MD&A
Exhibit 99.1
MANAGEMENT’S DISCUSSION AND ANALYSIS (“MD&A”)
The following discussion and analysis of financial results is dated August 5, 2021 and is to be read in conjunction with:
● | the unaudited interim condensed consolidated financial statements of Enerplus Corporation (“Enerplus” or the “Company”) as at and for the three and six months ended June 30, 2021 and 2020 (the “Interim Financial Statements”); |
● | the audited consolidated financial statements of Enerplus as at December 31, 2020 and 2019 and for the years ended December 31, 2020, 2019 and 2018; and |
● | our MD&A for the year ended December 31, 2020 (the “Annual MD&A”). |
The following MD&A contains forward-looking information and statements. We refer you to the end of the MD&A under “Forward-Looking Information and Statements” for further information. The following MD&A also contains financial measures that do not have a standardized meaning as prescribed by accounting principles generally accepted in the United States of America (“U.S. GAAP”). See “Non-GAAP Measures” at the end of the MD&A for further information. In addition, the following MD&A contains disclosure regarding certain risks and uncertainties associated with Enerplus' business. See "Risk Factors and Risk Management" in the Annual MD&A and "Risk Factors" in Enerplus' annual information form for the year ended December 31, 2020 (the "Annual Information Form”).
BASIS OF PRESENTATION
The Interim Financial Statements and Notes thereto have been prepared in accordance with U.S. GAAP, including the prior period comparatives. All amounts are stated in Canadian dollars unless otherwise specified and all note references relate to the notes included in the Interim Financial Statements. Certain prior period amounts have been reclassified to conform with current period presentation.
Where applicable, natural gas has been converted to barrels of oil equivalent (“BOE”) based on 6 Mcf:1 bbl and crude oil and natural gas liquids (“NGL”) have been converted to thousand cubic feet of gas equivalent (“Mcfe”) based on 0.167 bbl:1 Mcf. BOE and Mcfe measures are based on an energy equivalent conversion method primarily applicable at the burner tip and do not represent a value equivalent at the wellhead. Given that the value ratio based on the current price of natural gas as compared to crude oil is significantly different from the energy equivalency of 6:1 or 0.167:1, as applicable, utilizing a conversion on this basis may be misleading as an indication of value. Use of BOE and Mcfe in isolation may be misleading. Unless otherwise stated, all production volumes and realized product prices information is presented on a “Company interest” basis, being the Company’s working interest share before deduction of any royalties paid to others, plus the Company’s royalty interests. Company interest is not a term defined in Canadian National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and may not be comparable to information produced by other entities.
All references to "liquids" in this MD&A include light and medium crude oil, heavy oil and tight oil (all together referred to as "crude oil") and natural gas liquids on a combined basis. All references to “natural gas” in this MD&A include conventional natural gas and shale gas.
In accordance with U.S. GAAP, crude oil and natural gas sales are presented net of royalties in our Interim Financial Statements. Under International Financial Reporting Standards, industry standard is to present crude oil and natural gas sales before deduction of royalties, and as such, this MD&A presents production, crude oil and natural gas sales, and BOE measures on this basis to remain comparable with our Canadian peers.
For more details on our acquisition (the “Bruin Acquisition”) of Bruin E&P HoldCo, LLC (“Bruin”), see Note 4 to the Interim Financial Statements as well as the material change report dated January 29, 2021 and the business acquisition report dated April 13, 2021, each available under Enerplus’ SEDAR profile at www.sedar.com and Enerplus’ EDGAR profile under Form 6-K at www.sec.gov.
For more details on our acquisition (the “Dunn County Acquisition” or the “Hess Acquisition”) of certain assets in the Williston Basin (“Dunn County”) from Hess Bakken Investments II, LLC (“Hess”), see Note 4 to the Interim Financial Statements as well as the material change report dated April 16, 2021 available under Enerplus’ SEDAR profile at www.sedar.com and Enerplus’ EDGAR profile under Form 6-K at www.sec.gov.
ENERPLUS 2021 Q2 REPORT 1
OVERVIEW
Global economies have begun to recover from the impacts brought on by the coronavirus (“COVID-19”) pandemic and demand for crude oil improved significantly during the second quarter of 2021. This resulted in higher crude oil prices and improved market sentiment.
During the first half of 2021, we completed two acquisitions, which we expect will provide meaningful free cash flow and core inventory, while increasing the scope and scale of our business. The Bruin Acquisition was completed on March 10, 2021, for total cash consideration of US$465 million, subject to certain purchase price adjustments. The Bruin Acquisition was funded by a new three-year US$400 million term loan and through a portion of the proceeds of a bought deal public offering of common shares, which was completed on February 3, 2021. On April 30, 2021, we completed the Dunn County Acquisition, where we acquired certain assets in the Williston Basin from Hess for total cash consideration of US$312 million, subject to customary purchase price adjustments. The Dunn County Acquisition was funded using our existing cash balance and drawing on our sustainability linked bank credit facility (“Bank Credit Facility” or “SLL Credit Facility”).
During the second quarter of 2021, the Board of Directors approved a 10% increase to the dividend to $0.033 per share paid quarterly, beginning in June 2021, from $0.01 per share paid monthly previously. Subsequent to the quarter, the Board of Directors approved a 15% increase to the dividend to $0.038 per share, to be paid quarterly, beginning September 2021. We expect to fund the increase through the incremental free cash flow generated by the business.
Production during the second quarter of 2021 averaged 115,351 BOE/day, an increase of 26% compared to average production of 91,671 BOE/day in the first quarter of 2021, and crude oil and natural gas liquids production increased by 46% over the same period. The increase in production was primarily due to a full quarter of production from the Bruin Acquisition and a two month contribution from the Dunn County Acquisition. The increase was also due to 19 net operated wells coming onstream in North Dakota at the end of the first quarter of 2021 and into the second quarter of 2021. As a result of strong production volumes during the first half of the year, we are revising our average annual production guidance for 2021 to 112,000 to 115,000 BOE/day, including 69,500 to 71,500 bbls/day in crude oil and natural gas liquids, from 111,000 to 115,000 BOE/day, including 68,500 to 71,500 bbls/day of crude oil and natural gas liquids.
Capital spending during the second quarter of 2021 totaled $129.9 million, compared to $65.5 million during the first quarter of 2021. The majority of the spending was focused on our U.S. crude oil properties. During the second quarter, we reinitiated our drilling program and continued our completion program in North Dakota. We continue to expect capital spending for 2021 to range between $360 to $400 million.
Our realized Bakken crude oil price differential narrowed to average US$2.76/bbl below WTI during the second quarter of 2021 compared to US$3.12/bbl below WTI during the first quarter of 2021. Bakken differentials in North Dakota were supported by increased demand in both the Midwest and U.S. Gulf coast refining markets. With increased certainty of the continued operation of the Dakota Access Pipeline (“DAPL”) and with additional capacity to sell crude oil at U.S. Gulf coast prices due to the expansion of DAPL, we are narrowing our annual Bakken crude oil price differential to average US$2.35/bbl below WTI from US$3.25/bbl below WTI for 2021.
Our realized Marcellus natural gas price differential widened to average US$0.89/Mcf below NYMEX in the second quarter of 2021, compared to US$0.15/Mcf below NYMEX during the first quarter of 2021. As a result of ongoing pipeline maintenance activity in the region, we expect differentials to be wider and have adjusted our annual Marcellus natural gas price differential to average US$0.65/Mcf below NYMEX from US$0.55/Mcf below NYMEX for 2021.
Operating costs for the second quarter of 2021 increased to $88.5 million or $8.43/BOE, compared to $64.5 million or $7.82/BOE, during the first quarter of 2021. This increase was primarily due to higher U.S. crude oil production as a result of the Bruin and Dunn County acquisitions. We continue to expect operating expenses to average $8.25/BOE, during 2021.
We reported a net loss of $59.7 million in the second quarter of 2021 compared to net income of $14.7 million in the first quarter of 2021. The net loss recognized in the second quarter of 2021 was primarily due to a larger commodity derivative instrument loss as a result of significantly higher commodity prices. This was offset by higher crude oil and natural gas liquids revenue as a result of higher production and realized prices.
Cash flow from operations increased to $136.9 million in the second quarter of 2021, compared to $37.2 million in the first quarter of 2021, primarily due to higher realized prices and production. Second quarter adjusted funds flow increased to $184.3 million from $128.0 million over the same period. The increase was primarily due to higher production and an improvement in commodity prices during the quarter.
2 ENERPLUS 2021 Q2 REPORT
During the quarter, we increased and extended our senior unsecured Bank Credit Facility to US$900 million from US$600 million with a maturity of October 31, 2025. In addition, we transitioned the facility to a sustainability-linked credit facility with three sustainability-linked performance targets, which reduce or increase our borrowing costs by up to 5 bps as the targets are exceeded or missed.
At June 30, 2021, our total debt net of cash was $1,132.8 million, comprised of senior notes, Bank Credit Facility and the term loan totaling $1,208.1 million, less cash on hand of $75.3 million. Our net debt to adjusted funds flow ratio was 2.3x, which does not include the trailing adjusted funds flow associated with the Bruin and Dunn County acquisitions.
Subsequent to June 30, 2021, we received approval from the Board of Directors to commence a Normal Course Issuer Bid (“NCIB”) to purchase up to 10% of the public float (within the meaning under Toronto Stock Exchange (“TSX”) rules) during a 12-month period. The NCIB remains subject to approval by the TSX.
RESULTS OF OPERATIONS
Daily production for the second quarter of 2021 averaged 115,351 BOE/day, an increase of 26% compared to average production of 91,671 BOE/day in the first quarter of 2021, with crude oil and natural gas liquids production increasing by 46% to 71,693 bbls/day over the same period. The increase is primarily the result of a full quarter of production from the Bruin assets and a two month contribution from the Dunn County Acquisition. In addition, 19 net operated wells came onstream in North Dakota.
Natural gas production increased slightly to 261,945 Mcf/day, compared to 255,749 Mcf/day in the first quarter of 2021, due to additional natural gas production from the Bruin and Dunn County assets, partially offset by a 6% decrease in production in the Marcellus with less onstream activity in the second quarter of 2021.
For the three months ended June 30, 2021, total production increased by 32% when compared to the same period in 2020. The increase in production was primarily due to a full quarter of production from Bruin’s assets and a two-month contribution of the Dunn County assets in the second quarter of 2021. Production for the three months ended June 30, 2020 was impacted by the temporary curtailment of certain crude oil and natural gas liquids production, and the suspension of our operated North Dakota drilling and completions program during the second quarter of 2020, in response to the significant decline in crude oil prices with the onset of the COVID-19 pandemic.
For the six months ended June 30, 2021, total production increased by 12% compared to the same period in 2020. The increase was mainly due to additional production from the Bruin and Dunn County assets during the first half of 2021. Production for the six months ended June 30, 2020 was also impacted by a decline in natural gas production as a result of limited capital activity in the Marcellus and our decision to shut-in, abandon and reclaim our Canadian natural gas property in Tommy Lakes during the first quarter of 2020.
Our crude oil and natural gas liquids weighting for the three and six months ended June 30, 2021 increased to 62% and 58%, respectively, from 55% for each of the same periods in 2020.
