 20.2 | 101.3 | ||||||||
| Adjusted funds flow | $ | 196.6 | $ | 297.4 | $ | 457.1 | $ | 559.3 | ||||
| Capital spending | (180.9) | (132.9) | (319.6) | (231.9) | ||||||||
| Free cash flow | $ | 15.7 | $ | 164.5 | $ | 137.5 | $ | 327.4 | ||||
Other Financial Measures
CAPITAL MANAGEMENT MEASURES
Capital management measures are financial measures disclosed by a company that (a) are intended to enable an individual to evaluate a company’s objectives, policies and processes for managing the company’s capital, (b) are not a component of a line item disclosed in the primary financial statements of the company, (c) are disclosed in the notes to the financial statements of the company, and (d) are not disclosed in the primary financial statements of the company. The following section provides an explanation of the composition of those capital management measures if not previously provided:
“Adjusted funds flow” is used by Enerplus and is useful to investors and securities analysts, in analyzing operating and financial performance, leverage and liquidity. 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.
“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. “Net debt” is useful to investors and securities analysts in analyzing financial liquidity and Enerplus considers net debt to be a key measure of capital management. For further details, see Note 5 to the Interim Financial Statements.
“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.
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.
“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.
Electronic copies of Enerplus’ 2023 interim and 2022 annual Financial Statements and associated MD&As, along with other public information including investor presentations, are or will be 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
Share This:
