CDN NEWS | 
US NEWS 
All financial information contained within this news release has been prepared in accordance with U.S. GAAP. 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 “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’ 2021 Financial Statements and MD&A is available on our website at www.enerplus.com, under our profile on SEDAR at www.sedar.com and on the EDGAR website at www.sec.gov. All amounts in this news release are stated in United States dollars unless otherwise specified.
Reporting currency changed to U.S. dollars; production volumes changed to a “net” (after deduction of royalty) basis as announced on February 2, 2022.
CALGARY, AB, Feb. 24, 2022 /CNW/ – Enerplus Corporation (“Enerplus” or the “Company”) (TSX: ERF) (NYSE: ERF) today reported fourth quarter 2021 cash flow from operating activities and adjusted funds flow(1) of $283.5 million and $258.5 million, respectively, compared to $70.9 million and $68.6 million, respectively, in the fourth quarter of 2020. Full year 2021 cash flow from operating activities and adjusted funds flow(1) was $604.8 million and $712.4 million, respectively, compared to $335.9 million and $265.5 million, respectively, in 2020.
HIGHLIGHTS – FULL YEAR 2021
- Robust free cash flow generation– Adjusted funds flow(1) was $712.4 million in 2021, which exceeded capital spending of $302.3 million, generating free cash flow(1) of $410.1 million (representing a reinvestment rate(1) of 42%).
- Strategic Bakken acquisitions – Completed two highly accretive and strategic acquisitions in the Bakken in 2021 which have enhanced Enerplus’ free cash flow generation and extended the Company’s high quality drilling inventory to over a decade.
- Maintained balance sheet strength – Ended 2021 with net debt(1)of $640.4 million and a net debt to adjusted funds flow ratio(1) of 0.9x.
- Meaningful capital returned to shareholders – Increased the dividend by 37% and repurchased $123.2 million of the Company’s shares in 2021 for a total cash return to shareholders of $153.7 million.
- Strong performance relative to emissions targets – Continued progress towards Enerplus’ 50% greenhouse gas (“GHG”) emissions intensity reduction target by 2030 (Scope 1 and 2). Relative to its 2019 baseline, the Company reduced methane emissions intensity by over 20% in 2021 (one year ahead of target) and reduced 2021 GHG emissions intensity by approximately 25%, based on preliminary estimates.
- Capital efficiency improvement – Solid operational execution delivered another significant reduction in total well cost performance in North Dakota which averaged $5.7 million per well in 2021, down 10% year-over-year.
- Substantial reserves growth – Year end 2021 net proved reserves increased 163% year-over-year (U.S. SEC Standards), and gross proved plus probable reserves increased 45% year-over-year (Canadian NI 51-101 Standards). See separate news release issued today.
| (1)Â This is a non-GAAP financial measure. Refer to “Non-GAAP and Other Financial Measures” section for more information. |
HIGHLIGHTS – 2022 AND FIVE-YEAR OUTLOOK
- 2022 free cash flow outlook– At commodity prices of $75 per barrel WTI and $4.00 per Mcf NYMEX, Enerplus expects to generate approximately $500 million of free cash flow(1) in 2022, representing a reinvestment rate(1) of less than 45%.
- Increased share repurchase plan – Based on current market conditions, Enerplus plans to execute its remaining Normal Course Issuer Bid (“NCIB”) authorization by the end of July 2022. This represents an increase to the Company’s current CDN$200 million repurchase program by approximately $100 million, assuming Enerplus’ current share price. Upon completion, this is expected to result in over $300 million in total cash returns to shareholders over the preceding 12-month period through dividends and share repurchases.
- Updated five-year outlook – Extended through 2026 and under commodity price assumptions of $70 per barrel WTI and $3.00 per Mcf NYMEX(2), Enerplus projects $2.2 billion of cumulative free cash flow(1) under annual capital spending of $400 to $450 million. Liquids production is expected to grow by 3% to 5% annually.
| (1)Â This is a non-GAAP financial measure. Refer to “Non-GAAP and Other Financial Measures” section for more information. |
| (2)Â 2022 is based on $75/bbl WTI and $4.00/Mcf NYMEX. |
“2021 was a transformational year for Enerplus. We completed two highly strategic and accretive acquisitions, maintained our commitment to operating with low financial leverage, and generated company record production and free cash flow,” said Ian C. Dundas, President and CEO.
“The depth of our North Dakota inventory and our operational scale have substantially increased following our 2021 acquisitions. We can point to over a decade of high-quality North Dakota drilling inventory, which further supports the sustainability of our long-term plan,” commented Dundas.
“Looking ahead, we are positioned to deliver another year of strong results supported by high commodity prices, a capital efficient operating plan in North Dakota that is 75% protected from cost inflation, and structurally tight Bakken oil price differentials. Consistent with our track record, we expect to deliver meaningful cash returns to shareholders in 2022. We continue to believe that our intrinsic value, based on mid-cycle commodity price assumptions, is not adequately reflected in our current market value. As a result, we plan to continue our aggressive approach to share repurchases which is expected to result in a reduction to our shares outstanding of approximately 10% in less than a year since commencing the program.”
FOURTH QUARTER 2021 SUMMARY
Enerplus delivered fourth quarter total production of 102,823 BOE per day, which was at the high end of its guidance range (100,000 to 103,200 BOE per day). Total production in the fourth quarter was 4% higher than the prior quarter and 48% higher than the same period in 2020. Liquids production in the fourth quarter was 64,959 barrels per day, which was in line with the Company’s guidance (64,150 to 66,550 barrels per day). Liquids production in the fourth quarter was 3% higher than the prior quarter and 63% higher than the same period in 2020. The higher quarter-over-quarter production was due to development activity in North Dakota and the Marcellus. The higher production compared to the same period in 2020 was primarily due to the Company’s acquisitions in North Dakota completed during the first half of 2021. Enerplus completed the divestment of its Sleeping Giant and Russian Creek interests in the Williston Basin during the fourth quarter with associated production of approximately 2,400 BOE per day.