Average daily production volumes for the three and six months ended June 30, 2021 and 2020 are outlined below:
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| | Three months ended June 30, | | Six months ended June 30, | ||||||||
Average Daily Production Volumes | | 2021 | | 2020 | | % Change |
| 2021 | | 2020 | | % Change |
Tight oil (bbls/day) | | 54,797 | | 37,102 | | 48% | | 45,090 | | 39,155 | | 15% |
Heavy oil (bbls/day) | | 4,008 | | 2,912 | | 38% | | 4,063 | | 3,634 | | 12% |
Light and medium oil (bbls/day) | | 2,998 | | 3,154 | | (5)% | | 3,034 | | 3,317 | | (9)% |
Total crude oil (bbls/day) |
| 61,803 |
| 43,168 |
| 43% | | 52,187 |
| 46,106 |
| 13% |
| | | | | | | | | | | | |
Natural gas liquids (bbls/day) |
| 9,890 |
| 4,929 | | 101% | | 8,245 |
| 5,137 | | 61% |
| | | | | | | | | | | | |
Shale gas (Mcf/day) | | 254,556 | | 223,460 | | 14% | | 250,396 | | 235,862 | | 6% |
Conventional natural gas (Mcf/day) | | 7,389 | | 12,119 | | (39)% | | 8,467 | | 13,384 | | (37)% |
Total natural gas (Mcf/day) |
| 261,945 |
| 235,579 | | 11% | | 258,863 |
| 249,246 | | 4% |
Total daily sales (BOE/day) |
| 115,351 |
| 87,360 | | 32% | | 103,576 |
| 92,784 | | 12% |
As a result of strong production volumes during the first half of the year, we are revising our average annual production guidance for 2021 to 112,000 to 115,000 BOE/day, including 69,500 to 71,500 bbls/day in crude oil and natural gas liquids, from 111,000 to 115,000 BOE/day, including 68,500 to 71,500 bbls/day of crude oil and natural gas liquids.
ENERPLUS 2021 Q2 REPORT 3
Pricing
The prices received for crude oil and natural gas production directly impact our earnings, cash flow from operations, adjusted funds flow and financial condition. The following table compares quarterly average benchmark prices, selling prices and differentials:
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| Six months ended June 30, | | | | | | | | | | | | | | | | ||||
Pricing (average for the period) | 2021 | | 2020 | | Q2 2021 | | | Q1 2021 | | | Q4 2020 | | | Q3 2020 | | | Q2 2020 | |||
Benchmarks | |
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WTI crude oil (US$/bbl) | $ | 61.96 | | $ | 37.01 | | $ | 66.07 | | $ | 57.84 | | $ | 42.66 | | $ | 40.93 | | $ | 27.85 |
Brent (ICE) crude oil (US$/bbl) | | 65.06 | | | 42.12 | | | 69.02 | | | 61.10 | | | 45.24 | | | 43.37 | | | 33.27 |
NYMEX natural gas – last day (US$/Mcf) |
| 2.76 | |
| 1.83 | |
| 2.83 | |
| 2.69 | |
| 2.66 | |
| 1.98 | |
| 1.72 |
USD/CDN average exchange rate |
| 1.25 | |
| 1.37 | |
| 1.23 | |
| 1.27 | |
| 1.30 | |
| 1.33 | |
| 1.39 |
USD/CDN period end exchange rate |
| 1.24 | |
| 1.36 | |
| 1.24 | |
| 1.26 | |
| 1.27 | |
| 1.33 | |
| 1.36 |
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Enerplus selling price(1) |
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Crude oil ($/bbl) | $ | 72.90 | | $ | 41.59 | | $ | 76.67 | | $ | 67.34 | | $ | 47.95 | | $ | 46.43 | | $ | 30.55 |
Natural gas liquids ($/bbl) |
| 28.06 | |
| 6.16 | |
| 22.72 | |
| 36.17 | |
| 17.19 | |
| 10.60 | |
| (0.96) |
Natural gas ($/Mcf) |
| 2.96 | |
| 1.87 | |
| 2.45 | |
| 3.48 | |
| 2.04 | |
| 1.72 | |
| 1.63 |
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Average differentials |
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Bakken DAPL – WTI (US$/bbl) | $ | (1.51) | | $ | (5.29) | | $ | (0.40) | | $ | (2.63) | | $ | (3.45) | | $ | (3.40) | | $ | (5.24) |
Brent (ICE) – WTI (US$/bbl) | | 3.10 | | | 5.11 | | | 2.95 | | | 3.26 | | | 2.58 | | | 2.44 | | | 5.42 |
MSW Edmonton – WTI (US$/bbl) | | (3.11) | | | (6.86) | | | (4.18) | | | (5.24) | | | (3.91) | | | (3.51) | | | (6.14) |
WCS Hardisty – WTI (US$/bbl) |
| (11.98) | |
| (16.00) | |
| (11.49) | |
| (12.47) | |
| (9.30) | |
| (9.08) | |
| (11.47) |
Transco Leidy monthly – NYMEX (US$/Mcf) |
| (0.87) | |
| (0.41) | |
| (1.17) | |
| (0.58) | | | (1.24) | |
| (0.80) | |
| (0.45) |
Transco Z6 Non-New York monthly – NYMEX (US$/Mcf) |
| (0.28) | |
| 0.16 | |
| (0.72) | |
| 0.17 | |
| (0.83) | |
| (0.56) | |
| (0.37) |
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Enerplus realized differentials(1)(2) |
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Bakken crude oil – WTI (US$/bbl) | $ | (2.91) | | $ | (4.87) | | $ | (2.76) | | $ | (3.12) | | $ | (4.82) | | $ | (5.37) | | $ | (4.36) |
Marcellus natural gas – NYMEX (US$/Mcf) |
| (0.51) | |
| (0.44) | |
| (0.89) | |
| (0.15) | |
| (1.07) | |
| (0.72) | |
| (0.49) |
Canada crude oil – WTI (US$/bbl) | | (12.17) | | | (16.34) | | | (11.46) | | | (12.89) | | | (10.18) | | | (9.74) | | | (14.49) |
(1) | Excluding transportation costs, royalties and the effects of commodity derivative instruments. |
(2) | Based on a weighted average differential for the period. |
CRUDE OIL AND NATURAL GAS LIQUIDS
During the second quarter of 2021, our realized crude oil sales price averaged $76.67/bbl, an increase of 14% compared to the first quarter of 2021 and consistent with the increase in the benchmark WTI price over the same period. In the U.S., crude oil prices and price differentials strengthened as refinery demand increased due to improving market conditions in developed nations with the easing of COVID-19 restrictions. Oil supply continues to be managed through the agreement made by the Organization of the Petroleum Exporting Countries Plus (“OPEC+”) nations to curtail production from the market through the end of 2022.
Our realized Bakken crude oil price differential averaged US$2.76/bbl below WTI during the second quarter of 2021 compared to US$3.12/bbl below WTI during the first quarter of 2021. Bakken differentials in North Dakota were supported by increased demand in both the Midwest and U.S. Gulf coast refining markets, as well as excess pipeline capacity within the basin.
Our Bakken crude oil sales portfolio consists of a combination of in-basin monthly spot and index sales, term physical sales with fixed differential pricing versus WTI, sales at Cushing, and sales at the U.S. Gulf Coast delivered via firm capacity on DAPL. Effective August 1, 2021, we increased our committed capacity to deliver crude oil from North Dakota to the U.S. Gulf coast via DAPL as a part of its broader system expansion (see “Transportation Expense” in this MD&A). As a result of the additional DAPL transportation and year to date realized pricing, we are narrowing our guidance for our annual Bakken realized crude oil sales price differential to average approximately US$2.35/bbl below WTI in 2021, from US$3.25/bbl below WTI.
Our realized Canadian crude oil price differential narrowed by 11% compared to the first quarter of 2021, which was in line with changes to the underlying benchmark prices.
Our realized sales price for natural gas liquids averaged $22.72/bbl during the second quarter of 2021, compared to $36.17/bbl in the first quarter of 2021. Natural gas liquids prices normalized during the second quarter after they benefited from the cold weather event in February 2021, which was centered over key natural gas liquids pricing hubs in both the Midwest and Texas.
4 ENERPLUS 2021 Q2 REPORT
NATURAL GAS
Our realized natural gas sales price averaged $2.45/Mcf during the second quarter of 2021, a decrease of 30% compared to the first quarter of 2021. Although the NYMEX benchmark price increased by 5% over the same period, Marcellus basin pricing weakened considerably during the quarter due to maintenance activities on regional pipeline systems, and the normal seasonality in pricing we see in the U.S. Northeast during the second quarter.
The lower regional pricing in the Marcellus resulted in our realized Marcellus sales price differential widening to average US$0.89/Mcf below NYMEX during the quarter compared to US$0.15/Mcf below NYMEX in the first quarter of 2021. As a result of ongoing maintenance in the near term, we expect continued weakness in regional price differentials, and, as a result, we are widening our Marcellus differential to average US$0.65/Mcf below NYMEX for 2021, from US$0.55/Mcf below NYMEX.
Our crude oil and natural gas sales are impacted by foreign exchange fluctuations as the majority of our sales are based on U.S. dollar denominated benchmark indices. A stronger Canadian dollar decreases the amount of our realized sales as well as the amount of our U.S. denominated costs, such as capital, the interest on our U.S. denominated debt, and the value of our outstanding U.S. senior notes, term loan and LIBOR based borrowing on our Bank Credit Facility.
The Canadian dollar strengthened significantly during the first six months of 2021 in response to higher commodity prices as global economies continued to stabilize and crude oil demand continued to recover from the onset of the COVID-19 pandemic in the first quarter of 2020. The Canadian dollar exchange rate to U.S. dollar (“USD”) was 1.24 USD/CDN at June 30, 2021, compared to 1.27 USD/CDN at December 31, 2020. The average exchange rate of 1.25 USD/CDN for the six months ended June 30, 2021 was considerably stronger than the same period in 2020 when it averaged 1.37 USD/CDN.
We have a price risk management program that considers our overall financial position, free cash flow and the economics of our capital program.
We continue to expect our hedging contracts to protect a portion of our cash flow from operating activities and adjusted funds flow. As of August 4, 2021, we have hedged 31,500 bbls/day of crude oil for the remainder of 2021 and 20,800 bbls/day during 2022. We have also hedged 100,000 Mcf/day of natural gas for the period of July 1, 2021 to October 31, 2021 and 40,000 Mcf/day for the period of November 1, 2021 to March 31, 2022. Our crude oil contracts consist of swaps and three way collars. The three way collars provide us with exposure to upward price movement; however, the sold put effectively limits the amount of downside protection we have to the difference between the strike price of the purchased and sold puts.