Enerplus reported fourth quarter 2021 net income of $176.9 million, or $0.71 per share, compared to a net loss of $161.6 million, or ($0.73) per share, in the fourth quarter of 2020. Excluding certain non-cash or non-recurring items, fourth quarter 2021 adjusted net income(1) was $130.0 million, or $0.52 per share, compared to $15.3 million, or $0.07 per share, during the same period in 2020. The higher net income and adjusted net income was primarily due to higher production and commodity prices. The net loss in the fourth quarter of 2020 was primarily due to a non-cash property, plant and equipment (“PP&E”) impairment of $244.5 million.
Enerplus’ fourth quarter 2021 Bakken crude oil price differential was $0.88 per barrel below WTI, compared to
$5.12 per barrel below WTI for the same period in 2020. The stronger Bakken differential was due to an improved supply and demand balance and excess pipeline capacity in the region. Enerplus’ fourth quarter Marcellus natural gas price differential was $1.70 per Mcf below NYMEX, compared to $1.07 per Mcf below NYMEX for the same period in 2020. The wider Marcellus differential was due to volatility in NYMEX pricing and weaker local markets during the fourth quarter of 2021.
Operating expenses in the fourth quarter of 2021 were $8.46 per BOE, compared to $7.82 per BOE in the same period in 2020. The increase in per unit operating expenses was due to the Company’s higher crude oil production, contract price escalation and increased well service activity. Cash general and administrative (“G&A”) expenses were $1.12 per BOE in the fourth quarter of 2021, compared to $1.40 per BOE in the prior year period. The reduction in per unit G&A expenses was due to higher production in the fourth quarter of 2021.
Capital spending totaled $81.1 million in the fourth quarter of 2021. The Company paid $7.9 million in dividends during the quarter and repurchased 11.2 million shares at an average price of $10.08 (CDN$12.70) per share for a total cost of $113.3 million.
Enerplus ended the fourth quarter of 2021 with net debt of $640.4 million and was undrawn on its $900 million bank credit facility.
| (1)Â This is a non-GAAP financial measure. Refer to “Non-GAAP and Other Financial Measures” section for more information. |
FULL YEAR 2021 SUMMARY
Enerplus delivered 2021 total production of 92,221 BOE per day, which was at the high end of its guidance range (91,450 to 92,250 BOE per day). Total production in 2021 was 26% higher compared to 2020. Liquids production in 2021 was 56,337 barrels per day, which was in line with the Company’s guidance (55,950 to 56,750 barrels per day). Liquids production in 2021 was 37% higher compared to 2020. The higher year-over-year production was primarily due to the Company’s acquisitions in North Dakota completed during the first half of 2021 and its development program in 2021.
Enerplus reported full year 2021 net income of $234.4 million, or $0.93 per share, compared to a net loss of $693.4 million, or ($3.12) per share, in 2020. Excluding certain non-cash or non-recurring items, 2021 adjusted net income(1) was $315.7 million, or $1.25 per share, compared to $14.5 million, or $0.07 per share, in 2020. The higher net income and adjusted net income was primarily due to higher production and commodity prices. The net loss in 2020 was primarily due to non-cash impairments of $900.9 million as a result of low commodity prices in 2020.
Enerplus’ 2021 Bakken crude oil price differential was $2.15 per barrel below WTI, compared to $5.39 per barrel below WTI in 2020. Bakken pricing strengthened throughout the year as basin-wide production fell below 2020 levels, while pipeline egress capacity out of the basin increased with the Dakota Access Pipeline expansion start-up in August 2021. Enerplus’ 2021 Marcellus natural gas price differential was $0.81 per Mcf below NYMEX, compared to $0.65 per Mcf below NYMEX in 2020. The weaker pricing was driven by warmer than anticipated weather for much of the year and volatility in NYMEX benchmark prices.
Operating expenses in 2021 were $8.69 per BOE, compared to $7.38 per BOE in 2020. Cash G&A expenses in 2021 were $1.14 per BOE, compared to $1.26 per BOE in 2020.
Capital spending totaled $302.3 million in 2021, in line with the Company’s guidance of $303 million. The Company paid $30.5 million in dividends in 2021 and repurchased 12.9 million shares at an average price of $9.55 (CDN$12.06) per share for a total cost of $123.2 million.
| (1)Â This is a non-GAAP financial measure. Refer to “Non-GAAP and Other Financial Measures” section for more information. |
ASSET ACTIVITY
Williston Basin production averaged 67,590 BOE per day during the fourth quarter of 2021, 4% higher than the prior quarter. In the fourth quarter, Enerplus drilled six operated wells (100% working interest) and brought eight operated wells on production (100% working interest). Enerplus continued to deliver reductions to its well cost structures in 2021 through improved execution and technology application. This led to a 10% improvement year-over-year in total well costs which averaged $5.7 million in 2021.
Marcellus production averaged 161 MMcf per day during the fourth quarter of 2021, 5% higher than the prior quarter. Canadian waterflood production averaged 5,741 BOE per day during the fourth quarter of 2021, 2% lower than the prior quarter.
ENVIRONMENTAL, SOCIAL AND GOVERNANCE (ESG) UPDATE
Enerplus continued to make strong progress on its ESG initiatives in 2021. Based on preliminary estimates, the Company expects to have reduced its 2021 scope 1 and 2 GHG emissions intensity by approximately 25% and its methane emissions intensity by over 20%, each compared to a 2019 baseline. Enerplus also reduced its freshwater use per well completion in the Fort Berthold Indian Reservation by 31% in 2021, compared to a 2019 baseline, exceeding its target of 25%. The Company continues to work towards its longer-term environmental targets, including a 50% reduction in GHG emissions intensity by 2030 and a 50% reduction in freshwater use per well completion corporately by 2025.
Enerplus is also well positioned to achieve its safety targets having delivered a company record in 2021 of zero lost time injuries. Enerplus is targeting a 25% reduction in lost time injury frequency, on average, from 2020 to 2023, relative to its 2019 baseline.
2022 GUIDANCE AND FREE CASH FLOW OUTLOOK
Enerplus’ previously announced 2022 preliminary outlook was $400 million of capital spending expected to result in production of approximately 98,000 BOE per day, including 60,000 barrels per day of liquids. Enerplus has provided formal 2022 guidance of $370 to $430 million of capital spending, total production of 95,500 to 100,500 BOE per day, and liquids production of 58,000 to 62,000 barrels per day.
At commodity prices of $75 per barrel WTI and $4.00 per Mcf NYMEX, Enerplus expects to generate approximately $500 million of free cash flow(1) in 2022, representing a reinvestment rate(1) of less than 45%. Enerplus remains committed to both reducing debt and returning a significant portion of free cash flow to shareholders.
Increasing return of capital to shareholders
Enerplus has a long track record of returning capital to shareholders throughout the cycle. Since 2017, Enerplus has returned over 60% of its free cash flow(1), or $435 million, to shareholders through dividends and share repurchases.
Upon completion of the Company’s CDN$200 million share repurchase program, which is expected by the end of the first quarter of 2022, Enerplus plans to repurchase the remaining authorization under its NCIB by the end of July 2022, based on current market conditions. Using Enerplus’ current share price, this equates to additional share repurchases of approximately $100 million and, when fully executed, will represent approximately 10% of the Company’s shares outstanding having been repurchased since the third quarter of 2021. Inclusive of dividends and share repurchases, the Company expects to have returned over $300 million to shareholders over the 12-month period ending July 2022. The Company intends to renew its NCIB in August 2022.
Operating plan
The Company has added a second drilling rig in North Dakota which it plans to operate for approximately six months, reverting to one drilling rig in the second half of 2022. Enerplus expects to drill 46 to 54 gross operated wells (79% average working interest) and bring 36 to 44 gross operated wells (87% average working interest) on production in North Dakota during the year. In total, the Company expects to allocate 83% of its 2022 capital budget to North Dakota which includes approximately $80 million for non-operated North Dakota activity.
The remaining 17% of the Company’s 2022 capital spending is expected to be allocated to the Marcellus (10%), the Canadian Waterfloods (4%) and the DJ Basin (3%).
With strong demand and significant available pipeline capacity in the basin, Enerplus expects its 2022 realized Bakken oil price differential to strengthen year-over-year. The Company expects its 2022 Bakken oil price differential to average $0.50 per barrel below WTI.
Operating costs are expected to increase in 2022 to $9.50 to $10.50 per BOE, compared to $8.69 per BOE in 2021. The expected increase is primarily due to contract price escalation (linked to the Consumer Price Index), increased sales gas processing volumes due to improved capture rates, and higher well-service activity.
The table below summarizes Enerplus’ 2022 guidance. The Company’s 2022 guidance has not been adjusted to reflect the potential divestment of its Canadian assets as announced on February 2, 2022.
2022 Guidance Summary
| Capital spending | $370 – 430 million |
| Average total production | 95,500 – 100,500 BOE/day |
| Average liquids production | 58,000 – 62,000 bbls/day |
| Average production tax rate (% of net sales, before transportation) | 7% |
| Operating expense | $9.50 –10.50/BOE |
| Transportation expense | $4.15/BOE |
| Cash G&A expense | $1.25/BOE |
| Current tax expense | $10 million |
2022 Differential/Basis Outlook(2)
| U.S. Bakken crude oil differential (compared to WTI crude oil) | $(0.50)/bbl |
| Marcellus natural gas sales price differential (compared to NYMEX natural gas) | $(0.75)/Mcf |
| (1)Â This is a non-GAAP financial measure. Refer to “Non-GAAP and Other Financial Measures” section for more information. | |
| (2)Â Excluding transportation costs. | |
UPDATED FIVE-YEAR OUTLOOK
Enerplus has updated its five-year outlook to include 2026 and to reflect the higher current commodity price and inflationary environment. Enerplus’ previous five-year outlook (provided in 2021) was based on a commodity price environment of $50 to $55 per barrel WTI and $2.75 per Mcf NYMEX. Enerplus is extending its outlook through 2026 and increasing its commodity price assumptions to $70 per barrel WTI and $3.00 per Mcf NYMEX(1). The Company’s outlook continues to be underpinned by a focus on operating with low financial leverage, delivering strong and sustainable free cash flow growth, and returning capital to shareholders.
The Company projects annual capital spending of between $400 to $450 million with cumulative free cash flow(2) estimated at over $2.2 billion between 2022 and 2026. This is expected to result in an average reinvestment rate(2) of approximately 50% over the period. Enerplus projects 3% to 5% annual liquids production growth over this period (2022 annual growth is higher due to timing impacts of the 2021 acquisitions).
| (1)Â 2022 is based on $75/bbl WTI and $4.00/Mcf NYMEX. |
| (2)Â This is a non-GAAP financial measure. Refer to “Non-GAAP and Other Financial Measures” section for more information. |
QUARTERLY DIVIDEND DECLARED
Enerplus changed its dividend declaration currency to U.S. dollars consistent with its change in reporting currency. The Company declared a quarterly cash dividend of $0.033 per share, equivalent to approximately CDN$0.042 per share if converted using the current US/Canadian dollar exchange rate of 1.28. The dividend is effective with the March 15, 2022 dividend payment and applies to all shareholders of record at the close of business on March 4, 2022. The ex-dividend date for this payment is March 3, 2022.