ENERPLUS 2021 Q2 REPORT 5
The following is a summary of our financial contracts in place at August 4, 2021:
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| | WTI Crude Oil (1)(2) | | NYMEX Natural Gas | ||||||||
| | (US$/bbl) | | (US$/Mcf) | ||||||||
| | Jul 1, 2021 – | | Jan 1, 2022 – | | Jan 1, 2023 – | | Nov 1, 2023 – | | Jul 1, 2021 – | | Nov 1, 2021 – |
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| Dec 31, 2021 | | Dec 31, 2022 | | Oct 31, 2023 | | Dec 31, 2023 | | Oct 31, 2021 | | Mar 31, 2022 |
Swaps | | | | | | | | | | | | |
Volume (bbls/day) | | – | | – | | – | | – | | 60,000 | | – |
Sold Swaps | | – | | – | | – | | – | | $ 2.90 | | – |
| | | | | | | ��� | | | | | |
Collars | | | | | | | | | | | | |
Volume (bbls/day) | | 23,000 | | 17,000 | | – | | – | | 40,000 | | 40,000 |
Sold Puts | | $ 36.39 | | $ 40.00 | | – | | – | | $ 2.15 | | – |
Purchased Puts | | $ 46.39 | | $ 50.00 | | – | | – | | $ 2.75 | | $ 3.43 |
Sold Calls | | $ 56.70 | | $ 57.91 | | – | | – | | $ 3.25 | | $ 6.00 |
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Hedges acquired from Bruin(3) | | | | | | | | | | | | |
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Swaps | | | | | | | | | | | | |
Volume (bbls/day) | | 8,465 | | 3,828 | | 250 | | – | | – | | – |
Sold Swaps | | $ 42.52 | | $ 42.35 | | $ 42.10 | | – | | – | | – |
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Collars |
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Volume (bbls/day) | | – | | – | | 2,000 | | 2,000 | | – | | – |
Purchased Puts | | – | | – | | $ 5.00 | | $ 5.00 | | – | | – |
Sold Calls | | – | | – | | $ 75.00 | | $ 75.00 | | – | | – |
(1) | The total average deferred premium spent on our outstanding crude oil contracts is US$0.84/bbl from July 1, 2021 - December 31, 2021 and US$1.22/bbl from January 1, 2022 - December 31, 2022. |
(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 $96.5 million. At June 30, 2021, the balance was a liability of $64.5 million on the Condensed Consolidated Balance Sheets. Realized and unrealized gains and losses on the acquired contracts are recognized in Consolidated Statement of Income/(Loss) and the Consolidated Balance Sheets to reflect changes in crude oil prices from the date of closing of the Bruin Acquisition. See Note 17 to the Interim Financial Statements for further details. |
ACCOUNTING FOR PRICE RISK MANAGEMENT
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Commodity Risk Management Gains/(Losses) | | Three months ended June 30, | | Six months ended June 30, | ||||||||
($ millions) | | 2021 | | 2020 | | 2021 | | 2020 | ||||
Cash gains/(losses): |
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Crude oil | | $ | (37.9) | | $ | 53.5 | | $ | (58.0) | | $ | 86.5 |
Natural gas | |
| 0.7 | |
| — | |
| 1.4 | |
| — |
Total cash gains/(losses) | | $ | (37.2) | | $ | 53.5 | | $ | (56.6) | | $ | 86.5 |
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Non-cash gains/(losses): | |
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Crude oil | | $ | (146.9) | | $ | (64.4) | | $ | (198.5) | | $ | 33.9 |
Natural gas | |
| (13.9) | |
| — | |
| (12.7) | |
| — |
Total non-cash gains/(losses) | | $ | (160.8) | | $ | (64.4) | | $ | (211.2) | | $ | 33.9 |
Total gains/(losses) | | $ | (198.0) | | $ | (10.9) | | $ | (267.8) | | $ | 120.4 |
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| | Three months ended June 30, | | Six months ended June 30, | ||||||||
(Per BOE) | | 2021 | | 2020 | | 2021 | | 2020 | ||||
Total cash gains/(losses) |
| $ | (3.53) |
| $ | 6.73 |
| $ | (3.02) |
| $ | 5.12 |
Total non-cash gains/(losses) | |
| (15.32) |
| | (8.10) |
| | (11.27) |
| | 2.01 |
Total gains/(losses) | | $ | (18.85) | | $ | (1.37) | | $ | (14.29) | | $ | 7.13 |
We realized cash losses of $37.9 million and $58.0 million, respectively, on our crude oil contracts during the three and six months ended June 30, 2021, compared to realized cash gains of $53.5 million and $86.5 million for the same periods in 2020. We recorded realized cash gains of $0.7 million and $1.4 million, respectively, on our natural gas contracts in the three and six months ended June 30, 2021 and there were no natural gas derivative contracts outstanding during the same periods in 2020.
6 ENERPLUS 2021 Q2 REPORT
As the forward markets for crude oil and natural gas fluctuate, as new contracts are executed, and as existing contracts are realized, changes in fair value are reflected as either a non-cash charge or gain to earnings. At June 30, 2021, the fair value of our crude oil and natural gas contracts was in a net liability position of $287.9 million. For the three and six months ended June 30, 2021, the change in the fair value of our crude oil contracts resulted in an unrealized loss of $146.9 million and $198.5 million, respectively, compared to a loss of $64.4 million and a gain of $ 33.9 million, respectively, during the same periods in 2020. We recorded unrealized losses on our natural gas contracts of $13.9 million and $12.7 million, respectively, for the three and six months ended June 30, 2021.
On March 10, 2021, the outstanding crude oil contracts acquired with the Bruin Acquisition were recorded at fair value, resulting in a liability of $96.5 million on the 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 closing date of the Bruin Acquisition. At June 30, 2021, the fair value of the Bruin contracts was a liability of $99.9 million, including $64.5 million of the original $96.5 million liability acquired. For the three and six months ended June 30, 2021 we recorded a realized loss of $2.2 million and $1.7 million, respectively, on the settlement of the Bruin contracts. In addition, we recognized an unrealized loss of $52.8 million and $35.4 million, respectively, for the change in the fair value of the Bruin contracts over the same periods. See Note 17 to the Interim Financial Statements for further detail.
Revenues
| | | | | | | | | | | | |
| | Three months ended June 30, | | Six months ended June 30, | ||||||||
($ millions) | | 2021 | | 2020 |
| 2021 |
| 2020 | ||||
Crude oil and natural gas sales | | $ | 510.2 | | $ | 155.3 | | $ | 869.5 | | $ | 440.9 |
Royalties | |
| (101.6) | |
| (33.2) | |
| (172.1) | |
| (90.7) |
Crude oil and natural gas sales, net of royalties | | $ | 408.6 | | $ | 122.1 | | $ | 697.4 | | $ | 350.2 |
Crude oil and natural gas sales, net of royalties, for the three and six months ended June 30, 2021 were $408.6 million and $697.4 million, respectively, compared to $122.1 million and $350.2 million, from the same periods in 2020. The increase in revenue was primarily due to higher production as a result of the Bruin and Dunn County acquisitions in 2021 and higher realized prices. Revenues in 2020 were impacted by lower realized prices as a result of the demand destruction from the COVID-19 pandemic and the Saudi Arabia and Russian price war, along with price related production curtailments.
Royalties and Production Taxes
| | | | | | | | | | | |
| Three months ended June 30, | | Six months ended June 30, | ||||||||
($ millions, except per BOE amounts) | 2021 | | 2020 | | 2021 | | 2020 | ||||
Royalties | $ | 101.6 | | $ | 33.2 |
| $ | 172.1 |
| $ | 90.7 |
Per BOE | $ | 9.68 | | $ | 4.18 | | $ | 9.18 | | $ | 5.37 |
| | | | | | | | | | | |
Production taxes | $ | 30.5 | | $ | 7.7 | | $ | 48.0 | | $ | 23.1 |
Per BOE | $ | 2.90 | | $ | 0.97 | | $ | 2.56 | | $ | 1.37 |
Royalties and production taxes | $ | 132.1 | | $ | 40.9 | | $ | 220.1 | | $ | 113.8 |
Per BOE | $ | 12.58 | | $ | 5.15 | | $ | 11.74 | | $ | 6.74 |
| | | | | | | | | | | |
Royalties and production taxes (% of crude oil and natural gas sales) | | 25.9% | | | 26.3% | | | 25.3% | | | 25.8% |
Royalties are paid to government entities, land owners and mineral rights owners. Production taxes include state production taxes, Pennsylvania impact fees and freehold mineral taxes. A large percentage of our production is from U.S. properties where royalty rates are generally higher than in Canada. Royalties and production taxes for the three and six months ended June 30, 2021, were $132.1 million and $220.1 million, respectively, compared to $40.9 million and $113.8 million from the same periods in 2020. Total royalties increased due to higher realized prices and higher production volumes, compared to lower realized prices and lower production volumes during the comparative periods in 2020.
We continue to expect annual royalties and production taxes in 2021 to average 26% of crude oil and natural gas sales before transportation.
ENERPLUS 2021 Q2 REPORT 7
Operating Expenses
| | | | | | | | | | | | |
| | Three months ended June 30, | | Six months ended June 30, | ||||||||
($ millions, except per BOE amounts) | | 2021 | | 2020 | | 2021 | | 2020 | ||||
Operating expenses |
| $ | 88.5 |
| $ | 54.4 |
| $ | 153.0 |
| $ | 133.4 |
Per BOE | | $ | 8.43 | | $ | 6.84 | | $ | 8.16 | | $ | 7.90 |
For the three and six months ended June 30, 2021, operating expenses were $88.5 million or $8.43/BOE and $153.0 million or $8.16/BOE, respectively, compared to $54.4 million or $6.84/BOE and $133.4 million or $7.90/BOE, for the same periods in 2020. This increase was primarily due to higher U.S. crude oil production, as a result of the Bruin and Dunn County acquisitions and increased liquids weighting, partially offset by a stronger Canadian dollar in 2021. Operating expenses were lower during the three and six months ended June 30, 2020 primarily due to the price-related production curtailment of our highest unit expense crude oil wells, along with less well servicing activity and lower service costs.
We continue to expect operating expenses of $8.25/BOE in 2021.
| | | | | | | | | | | | |
| | Three months ended June 30, | | Six months ended June 30, | ||||||||
($ millions, except per BOE amounts) | | 2021 | | 2020 | | 2021 | | 2020 | ||||
Transportation expenses |
| $ | 36.2 |
| $ | 34.0 |
| $ | 69.0 |
| $ | 69.3 |
Per BOE | | $ | 3.45 | | $ | 4.28 | | $ | 3.68 | | $ | 4.11 |
For the three and six months ended June 30, 2021, transportation expenses were $36.2 million or $3.45/BOE and $69.0 million or $3.68/BOE, respectively, compared to $34.0 million or $4.28/BOE and $69.3 million or $4.11/BOE, for the same periods in 2020. Transportation expenses decreased on a per BOE basis for both the three and six months periods ended June 30, 2021 compared to the same periods in 2020, primarily due to the impact of a stronger Canadian dollar on our U.S. dollar denominated transportation costs.
Effective August 1, 2021, Enerplus participated in the DAPL expansion with an additional 6,500 bbls/day of firm crude oil transportation. The additional transportation provides access to sell a greater portion of our production at U.S. Gulf Coast or Brent pricing.
We continue to expect transportation expenses of $3.85/BOE in 2021.
Netbacks
The crude oil and natural gas classifications below contain properties according to their dominant production category. These properties may include associated crude oil, natural gas or natural gas liquids volumes which have been converted to the equivalent BOE/day or Mcfe/day and as such, the revenue per BOE or per Mcfe may not correspond with the average selling price under the “Pricing” section of this MD&A.