Q4 AND FULL YEAR 2021 CONFERENCE CALL DETAILS
Enerplus plans to hold a conference call at 9:00 a.m. MT (11:00 a.m. ET) on February 25, 2022 to discuss these results. Details of the conference call are as follows:
| Date: | Friday, February 25, 2022 |
| Time: | 9:00 am MT/11:00 am ET |
| Dial-In: | 416-764-8688 1-888-390-0546 (toll free) |
| Conference ID: | 57309809 |
| Audiocast: | https://produceredition.webcasts.com/starthere.jsp?ei=1519306&tp_key=08cd734c3e |
| To ensure timely participation in the conference call, callers are encouraged to dial in 15 minutes prior to the start time to register for the event. A telephone replay will be available for 30 days following the conference call and can be accessed at the following numbers: | |
| Dial-In: | 416-764-8677 |
| 1-888-390-0541 (toll free) | |
| Passcode: | 546758 # |
PRICE RISK MANAGEMENT UPDATE
The following is a summary of Enerplus’ financial contracts in place at February 24, 2022:
| WTI Crude Oil ($/bbl)(1)(2)(3) | NYMEX Natural Gas ($/Mcf) | |||||||||||||
| Jan 1, 2022 – | Jan 1, 2022 – | Jan 1, 2023 – | Jan 1, 2023 – | Jan 1, 2022 – | Mar 1 , 2022 – | Apr 1, 2022 – | ||||||||
| Jun 30, 2022 | Dec 31, 2022 | Jun 30, 2023 | Dec 31, 2023 | Feb 28, 2022 | Mar 31, 2022 | Oct 31, 2022 | ||||||||
| Swaps | ||||||||||||||
| Volume (bbls/day) | – | – | – | – | – | 60,000 | 40,000 | |||||||
| Sold Puts | – | – | – | – | – | $ 4.50 | $ 3.40 | |||||||
| Collars | ||||||||||||||
| Volume (bbls/day) | 12,500 | 17,000 | 10,000 | 2,000 | 40,000 | 40,000 | 60,000 | |||||||
| Sold Puts | $ 58.00 | $ 40.00 | $ 60.00 | – | – | – | – | |||||||
| Purchased Puts | $ 75.00 | $ 50.00 | $ 76.50 | $ 5.00 | $ 3.43 | $ 3.43 | $3.77 | |||||||
| Sold Calls | $ 87.63 | $ 57.91 | $ 107.38 | $ 75.00 | $ 6.00 | $ 6.00 | $4.50 | |||||||
| (1) | (1) The total average deferred premium spent on our outstanding hedges is $1.50/bbl from January 1, 2022 – December 31, 2022 and $1.25/bbl from January 1, 2023 – June 30, 2023. | |||||||||||||
| (2) | Transactions with a common term have been aggregated and presented at weighted average prices and volumes. | |||||||||||||
| (3) | Upon closing of the Bruin Acquisition, Bruin’s outstanding crude oil contracts were recorded at a fair value liability of $76.4 million. At December 31, 2021, the remaining balance was a liability of $22.8 million on the Condensed Consolidated Balance Sheets. Realized and unrealized gains and losses on the acquired contracts are recognized in Consolidated Statement of Income/(Loss) and the Consolidated Balance Sheets to reflect changes in crude oil prices from the date of closing of the Bruin Acquisition. See Note 17 to the Financial Statements for a breakdown of the commodity contracts acquired from Bruin. | |||||||||||||
FOURTH QUARTER AND FULL YEAR 2021 PRODUCTION AND OPERATIONAL SUMMARY TABLES
Summary of Average Daily Production(1)
| Three months ended December 31, 2021 | Twelve months ended December 31, 2021 | ||||||||||||
| Williston Basin | Marcellus | Canadian Water-floods | Other(2) | Total | Williston Basin | Marcellus | Canadian Water-floods | Other(2) | Total | ||||
| Light & medium oil (bbl/d) | – | – | 2,160 | 25 | 2,185 | – | – | 2,187 | 44 | 2,231 | |||
| Heavy oil (bbl/d) | – | – | 3,208 | 16 | 3,223 | – | – | 3,282 | 20 | 3,302 | |||
| Tight oil (bbl/d) | 49,025 | – | – | 985 | 50,010 | 41,914 | – | – | 1,067 | 42,981 | |||
| Total crude oil (bbl/d) | 49,025 | – | 5,368 | 1,026 | 55,419 | 41,914 | – | 5,469 | 1,131 | 48,514 | |||
| Natural gas liquids (bbl/d) | 9,111 | – | 99 | 330 | 9,540 | 7,379 | – | 72 | 372 | 7,823 | |||
| Conventional natural gas (Mcf/d) | – | – | 1,644 | 6,353 | 7,997 | – | – | 1,403 | 6,415 | 7,818 | |||
| Shale gas (Mcf/d) | 56,726 | 161,432 | – | 1,031 | 219,189 | 48,440 | 157,946 | – | 1,100 | 207,486 | |||
| Total natural gas (Mcf/d) | 56,726 | 161,432 | 1,644 | 7,384 | 227,186 | 48,440 | 157,946 | 1,403 | 7,515 | 215,304 | |||
| Total production (BOE/d) | 67,590 | 26,905 | 5,741 | 2,587 | 102,823 | 57,366 | 26,324 | 5,775 | 2,756 | 92,221 | |||
| (1)Â Â Table may not add due to rounding. | |||||||||||||
| (2)Â Â Comprises DJ Basin and non-core properties in Canada. | |||||||||||||
Summary of Wells Drilled(1)
| Three months ended December 31, 2021 |
Twelve months ended December 31, 2021 |
|||||||||||
| Operated | Non-Operated | Operated | Non-Operated | |||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||
| Williston Basin | 6 | 6.0 | 19 | 3.4 | 18 | 18.0 | 37 | 4.0 | ||||
| Marcellus | – | – | 15 | 0.7 | – | – | 64 | 2.5 | ||||
| Canadian Waterfloods | – | – | – | – | – | – | – | – | ||||
| Other(2) | – | – | – | – | – | – | 3 | 0.4 | ||||