| | | | | | | | | |
| | Three months ended June 30, 2021 | |||||||
Netbacks by Property Type | | Crude Oil | | Natural Gas | | Total | |||
Average Daily Production |
| 81,934 BOE/day |
| 200,503 Mcfe/day |
| 115,351 BOE/day | |||
Netback(1) $ per BOE or Mcfe |
| (per BOE) |
| (per Mcfe) |
| (per BOE) | |||
Crude oil and natural gas sales | | $ | 62.51 | | $ | 2.42 | | $ | 48.60 |
Royalties and production taxes | |
| (16.49) | |
| (0.50) | |
| (12.58) |
Operating expenses | |
| (11.47) | |
| (0.16) | |
| (8.43) |
Transportation expenses | |
| (2.64) | |
| (0.91) | |
| (3.45) |
Netback before hedging | | $ | 31.91 | | $ | 0.85 | | $ | 24.14 |
Cash hedging gains/(losses) | |
| (5.08) | |
| 0.04 | |
| (3.53) |
Netback after hedging | | $ | 26.83 | | $ | 0.89 | | $ | 20.61 |
Netback before hedging ($ millions) | | $ | 237.9 | | $ | 15.5 | | $ | 253.4 |
Netback after hedging ($ millions) | | $ | 200.0 | | $ | 16.2 | | $ | 216.2 |
(1) | See “Non-GAAP Measures” in this MD&A. |
8 ENERPLUS 2021 Q2 REPORT
| | | | | | | | | |
| | Three months ended June 30, 2020 | |||||||
Netbacks by Property Type | | Crude Oil | | Natural Gas | | Total | |||
Average Daily Production |
| 52,198 BOE/day |
| 210,971 Mcfe/day |
| 87,360 BOE/day | |||
Netback(1) $ per BOE or Mcfe |
| (per BOE) |
| (per Mcfe) |
| (per BOE) | |||
Crude oil and natural gas sales | | $ | 25.63 | | $ | 1.75 | | $ | 19.53 |
Royalties and production taxes | |
| (7.18) | |
| (0.35) | |
| (5.15) |
Operating expenses | |
| (10.45) | |
| (0.25) | |
| (6.84) |
Transportation expenses | |
| (3.21) | |
| (0.98) | |
| (4.28) |
Netback before hedging | | $ | 4.79 | | $ | 0.17 | | $ | 3.26 |
Cash hedging gains/(losses) | |
| 11.26 | |
| — | |
| 6.73 |
Netback after hedging | | $ | 16.05 | | $ | 0.17 | | $ | 9.99 |
Netback before hedging ($ millions) | | $ | 22.7 | | $ | 3.3 | | $ | 26.0 |
Netback after hedging ($ millions) | | $ | 76.2 | | $ | 3.3 | | $ | 79.5 |
| | | | | | | | | |
| | Six months ended June 30, 2021 | |||||||
Netbacks by Property Type | | Crude Oil | | Natural Gas | | Total | |||
Average Daily Production |
| 68,876 BOE/day |
| 208,199 Mcfe/day |
| 103,576 BOE/day | |||
Netback(1) $ per BOE or Mcfe |
| (per BOE) |
| (per Mcfe) |
| (per BOE) | |||
Crude oil and natural gas sales | | $ | 61.09 | | $ | 2.86 | | $ | 46.38 |
Royalties and production taxes | |
| (15.92) | |
| (0.57) | |
| (11.74) |
Operating expenses | |
| (11.75) | |
| (0.17) | |
| (8.16) |
Transportation expenses | |
| (2.81) | |
| (0.90) | |
| (3.68) |
Netback before hedging | | $ | 30.61 | | $ | 1.22 | | $ | 22.80 |
Cash hedging gains/(losses) | |
| (4.65) | |
| 0.04 | |
| (3.02) |
Netback after hedging | | $ | 25.96 | | $ | 1.26 | | $ | 19.78 |
Netback before hedging ($ millions) | | $ | 381.6 | | $ | 45.8 | | $ | 427.4 |
Netback after hedging ($ millions) | | $ | 323.6 | | $ | 47.2 | | $ | 370.8 |
| | | | | | | | | |
| | Six months ended June 30, 2020 | |||||||
Netbacks by Property Type | | Crude Oil | | Natural Gas | | Total | |||
Average Daily Production | | 55,716 BOE/day | | 222,410 Mcfe/day |
| 92,784 BOE/day | |||
Netback(1) $ per BOE or Mcfe |
| (per BOE) |
| (per Mcfe) |
| (per BOE) | |||
Crude oil and natural gas sales | | $ | 35.63 | | $ | 1.96 | | $ | 26.11 |
Royalties and production taxes | |
| (9.71) | |
| (0.38) | |
| (6.74) |
Operating expenses | |
| (11.99) | |
| (0.29) | |
| (7.90) |
Transportation expenses | |
| (3.05) | |
| (0.95) | |
| (4.11) |
Netback before hedging | | $ | 10.88 | | $ | 0.34 | | $ | 7.36 |
Cash hedging gains/(losses) | |
| 8.53 | |
| — | |
| 5.12 |
Netback after hedging | | $ | 19.41 | | $ | 0.34 | | $ | 12.48 |
Netback before hedging ($ millions) | | $ | 110.4 | | $ | 14.0 | | $ | 124.4 |
Netback after hedging ($ millions) | | $ | 196.9 | | $ | 14.0 | | $ | 210.9 |
(1) | See “Non-GAAP Measures” in this MD&A. |
Total netbacks before and after hedging for the three and six months ended June 30, 2021, were higher compared to the same periods in 2020, primarily due to higher realized prices and higher production.
For the three months ended June 30, 2021, our crude oil properties accounted for 94% and 89%, respectively, of our total netback before hedging, compared to 87% and 89% during the same period in 2020.
ENERPLUS 2021 Q2 REPORT 9
General and Administrative (“G&A”) Expenses
Total G&A expenses include share-based compensation (“SBC”) charges related to our long-term incentive plans (“LTI plans”). See Note 13 and Note 16(b) to the Interim Financial Statements for further details.
| | | | | | | | | | | | |
| | Three months ended June 30, | | Six months ended June 30, | ||||||||
($ millions) | | 2021 | | 2020 | | 2021 | | 2020 | ||||
Cash: |
| |
|
| |
|
| |
|
| |
|
G&A expenses | | $ | 10.9 | | $ | 9.1 | | $ | 24.0 | | $ | 21.5 |
Share-based compensation expense | |
| 2.3 | |
| 1.2 | |
| 5.1 | |
| (1.6) |
| |
| | |
| | |
| | |
| |
Non-Cash: | |
| | |
| | |
| | |
| |
Share-based compensation expense | |
| 0.1 | |
| 3.6 | |
| 1.2 | |
| 11.3 |
Equity swap loss/(gain) | |
| (0.7) | |
| (0.5) | |
| (1.3) | |
| 1.4 |
G&A expenses | | | (0.1) | | | 0.1 | | | (0.2) | | | 0.1 |
Total G&A expenses | | $ | 12.5 | | $ | 13.5 | | $ | 28.8 | | $ | 32.7 |
| | | | | | | | | | | | |
| | Three months ended June 30, | | Six months ended June 30, | ||||||||
(Per BOE) | | 2021 | | 2020 | | 2021 | | 2020 | ||||
Cash: |
| |
|
| |
|
| |
|
| |
|
G&A expenses | | $ | 1.04 | | $ | 1.14 | | $ | 1.28 | | $ | 1.26 |
Share-based compensation expense | |
| 0.22 | |
| 0.15 | |
| 0.27 | |
| (0.09) |
| |
| | |
| | |
| | |
| |
Non-Cash: | |
| | |
| | |
| | |
| |
Share-based compensation expense | |
| 0.01 | |
| 0.45 | |
| 0.06 | |
| 0.67 |
Equity swap loss/(gain) | |
| (0.07) | |
| (0.06) | |
| (0.07) | |
| 0.08 |
G&A expenses | | | (0.01) | | | 0.01 | | | (0.01) | | | 0.01 |
Total G&A expenses | | $ | 1.19 | | $ | 1.69 | | $ | 1.53 | | $ | 1.93 |
Cash G&A expenses for the three and six months ended June 30, 2021, were $10.9 million or $1.04/BOE and $24.0 million or $1.28/BOE, respectively, compared to $9.1 million or $1.14/BOE and $21.5 million or $1.26/BOE for the same periods in 2020. Cash G&A expenses were higher compared to the same periods in 2020 due to government funding received related to the second quarter of 2020, during the height of the COVID-19 pandemic, which reimbursed qualifying Canadian employers for a portion of salaries paid. Cash G&A on a per BOE basis decreased compared to the three months ended June 30, 2021, due to higher production in the second quarter of 2021.
Cash SBC expenses for the three and six months ended June 30, 2021, were $2.3 million and $5.1 million, respectively, compared to an expense of $1.2 million and a recovery of $1.6 million, respectively, for the same periods in 2020. The higher expense was due to the increase in our share price on our outstanding Director Deferred Share Units. Non-cash SBC expense for the three and six months ended June 30, 2021 were $0.1 million or $0.01/BOE and $1.2 million or $0.06/BOE, respectively, compared to $3.6 million or $0.45/BOE and $11.3 million or $0.67/BOE, respectively for the same periods in 2020. The decrease in non-cash SBC expense was the result of lower performance multipliers on our outstanding Performance Share Units (“PSUs”).
We have hedges in place on a portion of the outstanding cash-settled grants under our LTI plans. During the three and six months ended June 30, 2021, we recorded a mark-to-market gain of $0.7 million and $1.3 million, as a result of the increase in our share price.
We continue to expect cash G&A expenses of $1.25/BOE.
Interest Expense
For the three months and six months ended June 30, 2021, we recorded total interest expense of $9.5 million and $16.4 million, respectively, compared to $7.1 million and $16.0 million, respectively, for the same periods in 2020. The increase was primarily due to increased debt levels used to fund the Bruin and Dunn County acquisitions. The increase was partially offset by the final repayment of our 2009 senior notes and the partial repayment of our 2012 senior notes during the second quarter of 2021, which carry higher interest rates than our Bank Credit Facility as well as the strengthening of the Canadian dollar on our U.S. dollar denominated interest expense.
At June 30, 2021, approximately 31% of our debt was based on fixed interest rates and 69% on floating interest rates (December 31, 2020 – 100% fixed), with weighted average interest rates of 4.4% and 1.9%, respectively (December 31, 2020 – 4.4%). See Note 9 to the Interim Financial Statements for further details.
10 ENERPLUS 2021 Q2 REPORT
Foreign Exchange
| | | | | | | | | ��� | | | |
| | Three months ended June 30, | | Six months ended June 30, | ||||||||
($ millions) | | 2021 | | 2020 | | 2021 | | 2020 | ||||
Realized foreign exchange (gain)/loss: | | | | | | | | | | | | |
Foreign exchange (gain)/loss on settlements |
| $ | 3.8 |
| $ | 0.1 |
| $ | 3.1 |
| $ | — |
Translation of U.S. dollar cash held in Canada (gain)/loss | | | (2.4) | | | 0.4 | | | (2.0) | | | (2.7) |
Unrealized foreign exchange (gain)/loss | |
| 5.5 | |
| 1.0 | |
| 5.9 | |
| (1.4) |
Total foreign exchange (gain)/loss | | $ | 6.9 | | $ | 1.5 | | $ | 7.0 | | $ | (4.1) |
USD/CDN average exchange rate | |
| 1.23 | |
| 1.39 | | | 1.25 | | | 1.37 |
USD/CDN period end exchange rate | |
| 1.24 | |
| 1.36 | |
| 1.24 | |
| 1.36 |
For the three and six months ended June 30, 2021, we recorded a foreign exchange loss of $6.9 million and $7.0 million, respectively, compared to a loss of $1.5 million and a gain of $4.1 million, respectively, for the same periods in 2020. Realized foreign exchange gains and losses relate primarily to day-to-day transactions recorded in foreign currencies and the translation of our U.S. dollar denominated cash held in Canada, while unrealized foreign exchange gains and losses are recorded on the translation of our U.S. dollar denominated Bank Credit Facility and working capital held in Canada at each period end.
At June 30, 2021, US$303.8 million of senior notes outstanding and the US$400 million term loan were designated as net investment hedges. For the three and six months ended June 30, 2021, Other Comprehensive Income/(Loss) included an unrealized gain of $14.7 million and $23.2 million, respectively, on our U.S. dollar denominated senior notes and term loan compared to an unrealized gain of $19.5 million and an unrealized loss of $30.6 million, respectively for the same periods in 2020.
Capital Investment
| | | | | | | | | | | | |
| | Three months ended June 30, | | Six months ended June 30, | ||||||||
($ millions) | | 2021 | | 2020 | | 2021 | | 2020 | ||||
Capital spending(1) |
| $ | 129.9 |
| $ | 40.1 | | $ | 195.4 |
| $ | 203.7 |
Office capital(1) | |
| 0.5 | |
| 0.9 | |
| 0.9 | |
| 2.8 |
Sub-total | |
| 130.4 | |
| 41.0 | |
| 196.3 | |
| 206.5 |
Property and land acquisitions | | $ | 1.7 | | $ | 3.4 | | $ | 5.1 | | $ | 5.7 |
Bruin Acquisition | | | 32.3 | | | — | | | 657.5 | | | — |
Dunn County Acquisition | | | 374.8 | | | — | | | 374.8 | | | — |
Property divestments | |
| — | |
| 0.1 | |
| (5.0) | |
| (5.5) |
Sub-total | |
| 408.8 | |
| 3.5 | |
| 1,032.4 | |
| 0.2 |
Total | | $ | 539.2 | | $ | 44.5 | | $ | 1,228.7 | | $ | 206.7 |
(1) | Excludes changes in non-cash investing working capital. See Note 18(c) to the Interim Financial Statements for further details. |
Capital spending for the three and six months ended June 30, 2021 totaled $129.9 million and $195.4 million, respectively, compared to $40.1 million and $203.7 million, respectively, for the same periods in 2020. The increase is mainly due to the suspension of operated drilling and completions activity in North Dakota during the second quarter of 2020 and the start of the 2021 capital program in early March. Capital spending during the second quarter of 2021 included $116.8 million on our U.S. crude oil properties, $8.7 million on our Marcellus natural gas assets and $4.4 million on our Canadian waterflood properties.
On April 30, 2021, we completed the Dunn County Acquisition for total cash consideration of $376.9 million, with $374.8 million allocated to PP&E, excluding the assumed asset retirement obligation.
During the six months ended June 30, 2021, we completed the Bruin Acquisition for total cash consideration of $531.1 million, with $657.5 million allocated to PP&E, excluding the assumed asset retirement obligation.
We continue to expect our capital spending for 2021 to range between $360 to $400 million.
ENERPLUS 2021 Q2 REPORT 11
Depletion, Depreciation and Accretion (“DD&A”)
| | | | | | | | | | | | |
| | Three months ended June 30, | | Six months ended June 30, | ||||||||
($ millions, except per BOE amounts) | | 2021 | | 2020 | | 2021 | | 2020 | ||||
DD&A expense |
| $ | 93.9 |
| $ | 79.9 |
| $ | 140.4 |
| $ | 175.1 |
Per BOE | | $ | 8.95 | | $ | 10.05 | | $ | 7.49 | | $ | 10.37 |
DD&A related to PP&E is recognized using the unit-of-production method based on proved reserves. For the three and six months ended June 30, 2021, we recorded DD&A expense of $93.9 million and $140.4 million, respectively, compared to $79.9 million and $175.1 million, respectively, for the same periods in 2020. DD&A expense on a per BOE basis decreased compared to the same periods in 2020 mainly due to the impact of previous PP&E impairments.
Impairment
PP&E
Under U.S. GAAP, the full cost ceiling test is performed on a country-by-country basis using estimated after-tax future net cash flows discounted at a prescribed 10 percent rate based on proved reserves using SEC constant prices ("Standardized Measure"). SEC prices are calculated as the unweighted average of the trailing twelve first-day-of-the-month commodity prices. The Standardized Measure is not related to Enerplus' investment criteria and is not a fair value based measurement, but rather a prescribed accounting calculation. Impairments are non-cash and are not reversed in future periods under U.S. GAAP. See Note 7(a) to the Interim Financial Statements for trailing twelve month prices.
Trailing twelve month average crude oil and natural gas prices declined throughout 2020 and have improved throughout 2021. For the three and six months ended June 30, 2021, we recorded a non-cash PP&E impairment of nil and $4.3 million, respectively, related to our Canadian assets. For the three and six months ended June 30, 2020, we recorded a non-cash PP&E impairment of $426.8 million (Canadian cost centre: $77.5 million, U.S. cost centre: $349.3 million).
We requested and received a temporary exemption from the SEC to exclude the properties acquired in the Bruin Acquisition in the U.S. full cost ceiling test, for each quarter of 2021. See Note 7(b) to the Interim Financial Statements for further details.
Many factors influence the allowed ceiling value versus our net capitalized cost base, making it difficult to predict with reasonable certainty the value of impairment losses from future ceiling tests. For the remainder of 2021, the primary factors include future first-day-of-the-month commodity prices, reserves revisions, capital expenditure levels and timing, acquisition and divestment activity, as well as production levels, which affect DD&A expense. See "Risk Factors and Risk Management - Risk of Impairment of Oil and Gas Properties and Deferred Tax Assets" in the Annual MD&A.
Goodwill
During the second quarter of 2020, we recorded a non-cash goodwill impairment of $202.8 million related to our U.S. reporting unit. The impairment was a result of the ongoing deterioration in macroeconomic conditions and low commodity prices due to the COVID-19 pandemic, which resulted in a reduction in the fair value of the U.S. reporting unit and a full write-off of our U.S. goodwill asset. At June 30, 2021, there was no goodwill remaining on our Condensed Consolidated Balance Sheet.
Asset Retirement Obligation (“ARO”)
In connection with our operations, we incur abandonment, reclamation and remediation costs related to assets, such as surface leases, wells, facilities and pipelines. Total ARO included on the Condensed Consolidated Balance Sheet is based on management’s estimate of our net ownership interest, costs to abandon, reclaim and remediate and the timing of the costs to be incurred in future periods. We have estimated the net present value of our asset retirement obligation, using a weighted average credit-adjusted risk-free rate of 5.05%, to be $160.2 million at June 30, 2021, compared to $130.2 million at December 31, 2020, using a weighted average credit-adjusted risk-free rate of 5.35%. The increase in the net present value of our asset retirement obligation to June 30, 2021 is largely due to $35.0 million of additional liability assumed in connection with the Bruin and Dunn County acquisitions. For the three and six months ended June 30, 2021, asset retirement obligation settlements were $1.4 million and $8.4 million, respectively, compared to $0.3 million and $11.1 million, respectively, during the same periods in 2020.
In 2021, Enerplus benefited from provincial government assistance to support the cleanup of inactive or abandoned crude oil and natural gas wells in Canada. These programs provide funding directly to oil field service contractors engaged by Enerplus to perform abandonment, remediation, and reclamation work. The funding received by the contractor is reflected as a reduction to ARO. For the six months ended June 30, 2021, Enerplus benefitted from $2.4 million in government assistance. See Note 3 and 10 to the Interim Financial Statements for further details.
12 ENERPLUS 2021 Q2 REPORT
Leases
Enerplus recognizes right-of-use (“ROU”) assets and lease liabilities on the Condensed Consolidated Balance Sheet for qualifying leases with a term greater than 12 months. We incur lease payments related to office space, drilling rig commitments, vehicles, and other equipment. Total lease liabilities are based on the present value of lease payments over the lease term. Total ROU assets represent our right to use an underlying asset for the lease term. At June 30, 2021, our total lease liability was $40.6 million (December 31, 2020 - $36.8 million). In addition, ROU assets of $37.0 million were recorded, which equate to our lease liabilities less lease incentives (December 31, 2020 - $32.9 million). See Note 11 to the Interim Financial Statements for further details.
Income Taxes
| | | | | | | | | | | | |
| | Three months ended June 30, | | Six months ended June 30, | ||||||||
($ millions) | | 2021 | | 2020 | | 2021 | | 2020 | ||||
Current tax expense/(recovery) |
| $ | 4.2 |
| $ | (14.4) |
| $ | 4.2 |
| $ | (14.4) |
Deferred tax expense/(recovery) | |
| (11.1) | |
| (98.9) | |
| (0.1) | |
| 10.4 |
Total tax expense/(recovery) | | $ | (6.9) | | $ | (113.3) | | $ | 4.1 | | $ | (4.0) |
For the three and six months ended June 30, 2021, we recorded a current tax expense of $4.2 million compared to a recovery of $14.4 million in 2020. The current tax expense in the second quarter primarily consists of U.S. Federal tax as a result of higher income in the U.S. in 2021. The recovery in 2020 relates to the final U.S. Alternative Minimum Tax ("AMT") refund.
We expect current tax expense of between US$5.0 to US$7.0 million in 2021.
For the three and six months ended June 30, 2021, we recorded deferred income tax recoveries of $11.1 million and $0.1 million respectively, compared to a recovery of $98.9 million and an expense of $10.4 million for the same periods in 2020. The deferred tax recovery in the second quarter was primarily due to the non-cash commodity derivative losses partially offset by higher U.S. income in 2021. The deferred tax recovery in 2020 was primarily due to non-cash PP&E impairments recorded in both Canada and the U.S.
We assess the recoverability of our deferred income tax assets each period to determine whether it is more likely than not all or a portion of our deferred income tax assets will not be realized. We have considered available positive and negative evidence including future taxable income and reversing existing temporary differences in making this assessment. This assessment is primarily the result of projecting future taxable income using total proved and probable reserves at forecast average prices and costs. There is a risk of a valuation allowance in future periods if commodity prices weaken or other evidence indicates that some of our deferred income tax assets will not be realized. See "Risk Factors and Risk Management - Risk of Impairment of Oil and Gas Properties and Deferred Tax Assets" in the Annual MD&A. For the six months ended June 30, 2021, no valuation allowance was recorded against our U.S. and Canadian income related deferred income tax assets, however, a full valuation allowance has been recorded against our deferred income tax assets related to capital items. Our overall net deferred income tax asset was $600.3 million at June 30, 2021 (December 31, 2020 - $607.0 million).
LIQUIDITY AND CAPITAL RESOURCES
There are numerous factors that influence how we assess liquidity and leverage, including commodity price cycles, capital spending levels, acquisition and divestment plans, hedging, share repurchases and dividend levels. We also assess our leverage relative to our most restrictive debt covenant under our Bank Credit Facility, term loan and senior notes, which is a maximum senior debt to earnings before interest, taxes, depreciation, amortization, impairment and other non-cash charges (“adjusted EBITDA”) ratio of 3.5x for a period of up to six months, after which it drops to 3.0x. At June 30, 2021, our senior debt to adjusted EBITDA ratio was 2.0x and our net debt to adjusted funds flow ratio was 2.3x, which does not include the trailing adjusted funds flow associated with the Bruin and Dunn County acquisitions. Although it is not included in our debt covenants, the net debt to adjusted funds flow ratio is often used by investors and analysts to evaluate liquidity. Refer to the definitions and footnotes below.
Total debt net of cash at June 30, 2021 increased to $1,132.8 million, compared to $376.0 million at December 31, 2020. Total debt was comprised of our senior notes, term loan and Bank Credit Facility, totaling $1,208.1 million, less cash on hand of $75.3 million. The increase was due to funding a portion of the Bruin Acquisition using a US$400 million term loan and funding the Dunn County Acquisition by drawing on our Bank Credit Facility and cash on hand.
During the second quarter of 2021, Enerplus made its final US$22.0 million principal repayment on its 2009 senior notes and its second US$59.6 million principal repayment on its 2012 senior notes, using the Bank Credit Facility. This resulted in a $99.3 million decrease to our outstanding senior notes at June 30, 2021, compared to December 31, 2020.
ENERPLUS 2021 Q2 REPORT 13
Our adjusted payout ratio, which is calculated as cash dividends plus capital and office expenditures divided by adjusted funds flow, was 77% and 69%, respectively, for the three and six months ended June 30, 2021, compared to 68% and 120% for the same periods in 2020.
During the second quarter of 2021, the Board of Directors approved a 10% increase to the dividend to $0.033 per share paid quarterly, beginning in June, from $0.01 per share paid monthly previously. Subsequent to the quarter, the Board of Directors approved a 15% increase to the dividend to $0.038 per share, to be paid quarterly, beginning September 2021. We expect to fund the increase though the incremental free cash flow generated by the business.