| Total | 6 | 6.0 | 34 | 4.2 | 18 | 18.0 | 104 | 6.9 | ||||
| (1)Â Â Â Â Table may not add due to rounding. | ||||||||||||
| (2)Â Â Â Â Comprises DJ Basin and non-core properties in Canada. | ||||||||||||
Summary of Wells Brought On-Stream(1)
| Three months ended December 31, 2021 |
Twelve months ended December 31, 2021 |
|||||||||||
| Operated | Non-Operated | Operated | Non-Operated | |||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||
| Williston Basin | 8 | 8.0 | 22 | 0.9 | 50 | 40.1 | 27 | 2.0 | ||||
| Marcellus | – | – | 20 | 2.4 | – | – | 74 | 4.5 | ||||
| Canadian Waterfloods | – | – | – | – | – | – | – | – | ||||
| Other(2) | – | – | 2 | 0.1 | 3 | 2.6 | 5 | 0.4 | ||||
| Total | 8 | 8.0 | 44 | 3.4 | 53 | 42.7 | 106 | 6.9 | ||||
| (1)Â Â Â Â Table may not add due to rounding. | ||||||||||||
| (2)Â Â Â Â Comprises DJ Basin and non-core properties in Canada. | ||||||||||||
SUMMARY FINANCIAL AND OPERATING RESULTS
| Three months ended | Twelve months ended | ||||||||||||||||||||||
| SELECTED FINANCIAL RESULTS | December 31, | December 31, | |||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||
| Financial (US$, thousands, except ratios) | |||||||||||||||||||||||
| Net Income/(Loss) | $ | 176,913 | $ | (161,566) | $ | 234,441 | $ | (693,351) | |||||||||||||||
| Adjusted Net Income(1) | 129,958 | 15,272 | 315,669 | 14,522 | |||||||||||||||||||
| Cash Flow from Operating Activities | 283,534 | 70,900 | 604,839 | 335,884 | |||||||||||||||||||
| Adjusted Funds Flow(1) | 258,477 | 68,634 | 712,433 | 265,490 | |||||||||||||||||||
| Dividends to Shareholders – Declared | 7,884 | 5,207 | 30,535 | 19,962 | |||||||||||||||||||
| Net Debt(1) | 640,423 | 295,455 | 640,423 | 295,455 | |||||||||||||||||||
| Capital Spending | 81,059 | 40,193 | 302,348 | 217,246 | |||||||||||||||||||
| Property and Land Acquisitions | 2,744 | 1,584 | 835,147 | 7,492 | |||||||||||||||||||
| Property Divestments | 108,869 | 37 | 112,651 | 4,456 | |||||||||||||||||||
| Net Debt to Adjusted Funds Flow Ratio(1) | 0.9x | 1.1x | 0.9x | 1.1x | |||||||||||||||||||
| Financial per Weighted Average Shares Outstanding | |||||||||||||||||||||||
| Net Income/(Loss) – Basic | $ | 0.71 | $ | (0.73) | $ | 0.93 | $ | (3.12) | |||||||||||||||
| Net Income/(Loss) – Diluted | 0.68 | (0.73) | 0.90 | (3.12) | |||||||||||||||||||
| Weighted Average Number of Shares Outstanding (000’s) – Basic | 250,359 | 222,548 | 251,909 | 222,503 | |||||||||||||||||||
| Weighted Average Number of Shares Outstanding (000’s) – Diluted | 258,365 | 222,548 | 259,851 | 222,503 | |||||||||||||||||||
| Selected Financial Results per BOE(2)(3) | |||||||||||||||||||||||
| Crude Oil & Natural Gas Sales(4) | $ | 52.82 | $ | 23.45 | $ | 44.04 | $ | 20.72 | |||||||||||||||
| Commodity Derivative Instruments | (7.12) | 2.67 | (4.84) | 3.47 | |||||||||||||||||||
| Operating Expenses | (8.46) | (7.82) | (8.69) | (7.38) | |||||||||||||||||||
| Transportation Costs | (4.27) | (3.70) | (3.81) | (3.69) | |||||||||||||||||||
| Production Taxes | (3.47) | (1.58) | (3.03) | (1.40) | |||||||||||||||||||
| General and Administrative Expenses | (1.12) | (1.40) | (1.14) | (1.26) | |||||||||||||||||||
| Cash Share-Based Compensation | (0.22) | (0.11) | (0.20) | 0.04 | |||||||||||||||||||
| Interest, Foreign Exchange and Other Expenses | (0.82) | (0.80) | (1.08) | (1.01) | |||||||||||||||||||
| Current Income Tax Recovery/(Expense) | (0.02) | — | (0.08) | 0.40 | |||||||||||||||||||
| Adjusted Funds Flow(1) | $ | 27.32 | $ | 10.71 | $ | 21.17 | $ | 9.89 | |||||||||||||||
| Three months ended | Twelve months ended | ||||||||||||||||||||||
| SELECTED OPERATING RESULTS | December 31, | December 31, | |||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||
| Average Daily Production(3) | |||||||||||||||||||||||
| Crude Oil (bbls/day) | 55,419 | 35,118 | 48,514 | 36,681 | |||||||||||||||||||
| Natural Gas Liquids (bbls/day) | 9,540 | 4,615 | 7,823 | 4,499 | |||||||||||||||||||
| Natural Gas (Mcf/day) | 227,186 | 179,265 | 215,304 | 191,014 | |||||||||||||||||||
| Total (BOE/day) | 102,823 | 69,611 | 92,221 | 73,016 | |||||||||||||||||||
| % Crude Oil and Natural Gas Liquids | 63% | 57% | 61% | 56% | |||||||||||||||||||
| Average Selling Price(3)(4) | |||||||||||||||||||||||
| Crude Oil (per bbl) | $ | 75.54 | $ | 36.89 | $ | 66.05 | $ | 33.30 | |||||||||||||||
| Natural Gas Liquids (per bbl) | 38.90 | 13.21 | 29.86 | 7.79 | |||||||||||||||||||
| Natural Gas (per Mcf) | 4.02 | 1.57 | 2.98 | 1.40 | |||||||||||||||||||
| Net Wells Drilled | 10 | 2 | 25 | 42 | |||||||||||||||||||
| (1) | This financial measure is a non-GAAP financial measure and may not be directly comparable to similar measures presented by other entities. See “Non-GAAP and Other Financial Measures” section in this MD&A. |
| (2) | Non–cash amounts have been excluded. |
| (3) | Based on Net production volumes. See “Basis of Presentation” section in the following MD&A. |
| (4) | Before transportation costs and commodity derivative instruments. |
Condensed Consolidated Balance Sheets
| (US$ thousands) | December 31, 2021 | December 31, 2020 | ||||
| Assets | ||||||
| Current assets | ||||||
| Cash and cash equivalents | $ | 61,348 | $ | 89,945 | ||
| Accounts receivable | 227,988 | 83,596 | ||||
| Other current assets | 10,956 | 5,609 | ||||
| Derivative financial assets | 5,668 | 2,790 | ||||
| 305,960 | 181,940 | |||||
| Property, plant and equipment: | ||||||
| Crude oil and natural gas properties (full cost method) | 1,253,505 | 452,302 | ||||
| Other capital assets | 13,887 | 11,499 | ||||
| Property, plant and equipment | 1,267,392 | 463,801 | ||||
| Other long-term assets | 9,756 | 3,845 | ||||
| Right-of-use assets | 26,118 | 25,818 | ||||
| Deferred income tax asset | 380,858 | 477,014 | ||||
| Total Assets | $ | 1,990,084 | $ | 1,152,418 | ||
| Liabilities | ||||||
| Current liabilities | ||||||
| Accounts payable | $ | 367,008 | $ | 197,895 | ||
| Dividends payable | — | 1,749 | ||||
| Current portion of long-term debt | 100,600 | 81,600 | ||||
| Derivative financial liabilities | 143,200 | 15,136 | ||||
| Current portion of lease liabilities | 10,618 | 10,523 | ||||
| 621,426 | 306,903 | |||||
| Long-term debt | 601,171 | 303,800 | ||||
| Asset retirement obligation | 132,814 | 102,325 | ||||
| Derivative financial liabilities | 7,098 | — | ||||
| Lease liabilities | 18,265 | 18,425 | ||||
| 759,348 | 424,550 | |||||
| Total Liabilities | 1,380,774 | 731,453 | ||||
| Shareholders’ Equity | ||||||
| Share capital – authorized unlimited common shares, no par value | ||||||
| Issued and outstanding: December 31, 2021 – 244 million shares | ||||||
|   December 31, 2020 – 223 million shares | 3,094,061 | 3,113,829 | ||||
| Paid-in capital | 50,881 | 49,382 | ||||
| Accumulated deficit | (2,238,325) | (2,447,735) | ||||
| Accumulated other comprehensive loss | (297,307) | (294,511) | ||||
| 609,310 | 420,965 | |||||
| Total Liabilities & Shareholders’ Equity | $ | 1,990,084 | $ | 1,152,418 | ||
Condensed Consolidated Statements of Income/(Loss) and Comprehensive Income/(Loss)
| For the year ended December 31 (US$ thousands) | 2021 | 2020 | 2019 | ||||||
| Revenues | |||||||||
| Crude oil and natural gas sales | $ | 1,482,575 | $ | 553,739 | $ | 945,894 | |||
| Commodity derivative instruments gain/(loss) | (274,432) | 75,742 | (47,930) | ||||||
| 1,208,143 | 629,481 | 897,964 | |||||||
| Expenses | |||||||||
| Operating | 292,433 | 197,097 | 219,343 | ||||||
| Transportation | 128,309 | 98,681 | 109,241 | ||||||
| Production taxes | 101,953 | 37,417 | 62,662 | ||||||
| General and administrative | 56,807 | 43,097 | 54,920 | ||||||
| Depletion, depreciation and accretion | 271,336 | 218,118 | 269,046 | ||||||
| Asset impairment | 3,420 | 751,723 | — | ||||||
| Goodwill impairment | — | 149,217 | 347,283 | ||||||
| Interest | 27,395 | 20,737 | 25,580 | ||||||
| Foreign exchange (gain)/loss | (6,908) | 1,232 | (16,420) | ||||||
| Transaction costs and other expense/(income) | (2,487) | 4,489 | (5,695) | ||||||
| 872,258 | 1,521,808 | 1,065,960 | |||||||
| Income/(Loss) Before Taxes | 335,885 | (892,327) | (167,996) | ||||||
| Current income tax expense/(recovery) | 2,689 | (10,716) | (25,246) | ||||||
| Deferred income tax expense/(recovery) | 98,755 | (188,260) | 61,650 | ||||||
| Net Income/(Loss) | $ | 234,441 | $ | (693,351) | $ | (204,400) | |||
| Other Comprehensive Income/(Loss) | |||||||||
| Unrealized gain/(loss) on foreign currency translation | (6,893) | (2,169) | 11,995 | ||||||
| Foreign exchange gain/(loss) on net investment hedge, net of tax | 4,097 | 1,780 | — | ||||||
| Total Comprehensive Income/(Loss) | $ | 231,645 | $ | (693,740) | $ | (192,405) | |||
| Net Income/(Loss) per Share | |||||||||
| Basic | $ | 0.93 | $ | (3.12) | $ | (0.88) | |||
| Diluted | $ | 0.90 | $ | (3.12) | $ | (0.88) | |||
Condensed Consolidated Statements of Cash Flows
| For the year ended December 31 (US$ thousands) | 2021 | 2020 | 2019 | ||||||
| Operating Activities | |||||||||
| Net income/(loss) | $ | 234,441 | $ | (693,351) | $ | (204,400) | |||
| Non-cash items add/(deduct): | |||||||||
| Depletion, depreciation and accretion | 271,336 | 218,118 | 269,046 | ||||||
| Asset impairment | 3,420 | 751,723 | — | ||||||
| Goodwill impairment | — | 149,217 | 347,283 | ||||||
| Changes in fair value of derivative instruments | 109,536 | 18,074 | 59,750 | ||||||