Subsequent to June 30, 2021, we received approval from the Board of Directors to commence a NCIB to purchase up to 10% of the public float (within the meaning under TSX rules) during a 12-month period. The NCIB remains subject to approval by the TSX.
Our working capital deficiency, excluding cash and current derivative financial assets and liabilities, decreased to $231.1 million at June 30, 2021 from $257.8 million at December 31, 2020. Our working capital varies due to the timing of the cash realization of our current assets and current liabilities, and the current level of business activity, including our capital spending program, along with commodity price volatility. We expect to finance our working capital deficit and ongoing working capital requirements through cash, adjusted funds flow and our Bank Credit Facility. We have sufficient liquidity to meet our financial commitments for the near term.
During the second quarter, we increased and extended our senior, unsecured, covenant-based Bank Credit Facility to US$900 million from US$600 million with a maturity of October 31, 2025. As part of the extension, the Company transitioned the facility to a sustainability-linked credit facility incorporating environmental, social and governance (“ESG”)-linked incentive pricing terms which reduce or increase the borrowing costs by up to 5 basis points as Enerplus’ sustainability performance targets (“SPT”) are exceeded or missed. The SPTs are based on the following ESG goals of the Company:
● | GHG Emissions: continuous progress toward Enerplus’ stated goal of a 50% reduction in corporate Scope 1 and 2 greenhouse gas emissions intensity by 2030, using 2019 as a baseline and measurement based on Enerplus’ annual internal targets; |
● | Water Management: achieve a 50% reduction in freshwater usage in corporate well completions by 2025 or earlier compared to 2019, with progress to be measured on an annual basis over the life of the credit facility; and |
● | Health & Safety: achieve and maintain a 25% reduction in the Company’s Lost Time Injury Frequency, based on a trailing 3-year average, relative to a 2019 baseline. |
At June 30, 2021, we were in compliance with all covenants under the Bank Credit Facility, the term loan and outstanding senior notes. If we exceed or anticipate exceeding our covenants, we may be required to repay, refinance or renegotiate the terms of the debt. See "Risk Factors – Debt covenants of the Corporation may be exceeded with no ability to negotiate covenant relief" in the Annual Information Form. Agreements relating to our Bank Credit Facility and term loan and the senior note purchase agreements have been filed under our SEDAR profile at www.sedar.com.
14 ENERPLUS 2021 Q2 REPORT
The following table lists our financial covenants as at June 30, 2021:
| | | | |
Covenant Description |
|
|
| June 30, 2021 |
Bank Credit Facility/Term Loan: |
| Maximum Ratio | | |
Senior debt to adjusted EBITDA (1) |
| 3.5x |
| 2.0x |
Total debt to adjusted EBITDA (1) |
| 4.0x |
| 2.0x |
Total debt to capitalization | | 55% | | 42% |
| | | | |
Senior Notes: |
| Maximum Ratio | | |
Senior debt to adjusted EBITDA (1)(2) |
| 3.0x - 3.5x |
| 2.0x |
Senior debt to consolidated present value of total proved reserves(3) | | 60% | | 47% |
|
| Minimum Ratio | | |
Adjusted EBITDA to interest (1) |
| 4.0x |
| 21.6x |
Definitions
“Senior debt” is calculated as the sum of drawn amounts on our Bank Credit Facility, term loan, outstanding letters of credit and the principal amount of senior notes.
“Adjusted EBITDA” is calculated as net income less interest, taxes, depletion, depreciation, amortization, accretion, impairment and other non-cash gains and losses. Adjusted EBITDA is calculated on a trailing twelve-month basis and is adjusted for material acquisitions and divestments. Adjusted EBITDA for the three months and the trailing twelve months ended June 30, 2021 was $203.7 million and $621.3 million, respectively.
“Total debt” is calculated as the sum of senior debt plus subordinated debt. Enerplus currently does not have any subordinated debt.
“Capitalization” is calculated as the sum of total debt and shareholder’s equity plus a $1.1 billion adjustment related to our adoption of U.S. GAAP.
Footnotes
(1) | See “Non-GAAP Measures” in this MD&A for a reconciliation of adjusted EBITDA to net income. |
(2) | Senior debt to adjusted EBITDA for the senior notes may increase to 3.5x for a period of 6 months, after which the ratio decreases to 3.0x. |
(3) | Senior debt to consolidated present value of total proved reserves is calculated annually on December 31 based on before tax reserves at forecast prices discounted at 10%.Total proved reserves at December 31, 2020 has been updated for reserves acquired through the Bruin and Dunn County Acquisitions. |
Dividends
| | | | | | | | | | | | |
| | Three months ended June 30, | | Six months ended June 30, | ||||||||
($ millions, except per share amounts) | | 2021 | | 2020 | | 2021 | | 2020 | ||||
Dividends to shareholders(1) |
| $ | 11.0 |
| $ | 6.7 |
| $ | 18.4 |
| $ | 13.3 |
Per weighted average share (Basic) | | $ | 0.04 | | $ | 0.03 | | $ | 0.07 | | $ | 0.06 |
(1) | Excludes changes in non-cash financing working capital. See Note 18(b) to the Interim Financial Statements for further details. |
During the three and six months ended June 30, 2021, we declared total dividends of $11.0 million or $0.04 per share, $18.4 million or $0.07 per share, respectively, compared to $6.7 million or $0.03 per share, or $13.3 million or $0.06 per share, respectively, for the same periods in 2020. The aggregate amount of dividends paid to shareholders has increased compared to the same period in 2020 due to an increase in common shares outstanding as a result of the bought deal equity financing completed in the first quarter of 2021 and an increase to the dividend during the second quarter of 2021.
The Board of Directors approved a 10% increase to the dividend to $0.033 per share paid quarterly beginning in June 2021, from $0.01 per share paid monthly previously. Subsequent to the quarter, the Board of Directors approved a 15% increase to the dividend to $0.038 per share, to be paid quarterly, beginning September 2021. The dividend is part of our strategy to return capital to shareholders. We continue to monitor commodity prices and economic conditions and are prepared to make adjustments as necessary.
Shareholders’ Capital
| | | | | | |
| | Six months ended June 30, | ||||
| | 2021 | | 2020 | ||
Share capital ($ millions) |
| $ | 3,236.1 | | $ | 3,097.0 |
| | | | | | |
Common shares outstanding (thousands) | |
| 256,750 | |
| 222,548 |
Weighted average shares outstanding – basic (thousands) | |
| 250,443 | |
| 222,457 |
Weighted average shares outstanding – diluted (thousands) | |
| 250,443 | |
| 222,457 |
For the six months ended June 30, 2021, a total of 2,014,193 units vested pursuant to our treasury settled LTI plans, including the impact of performance multipliers (2020 – 2,044,718). In total, 1,140,000 shares were issued from treasury and $11.9 million was transferred from paid-in capital to share capital (2020 – 1,160,000; $13.8 million). We elected to cash settle the remaining units related to the required tax withholdings (2021 – $4.5 million, 2020 – $7.2 million).
During the six months ended June 30, 2021, we issued 33,062,500 common shares at a price of $4.00 per common share for gross proceeds of $132.3 million ($127.2 million net of issue costs less tax) pursuant to a bought deal offering under our base shelf prospectus.
ENERPLUS 2021 Q2 REPORT 15
As of August 4, 2021, we had 256,750,100 common shares outstanding. In addition, an aggregate of 10,940,268 common shares may be issued to settle outstanding grants under the PSUs and Restricted Share Unit plans assuming the maximum performance multiplier of 2.0 times for the PSUs.
On June 23, 2021, we filed a short form base shelf prospectus (the “Shelf Prospectus”) with securities regulatory authorities in each of the provinces and territories of Canada and a Registration Statement with the U.S. Securities Exchange Commission. The Shelf Prospectus allows us to offer and issue up to an aggregate amount of $2.0 billion of common shares, preferred shares, warrants, subscription receipts and units by way of one or more prospectus supplements during the 25-month period that the Shelf Prospectus remains valid.
Subsequent to June 30, 2021, we received approval from the Board of Directors to commence a NCIB to purchase up to 10% of the public float (within the meaning under TSX rules) during a 12-month period. The NCIB remains subject to approval by the TSX.
For further details, see Note 16 to the Interim Financial Statements.
SELECTED CANADIAN AND U.S. FINANCIAL RESULTS
| | | | | | | | | | | | | | | | | | |
| | Three months ended June 30, 2021 | | Three months ended June 30, 2020 | ||||||||||||||
($ millions, except per unit amounts) |
| Canada |
| U.S. |
| Total |
| Canada |
| U.S. |
| Total | ||||||
Average Daily Production Volumes(1) |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
Crude oil (bbls/day) |
| | 7,006 | | | 54,797 | | | 61,803 | | | 6,066 | | | 37,102 | | | 43,168 |
Natural gas liquids (bbls/day) |
| | 447 | | | 9,443 | | | 9,890 | | | 613 | | | 4,316 | | | 4,929 |
Natural gas (Mcf/day) |
| | 7,584 | | | 254,361 | | | 261,945 | | | 12,315 | | | 223,264 | | | 235,579 |
Total average daily production (BOE/day) |
| | 8,717 | | | 106,634 | | | 115,351 | | | 8,731 | | | 78,629 | | | 87,360 |
| | | | | | | | | | | | | | | | | | |
Pricing(2) |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
Crude oil (per bbl) | | $ | 66.47 | | $ | 77.98 | | $ | 76.67 | | $ | 19.57 | | $ | 32.35 | | $ | 30.55 |
Natural gas liquids (per bbl) | |
| 40.62 | | | 21.88 | | | 22.72 | | | 15.17 | | | (3.25) | | | (0.96) |
Natural gas (per Mcf) | |
| 3.43 | | | 2.42 | | | 2.45 | | | 2.19 | | | 1.60 | | | 1.63 |
| | | | | | | | | | | | | | | | | | |
Capital Investment | |
| | |
| | |
| | |
| | |
| | |
| |
Capital and office expenditures | | $ | 4.2 | | $ | 125.7 | | $ | 129.9 | | $ | 2.9 | | $ | 37.2 | | $ | 40.1 |
Acquisitions, including property and land | |
| 0.6 | |
| 408.2 | |
| 408.8 | |
| 0.4 | |
| 3.0 | |
| 3.4 |
Property divestments | |
| — | |
| — | |
| — | |
| 0.1 | |
| — | |
| 0.1 |
| | | | | | | | | | | | | | | | | | |
Netback(3) Before Hedging | |
| | |
| | |
| | |
| | |
| | |
| |
Crude oil and natural gas sales | | $ | 46.6 | | $ | 463.6 | | $ | 510.2 | | $ | 14.7 | | $ | 140.6 | | $ | 155.3 |
Royalties | |
| (10.1) | |
| (91.5) | |
| (101.6) | |
| (1.7) | |
| (31.5) | |