| Deferred income tax expense/(recovery) | 98,755 | (188,260) | 61,650 | ||||||
| Foreign exchange (gain)/loss on debt and working capital | (8,055) | 1,363 | (21,899) | ||||||
| Share-based compensation and general and administrative | 13,424 | 9,508 | 17,356 | ||||||
| Other expense/(income) | (4,594) | — | — | ||||||
| Amortization of debt issuance costs | 1,093 | — | — | ||||||
| Translation of U.S. dollar cash held in parent company | (2,330) | (902) | 6,825 | ||||||
| Other income reclassified to Investing Activities | (4,593) | — | — | ||||||
| Asset retirement obligation settlements | (12,951) | (13,275) | (12,646) | ||||||
| Changes in non-cash operating working capital | (94,643) | 83,669 | (3,197) | ||||||
| Cash flow from/(used in) operating activities | 604,839 | 335,884 | 519,768 | ||||||
| Financing Activities | |||||||||
| Proceeds from bank term loan/bank credit facility | 400,000 | — | — | ||||||
| Debt issuance costs | (4,621) | — | — | ||||||
| Repayment of senior notes | (81,600) | (81,600) | (44,444) | ||||||
| Proceeds from the issuance of shares | 98,339 | — | — | ||||||
| Purchase of common shares under Normal Course Issuer Bid | (123,182) | (1,807) | (134,285) | ||||||
| Share-based compensation – tax withholdings settled in cash | (3,551) | (5,567) | (3,705) | ||||||
| Dividends | (32,284) | (19,897) | (21,003) | ||||||
| Cash flow from/(used in) financing activities | 253,101 | (108,871) | (203,437) | ||||||
| Investing Activities | |||||||||
| Capital and office expenditures | (271,131) | (248,990) | (454,521) | ||||||
| Bruin acquisition | (420,249) | — | — | ||||||
| Dunn County acquisition | (305,076) | — | — | ||||||
| Property and land acquisitions | (9,846) | (7,491) | (18,409) | ||||||
| Property divestments | 108,193 | 4,456 | 7,210 | ||||||
| Other expense/(income) | 4,593 | — | — | ||||||
| Cash flow from/(used in) investing activities | (893,516) | (252,025) | (465,720) | ||||||
| Effect of exchange rate changes on cash and cash equivalents | 6,979 | (1,786) | (295) | ||||||
| Change in cash and cash equivalents | (28,597) | (26,798) | (149,684) | ||||||
| Cash and cash equivalents, beginning of year | 89,945 | 116,743 | 266,427 | ||||||
| Cash and cash equivalents, end of year | $ | 61,348 | $ | 89,945 | $ | 116,743 | |||
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.
Follow @EnerplusCorp on Twitter at https://twitter.com/EnerplusCorp.
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. Previously, the Company presented production volumes on a “company interest” basis, which was calculated as its working interest share before deduction of royalties plus the Company’s royalty interests. With these changes, production volumes presented by the Company on a “net” basis are expected to be lower than those presented historically.
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, 2021 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, 2021, 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, 2021 which is available on our website at www.enerplus.com and under our SEDAR profile at www.sedar.com. 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 2022 average production volumes, timing thereof and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged; the results from our drilling program and the timing of related production and ultimate well recoveries; oil and natural gas prices and differentials, including expected changes to such differentials year-over-year, and our commodity risk management program in 2022 and in the future; expectations regarding our realized oil and natural gas prices; future royalty rates on our production and future production taxes; anticipated cash G&A, share-based compensation and financing expenses; operating, transportation and tax expenses; share repurchase plans and the amount of future cash returns to our shareholders by way of dividends and share repurchases; expected free cash flow generation and use thereof, including to fund share repurchases and dividends; execution of our remaining NCIB authorization and the anticipated timing thereof; expected reinvestment rates; capital spending levels and allocations in 2022 and impact thereof on our production levels and land holdings; our ESG initiatives, including GHG emissions intensity, freshwater use reduction and health and safety targets for 2022 and in the future; our anticipated progress towards our ESG initiatives, including timing 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; our future acquisitions and dispositions, including the divestment process for our Canadian assets in 2022 and the completion and timing thereof; and renewal of our NCIB and timing thereof.