| (33.2) |
Production taxes | |
| (0.7) | |
| (29.8) | |
| (30.5) | |
| 0.1 | |
| (7.8) | |
| (7.7) |
Operating expenses | |
| (13.8) | |
| (74.7) | |
| (88.5) | |
| (11.3) | |
| (43.1) | |
| (54.4) |
Transportation expenses | |
| (2.0) | |
| (34.2) | |
| (36.2) | |
| (1.7) | |
| (32.3) | |
| (34.0) |
Netback before hedging | | $ | 20.0 | | $ | 233.4 | | $ | 253.4 | | $ | 0.1 | | $ | 25.9 | | $ | 26.0 |
| | | | | | | | | | | | | | | | | | |
Other Expenses | |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
Asset impairment | | $ | — | | $ | — | | $ | — | | $ | 77.5 | | $ | 349.3 | | $ | 426.8 |
Goodwill impairment | | | — | | | — | | | — | | | — | | | 202.8 | | | 202.8 |
Commodity derivative instruments loss/(gain) | | | 198.0 | | | — | | | 198.0 | | | 10.9 | | | — | | | 10.9 |
Total G&A (including SBC) | |
| 0.1 | |
| 12.4 | |
| 12.5 | |
| (0.4) | |
| 13.9 | |
| 13.5 |
Current income tax expense/(recovery) | |
| — | |
| 4.2 | |
| 4.2 | |
| — | |
| (14.4) | |
| (14.4) |
(1) | Company interest volumes. |
(2) | Before transportation costs, royalties and the effects of commodity derivative instruments. |
(3) | See “Non-GAAP Measures” section in this MD&A. |
16 ENERPLUS 2021 Q2 REPORT
| | | | | | | | | | | | | | | | | | |
| | Six months ended June 30, 2021 | | Six months ended June 30, 2020 | ||||||||||||||
($ millions, except per unit amounts) | | Canada | | U.S. | | Total | | Canada | | U.S. | | Total | ||||||
Average Daily Production Volumes(1) |
| |
|
| |
|
| |
|
| |
| | |
| | |
|
Crude oil (bbls/day) |
| | 7,098 | | | 45,089 | | | 52,187 | | | 6,951 | | | 39,155 | | | 46,106 |
Natural gas liquids (bbls/day) |
| | 473 | | | 7,772 | | | 8,245 | | | 661 | | | 4,476 | | | 5,137 |
Natural gas (Mcf/day) |
| | 8,818 | | | 250,045 | | | 258,863 | | | 13,614 | | | 235,632 | | | 249,246 |
Total average daily production (BOE/day) |
| | 9,041 | | | 94,536 | | | 103,576 | | | 9,881 | | | 82,903 | | | 92,784 |
| | | | | | | | | | | | | | | | | | |
Pricing(2) |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
Crude oil (per bbl) | | $ | 61.38 | | $ | 74.71 | | $ | 72.90 | | $ | 30.40 | | $ | 43.57 | | $ | 41.59 |
Natural gas liquids (per bbl) | |
| 40.70 | | | 27.29 | | | 28.06 | | | 19.85 | | | 4.13 | | | 6.16 |
Natural gas (per Mcf) | |
| 3.72 | | | 2.93 | | | 2.96 | | | 2.18 | | | 1.85 | | | 1.87 |
| | | | | | | | | | | | | | | | | | |
Capital Investment | |
| | |
| | |
| | |
| | |
| | |
| |
Capital and office expenditures | | $ | 9.0 | | $ | 186.4 | | $ | 195.4 | | $ | 14.7 | | $ | 189.0 | | $ | 203.7 |
Acquisitions, including property and land | |
| 1.6 | |
| 1,035.8 | |
| 1,037.4 | |
| 1.5 | |
| 4.2 | |
| 5.7 |
Property divestments | |
| (5.0) | |
| — | |
| (5.0) | |
| 0.1 | |
| (5.6) | |
| (5.5) |
| | | | | | | | | | | | | | | | | | |
Netback(3) Before Hedging | |
| | |
| | |
| | |
| | |
| | |
| |
Crude oil and natural gas sales | | $ | 88.7 | | $ | 780.8 | | $ | 869.5 | | $ | 47.5 | | $ | 393.4 | | $ | 440.9 |
Royalties | |
| (17.7) | |
| (154.4) | |
| (172.1) | |
| (7.4) | |
| (83.3) | |
| (90.7) |
Production taxes | |
| (1.2) | |
| (46.8) | |
| (48.0) | |
| (0.2) | |
| (22.9) | |
| (23.1) |
Operating expenses | |
| (25.7) | |
| (127.3) | |
| (153.0) | |
| (28.9) | |
| (104.5) | |
| (133.4) |
Transportation expenses | |
| (4.1) | |
| (64.9) | |
| (69.0) | |
| (3.8) | |
| (65.5) | |
| (69.3) |
Netback before hedging | | $ | 40.0 | | $ | 387.4 | | $ | 427.4 | | $ | 7.2 | | $ | 117.2 | | $ | 124.4 |
| | | | | | | | | | | | | | | | | | |
Other Expenses | |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
Asset impairment | | $ | 4.3 | | $ | — | | $ | 4.3 | | $ | 77.5 | | $ | 349.3 | | $ | 426.8 |
Goodwill impairment | | | — | | | — | | | — | | | — | | | 202.8 | | | 202.8 |
Commodity derivative instruments loss/(gain) | | | 267.8 | | | — | | | 267.8 | | | (120.4) | | | — | | | (120.4) |
Total G&A (including SBC) | |
| 6.9 | |
| 21.9 | |
| 28.8 | |
| (0.6) | |
| 33.3 | |
| 32.7 |
Current income tax expense/(recovery) | |
| — | |
| 4.2 | |
| 4.2 | |
| — | |
| (14.4) | |
| (14.4) |
(1) | Company interest volumes. |
(2) | Before transportation costs, royalties and the effects of commodity derivative instruments. |
(3) | See “Non-GAAP Measures” section in this MD&A. |
QUARTERLY FINANCIAL INFORMATION
| | | | | | | | | | | | |
| | Crude Oil and Natural Gas | | | | | Net Income/(Loss) Per Share | |||||
($ millions, except per share amounts) | | Sales, Net of Royalties | | Net Income/(Loss) | | Basic | | Diluted | ||||
2021 | | | | | | | | | | | | |
Second Quarter | | $ | 408.6 | | $ | (59.7) | | $ | (0.23) | | $ | (0.23) |
First Quarter | | | 288.8 | | | 14.7 | | | 0.06 | | | 0.06 |
Total 2021 | | $ | 697.4 | | $ | (45.0) | | $ | (0.18) | | $ | (0.18) |
2020 | |
|
| |
|
| |
|
| |
|
|
Fourth Quarter | | $ | 195.1 |
| $ | (204.2) |
| $ | (0.92) |
| $ | (0.92) |
Third Quarter |
| | 191.9 | | | (112.8) | | | (0.51) | | | (0.51) |
Second Quarter | | | 122.1 | | | (609.3) | | | (2.74) | | | (2.74) |
First Quarter | |
| 228.1 | | | 2.9 | | | 0.01 | | | 0.01 |
Total 2020 | | $ | 737.2 | | $ | (923.4) | | $ | (4.15) |
| $ | (4.15) |
2019 | |
|
| |
|
| |
|
| |
|
|
Fourth Quarter | | $ | 327.0 |
| $ | (429.1) |
| $ | (1.93) |
| $ | (1.93) |
Third Quarter | |
| 318.9 | | | 65.1 | | | 0.28 | | | 0.28 |
Second Quarter | |
| 321.4 | | | 85.1 | | | 0.36 | | | 0.36 |
First Quarter | |
| 287.5 | | | 19.2 | | | 0.08 | | | 0.08 |
Total 2019 | | $ | 1,254.8 |
| $ | (259.7) |
| $ | (1.12) |
| $ | (1.12) |
Crude oil and natural gas sales, net of royalties, increased to $408.6 million during the second quarter of 2021 compared to $288.8 million during the first quarter of 2021. The increase in crude oil and natural gas sales, net of royalties, was a result of improved realized pricing and increased production during the second quarter of 2021, when compared to the first quarter of 2021. We reported a net loss of $59.7 million during the second quarter of 2021 compared to net income of $14.7 million during the first quarter of 2021. The net loss in the second quarter of 2021 was primarily due to a $198.0 million loss recorded on commodity derivative instruments, compared to a loss of $69.8 million recorded in the first quarter of 2021.
ENERPLUS 2021 Q2 REPORT 17
Crude oil and natural gas sales, net of royalties, decreased in 2020 compared to 2019 due to lower commodity prices, and decreased production due to the COVID-19 pandemic. We reported a net loss in 2020 due to a $994.8 million non-cash PP&E impairment and a $202.8 million non-cash goodwill impairment.
RECENT ACCOUNTING STANDARDS
We have not early adopted any accounting standard, interpretation or amendment that has been issued but is not yet effective. Our significant accounting policies remain unchanged from December 31, 2020, other than as described in Note 3 to the Interim Financial Statements, "Accounting Policy Changes".
U.S. Filing Status
Pursuant to U.S. securities regulations, we are required to reassess our U.S. securities filing status annually at June 30. As at June 30, 2021, we continued to qualify as a foreign private issuer for the purposes of U.S. reporting requirements.
2021 GUIDANCE
We are revising our average annual production guidance range for 2021 to 112,000 to 115,000 BOE/day including 69,500 to 71,500 bbls/day in crude oil and natural gas liquids, from 111,000 to 115,000 BOE/day including 68,500 to 71,500 bbls/day of crude oil and natural gas liquids.
We are modifying our full year Bakken and Marcellus differential guidance to US$2.35/bbl below WTI and US$0.65/Mcf below NYMEX from US$3.25/bbl below WTI and US$0.55/Mcf below NYMEX.
We are adding guidance for current income tax expense of US$5.0 million to US$7.0 million for 2021.
All other guidance targets remain unchanged.
| | |
Summary of 2021 Annual Expectations(1) |
| Target Annual Results |
Capital spending | | $360 - $400 million |
Average annual production | | 112,000 - 115,000 BOE/day (from 111,000 - 115,000 BOE/day) |
Average annual crude oil and natural gas liquids production | | 69,500 - 71,500 bbls/day (from 68,500 - 71,500 bbls/day) |
Average royalty and production tax rate (% of gross sales, before transportation) | | 26% |
Operating expenses | | $8.25/BOE |
Transportation costs | | $3.85/BOE |
Cash G&A expenses | | $1.25/BOE |
Current Income Tax expense | | US$5 - US$7 million |
| | |
Summary of 2021 Annual Expectations(1) |
| Target |
Average U.S. Bakken crude oil differential (compared to WTI crude oil)(2) | | US$(2.35)/bbl (from US$(3.25)/bbl) |
Average Marcellus natural gas sales price differential (compared to NYMEX natural gas) | | US$(0.65)/Mcf (from US$(0.55)/Mcf) |
(1) | Excluding transportation costs. |
(2) | Based on the continued operation of DAPL. |
18 ENERPLUS 2021 Q2 REPORT
NON-GAAP MEASURES
The Company utilizes the following terms for measurement within the MD&A that do not have a standardized meaning or definition as prescribed by U.S. GAAP and, therefore, may not be comparable with the calculation of similar measures by other entities:
“Netback” is used by Enerplus and is useful to investors and securities analysts in evaluating operating performance of crude oil and natural gas assets. Netback is calculated as crude oil and natural gas sales less royalties, production taxes, operating expenses and transportation expenses. The cash impact of hedging related to commodity derivative instruments is also analyzed as a part of this calculation.
| | | | | | | | | | | | |
Calculation of Netback | | Three months ended June 30, | | Six months ended June 30, | ||||||||
($ millions) | | 2021 | | 2020 | | 2021 | | 2020 | ||||
Crude oil and natural gas sales |
| $ | 510.2 |
| $ | 155.3 |
| $ | 869.5 |
| $ | 440.9 |
Less: | |
| | |
| | |
| | |
| |
Royalties | | | (101.6) | | | (33.2) | | | (172.1) | | | (90.7) |
Production taxes | |
| (30.5) | |
| (7.7) | |
| (48.0) | |
| (23.1) |
Operating expenses | |
| (88.5) | |
| (54.4) | |
| (153.0) | |
| (133.4) |
Transportation expenses | |
| (36.2) | |
| (34.0) | |
| (69.0) | |
| (69.3) |
Netback before hedging | | $ | 253.4 | | $ | 26.0 | | $ | 427.4 | | $ | 124.4 |
Cash gains/(losses) on commodity derivative instruments | |
| (37.2) | |
| 53.5 | |
| (56.6) | |
| 86.5 |
Netback after hedging | | $ | 216.2 | | $ | 79.5 | | $ | 370.8 | | $ | 210.9 |
“Adjusted funds flow” is used by Enerplus and is useful to investors and securities analysts in analyzing operating and financial performance, leverage and liquidity. Adjusted funds flow is calculated as cash flow from/(used in) operating activities before asset retirement obligation expenditures and changes in non-cash operating working capital.
| | | | | | | | | | | | |
Reconciliation of Cash Flow from Operating Activities to Adjusted Funds Flow | | Three months ended June 30, | | Six months ended June 30, | ||||||||
($ millions) | | 2021 | | 2020 | | 2021 | | 2020 | ||||
Cash flow from/(used in) operating activities |
| $ | 136.9 |
| $ | 90.6 | | $ | 174.1 |
| $ | 213.3 |
Asset retirement obligation expenditures | |
| 1.3 | |
| 0.3 | |
| 8.4 | |
| 11.1 |
Changes in non-cash operating working capital | |
| 46.1 | |
| (20.9) | |
| 129.9 | |
| (41.2) |
Adjusted funds flow | | $ | 184.3 | | $ | 70.0 | | $ | 312.4 | | $ | 183.2 |
“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 as outlined in the Capital Investment section of this MD&A.
| | | | | | | | | | | |
Calculation of Free Cash Flow | Three months ended June 30, | | Six months ended June 30, | ||||||||
($ millions) | 2021 |
| 2020 |
| 2021 |
| 2020 | ||||
Adjusted funds flow | $ | 184.3 | | $ | 70.0 | | $ | 312.4 | | $ | 183.2 |
Capital spending | | (129.9) | | | (40.1) | | | (195.4) | | | (203.7) |
Free cash flow | $ | 54.4 | | $ | 29.9 | | $ | 117.0 | | $ | (20.5) |
“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 understanding the impact of certain non-cash items and other items that the Company considers appropriate to adjust given the irregular nature and relevance to comparable companies. Adjusted net income/(loss) is calculated as net income/(loss) adjusted for unrealized derivative instrument gain/loss, asset impairment, goodwill impairment, unrealized foreign exchange gain/loss, the associated tax effect of these items, and the valuation allowance on our deferred income tax assets.
ENERPLUS 2021 Q2 REPORT 19
| | | | | | | | | | | | |
Calculation of Adjusted Net Income | | Three months ended June 30, | | Six months ended June 30, | ||||||||
($ millions) | | 2021 | | 2020 | | 2021 | | 2020 | ||||
Net income/(loss) |
| $ | (59.7) | | $ | (609.3) | | $ | (45.0) |
| $ | (606.4) |
Unrealized derivative instrument (gain)/loss | | | 160.1 | | | 63.9 | | | 210.0 | | | (32.5) |
Asset impairment | | | — | | | 426.8 | | | 4.3 | | | 426.8 |
Unrealized foreign exchange (gain)/loss | | | 5.5 | | | 1.0 | | | 5.9 | | | (1.4) |
Tax effect on above items | | | (38.0) | | | (126.4) | | | (51.0) | | | (103.0) |
Goodwill impairment | | | — | | | 202.8 | | | — | | | 202.8 |
Valuation allowance on deferred taxes | | | — | | | — | | | — | | | 93.6 |
Adjusted net income/(loss) |
| $ | 67.9 | | $ | (41.2) | | $ | 124.2 |
| $ | (20.1) |
“Total debt net of cash” is used by Enerplus and is useful to investors and securities analysts in analyzing leverage and liquidity. Total debt net of cash is calculated as senior notes plus term loan plus any outstanding Bank Credit Facility balance, minus cash and cash equivalents.
“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 total debt net of cash divided by trailing twelve months of adjusted funds flow. This measure is not equivalent to debt to earnings before interest, taxes, depreciation, amortization, accretion, impairment and other non-cash charges (“adjusted EBITDA”) and is not a debt covenant.
“Adjusted payout ratio” is used by Enerplus and is useful to investors and securities analysts in analyzing operating performance, leverage and liquidity. We calculate adjusted payout ratio as cash dividends plus capital and office expenditures, divided by adjusted funds flow.
| | | | | | | | | | | | |
Calculation of Adjusted Payout Ratio | | Three months ended June 30, | | Six months ended June 30, | ||||||||
($ millions) | | 2021 | | 2020 | | 2021 | | 2020 | ||||
Dividends | | $ | 11.0 |
| $ | 6.7 | | $ | 18.4 | | $ | 13.3 |
Capital and office expenditures | |
| 130.4 | |
| 41.0 | |
| 196.3 | |
| 206.5 |
Sub-total | | $ | 141.4 | | $ | 47.7 | | $ | 214.7 | | $ | 219.8 |
Adjusted funds flow | | $ | 184.3 | | $ | 70.0 | | $ | 312.4 | | $ | 183.2 |
Adjusted payout ratio (%) | | | 77% | | | 68% | | | 69% | | | 120% |
“Adjusted EBITDA” is used by Enerplus and its lenders to determine compliance with financial covenants under the Bank Credit Facility, term loan, and outstanding senior notes. Adjusted EBITDA is calculated on the trailing four quarters.
| | | |
Reconciliation of Net Income to Adjusted EBITDA(1) |
| | |
($ millions) | | June 30, 2021 | |
Net income/(loss) | | $ | (361.9) |
Add: | |
| |
Interest expense | |
| 28.8 |
Current and deferred tax expense/(recovery) | |
| (252.7) |
DD&A and asset impairment | |
| 830.8 |
Other non-cash charges(2) | |
| 275.3 |
Sub-total | | $ | 520.3 |
Adjustment for material acquisitions and divestments(3) | |
| 101.0 |
Adjusted EBITDA | | $ | 621.3 |
(1) | Balances above at June 30, 2021 include the six months ended June 30, 2021 and the third and fourth quarter of 2020. |
(2) | Includes the change in fair value of commodity derivatives and equity swaps, non-cash SBC expense, non-cash G&A expense, non-cash amortization of debt issuance costs and unrealized foreign exchange gains/losses. |
(3) | EBITDA is adjusted for material acquisitions or divestments during the period with net proceeds greater than US$37.5 million as if that acquisition or disposition has been made at the beginning of the period. |
In addition, the Company uses certain financial measures within the “Liquidity and Capital Resources” section of this MD&A that do not have a standardized meaning or definition as prescribed by U.S. GAAP and, therefore, may not be comparable with the calculation of similar measures by other entities. Such measures include “senior debt to adjusted EBITDA”, “total debt to adjusted EBITDA”, “total debt to capitalization”, “senior debt to consolidated present value of total proved reserves” and “adjusted EBITDA to interest” and are used to determine the Company’s compliance with financial covenants under the Bank Credit Facility, term loan and outstanding senior notes. Calculation of such terms is described under the “Liquidity and Capital Resources” section of this MD&A.
20 ENERPLUS 2021 Q2 REPORT
INTERNAL CONTROLS AND PROCEDURES
Our Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of our disclosure controls and procedures and internal control over financial reporting as defined in Rule 13a - 15 under the U.S. Securities Exchange Act of 1934 and as defined in Canada under National Instrument 52-109 - Certification of Disclosure in Issuer’s Annual and Interim Filings. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of Enerplus Corporation have concluded that, as at June 30, 2021, our disclosure controls and procedures and internal control over financial reporting were effective. There were no changes in our internal control over financial reporting during the period beginning on April 1, 2021 and ended June 30, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ADDITIONAL INFORMATION
Additional information relating to Enerplus, including our Annual Information Form, is available under our profile on the SEDAR website at www.sedar.com, on the EDGAR website at www.sec.gov and at www.enerplus.com.
FORWARD-LOOKING INFORMATION AND STATEMENTS
This MD&A 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 MD&A contains forward-looking information pertaining to the following: expected benefits of the Dunn County Acquisition and the Bruin Acquisition; expected impact of the Dunn County Acquisition and Bruin Acquisition on Enerplus' operations and financial results; anticipated impact of the Dunn County Acquisition and the Bruin Acquisition on Enerplus' future costs and expenses; the renewal of Enerplus’ NCIB and terms thereof; expected capital spending levels 2021 and impact thereof on our production levels and land holdings; expected production volumes and updated 2021 production guidance; expected operating strategy in 2021, including the effect of Enerplus’ production curtailment on its properties, operations and financial position; the effect of Enerplus’ participation in the DAPL expansion on increased crude oil transportation; 2021 average production volumes, timing thereof and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged and the expected effectiveness of such hedges in protecting our adjusted funds flow; the results from our drilling program and the timing of related production and ultimate well recoveries; oil and natural gas prices and differentials, our commodity risk management program in 2021 and expected hedging gains; expectations regarding our realized oil and natural gas prices; expected operating, transportation, cash G&A costs and share-based compensation and financing expenses; potential future non-cash PP&E impairments, as well as relevant factors that may affect such impairment; the amount of our future abandonment and reclamation costs and asset retirement obligations; future environmental expenses; our future royalty and production and U.S. cash taxes; deferred income taxes, our tax pools and the time at which we may pay Canadian cash taxes; 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; expectations regarding payment of increased dividends; expectations regarding our ability to comply with debt covenants under our Bank Credit Facility, term loan and outstanding senior notes; expectations regarding payment of increased dividends; Enerplus' costs reduction initiatives and the expected cost savings therefrom in 2021; the amount of future cash dividends that we may pay to our shareholders; and our ESG initiatives, including GHG emissions and water reduction targets for 2021.
The forward-looking information contained in this MD&A reflects several material factors and expectations and assumptions of Enerplus including, without limitation: the benefits of the Dunn County Acquisition and the Bruin Acquisition; that Enerplus will realize the expected impact of the Dunn County Acquisition and the Bruin Acquisition on Enerplus' operations and financial results and on Enerplus' future costs and expenses will be as expected and as discussed in this MD&A; that we will conduct our operations and achieve results of operations as anticipated; the continued ability to operate DAPL; that our development plans will achieve the expected results; that lack of adequate infrastructure and/or low commodity price environment will not result in curtailment of production and/or reduced realized prices beyond our current expectations; current commodity price, differentials and cost assumptions; the general continuance of current or, where applicable, assumed industry conditions, including expectations regarding the duration and overall impact of COVID-19; 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; the continued availability and sufficiency of our adjusted funds flow and availability under our Bank Credit Facility to fund our working capital deficiency; our ability to comply with our debt covenants; the availability of third party services; the extent of our liabilities; the rates used to calculate the amount of our future abandonment and reclamation costs and asset retirement obligations; and the availability of technology and process to achieve environmental targets. In addition, our expected 2021 capital expenditures, operating strategy and 2021 guidance described in this MD&A is based on the rest of the year prices and exchange rate of: a WTI price of US$69.00/bbl, a NYMEX price of US$3.92/Mcf and a USD/CDN exchange rate of 1.26. 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.
ENERPLUS 2021 Q2 REPORT 21
The forward-looking information included in this MD&A is not a guarantee of future performance and should not be unduly relied upon. Such information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information including, without limitation: failure by Enerplus to realize anticipated benefits of the Dunn County Acquisition or the Bruin Acquisition; continued instability, or further deterioration, in global economic and market environment, including from COVID-19; continued low commodity price environment or further decline and/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; unanticipated operating results, results from our capital spending activities or production declines; legal proceedings in connection with DAPL; 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 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; 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 this MD&A, our Annual Information Form, our Annual MD&A and Form 40-F as at December 31, 2020).
The forward-looking information contained in this MD&A speaks only as of the date of this MD&A. Enerplus does not undertake any obligation to publicly update or revise any forward-looking information contained herein, except as required by applicable laws.
22 ENERPLUS 2021 Q2 REPORT