The forward-looking information contained in this news release reflects several material factors and expectations and assumptions of Enerplus including, without limitation: 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 commodity prices, differentials and cost assumptions; expectations regarding inflation; the general continuance of current or, where applicable, assumed industry conditions; 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 working capital deficiency; the availability of third party services; the extent of our liabilities; estimates relating to our ESG emissions intensity; and the availability of technology and process to achieve environmental targets; the ability to achieve the expected benefits of the divestment of the Sleeping Giant and Russian Creek interests in the Williston Basin on Enerplus’ operations, reserves, inventory and opportunities, financial condition and overall strategy. In addition, our 2022 guidance contained in this news release is based on the following: a WTI price of $75.00/bbl, a NYMEX price of $4.00/Mcf, a Bakken crude oil price differential of $(0.50)/bbl below WTI, a Marcellus natural gas price differential of $(0.75)/Mcf below NYMEX and a CDN/USD exchange rate of 0.79. 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: decreases in commodity prices or volatility in commodity prices; changes in realized prices of Enerplus’ products; changes in the demand for or supply of our products; 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 facility 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 Sleeping Giant and Russian Creek interests in the Williston Basin; and certain other risks detailed from time to time in our public disclosure documents (including, without limitation, those risks identified in our AIF and Form 40-F as at December 31, 2021).
The purpose of our adjusted funds flow sensitivity is to assist readers in understanding our expected and targeted financial results, and this information may not be appropriate for other purposes. 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 MEASURES
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 indicated the composition of the measure, identified the GAAP equivalency to the extent one exists, provided comparative detail where appropriate, indicated the reconciliation of the measure to the mostly directly comparable GAAP financial measure and 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 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.
| Year ended December 31, | |||||||||
| ($Â millions) | 2021 | 2020 | 2019 | ||||||
| Cash flow from/(used in) operating activities | $ | 604.8 | $ | 335.9 | $ | 519.8 | |||
| Asset retirement obligation settlements | 13.0 | 13.3 | 12.6 | ||||||
| Changes in non-cash operating working capital | 94.6 | (83.7) | 3.2 | ||||||
| Adjusted funds flow | $ | 712.4 | $ | 265.5 | $ | 535.6 | |||
“Adjusted net income” 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). The calculation follows:
| Year ended December 31, | |||||||||
| ($Â millions) | 2021 | 2020 | 2019 | ||||||
| Net income/(loss) | $ | 234.4 | $ | (693.4) | $ | (204.4) | |||
| Unrealized derivative instrument (gain)/loss | 109.5 | 18.1 | 59.7 | ||||||
| Asset impairment | 3.4 | 751.7 | — | ||||||
| Unrealized foreign exchange (gain)/loss | (8.1) | 1.4 | (21.9) | ||||||
| Tax effect on above items | (24.9) | (201.0) | (13.5) | ||||||
| Other income related to investing activities | (4.6) | — | — | ||||||
| Goodwill impairment | — | 149.2 | 347.3 | ||||||
| Income tax rate adjustment on deferred taxes | 6.0 | — | 17.1 | ||||||
| Valuation allowance on deferred taxes | — | (11.5) | — | ||||||
| Adjusted net income | $ | 315.7 | $ | 14.5 | $ | 184.3 | |||
“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. There is no directly comparable related GAAP equivalent for this measure. Adjusted funds flow is reconciled above.
| Year ended December 31, | |||||||||
| ($Â millions) | 2021 | 2020 | 2019 | ||||||
| Adjusted funds flow | $ | 712.4 | $ | 265.5 | $ | 535.6 | |||
| Capital spending | (302.3) | (217.2) | (465.9) | ||||||
| Free cash flow | $ | 410.1 | $ | 48.3 | $ | 69.7 | |||
“Net debt” is calculated as current and long-term debt associated with senior notes plus any outstanding bank credit facility and term loan balances, minus cash and cash equivalents. The calculation follows:
| Year ended December 31, | ||||||
| ($Â millions) | 2021 | 2020 | ||||
| Current portion of long-term debt | $ | 100.6 | $ | 81.6 | ||
| Long-term debt | 601.2 | 303.8 | ||||
| Less: Cash and cash-equivalents | (61.4) | (89.9) | ||||
| Net debt | $ | 640.4 | $ | 295.5 | ||
“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. The calculation follows:
| Year ended December 31, | ||||||
| ($Â millions) | 2021 | 2020 | ||||
| Net debt | $ | 640.4 | 295.5 | |||
| Adjusted funds flow | 712.4 | 265.5 | ||||
| Net debt to adjusted funds flow ratio | 0.9x | 1.1x | ||||
“Reinvestment rate” is used by Enerplus and is useful to investors and securities analysts in analyzing the reinvestment of capital spending by comparing the amount of our capitals spending as compared to adjusted funds flow (as a percentage). There is no closely related GAAP measure. The calculation follows:
| Year ended December 31, | |||||||||
| ($Â millions) | 2021 | 2020 | 2019 | ||||||
| Capital spending | $ | 302.3 | $ | 217.2 | $ | 465.9 | |||
| Adjusted funds flow | 712.4 | 265.5 | 535.6 | ||||||
| Reinvestment rate (%) | 42% | 82% | 87% | ||||||
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.
“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’ 2021 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
For further information: Investor Contacts, Drew Mair, 403-298-1707; Krista Norlin, 403-298-4304
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