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Share Name | Share Symbol | Market | Type |
---|---|---|---|
Enerplus Corporation | NYSE:ERF | NYSE | Common Stock |
Price Change | % Change | Share Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|
0.00 | 0.00% | 20.09 | 0 | 01:00:00 |
FORM 6‑K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Report of Foreign Issuer pursuant to Rule 13‑a‑16 or 15d‑16
of the Securities Exchange Act of 1934
FOR THE MONTH OF MAY, 2018
COMMISSION FILE NUMBER 1‑15150
The Dome Tower
Suite 3000, 333 – 7th Avenue S.W.
Calgary, Alberta
Canada T2P 2Z1
(403) 298‑2200
Indicate by check mark whether the registrant files or will file annual reports under cover Form 20‑F or Form 40‑F.
Form 20‑F ☐ Form 40‑F ☒
Indicate by check mark if the registrant is submitting the Form 6‑K in paper as permitted by Regulation S‑T Rule 101(b)(1)
Yes ☐ No ☒
Indicate by check mark if the registrant is submitting the Form 6‑K in paper as permitted by Regulation S‑T Rule 101(b)(7)
Yes ☐ No ☒
Indicate by check mark whether, by furnishing the information contained in this Form, the registrant is also thereby furnishing the information to the Commission pursuant to Rule 12g3‑2(b) under the securities Exchange Act of 1934.
Yes ☐ No ☒
EXHIBIT INDEX
EXHIBIT 99.1 — Management’s Discussion and Analysis for the First Quarter ended March 31, 2018
EXHIBIT 99.2 — Unaudited Consolidated Financial Statements for the First Quarter ended March 31, 2018
EXHIBIT 99.3 — Certification of the Chief Executive Officer
EXHIBIT 99.4 — Certification of the Chief Financial Officer
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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ENERPLUS CORPORATION |
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BY: |
/s/ David A. McCoy |
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David A. McCoy |
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Vice President, General Counsel & Corporate Secretary |
DATE: May 3, 2018
MD&A
Exhibit 99.1
MANAGEMENT’S DISCUSSION AND ANALYSIS (“MD&A”)
The following discussion and analysis of financial results is dated May 2, 2018 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 months ended March 31, 2018 and 2017 (the “Interim Financial Statements”); |
· |
the audited consolidated financial statements of Enerplus as at December 31, 2017 and 2016 and for the years ended December 31, 2017, 2016 and 2015; and |
· |
our MD&A for the year ended December 31, 2017 (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.
BASIS OF PRESENTATION
The Interim Financial Statements and Notes 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 restated 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 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, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. Use of BOE and Mcfe in isolation may be misleading. All production volumes are 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 unless otherwise stated. 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.
In accordance with U.S. GAAP, oil and gas sales are presented net of royalties in our Interim Financial Statements. Under International Financial Reporting Standards, industry standard is to present oil and gas sales before deduction of royalties and as such this MD&A presents production, oil and gas sales, and BOE measures on this basis to remain comparable with our Canadian peers.
Effective in 2018, Enerplus adopted ASC 606 - Revenue from contracts with customers. The adoption of this standard had no impact on the Interim Financial Statements, with the exception of additional note disclosures. See Notes 3(a) and 10 to the Interim Financial Statements for further details.
Average daily production for the quarter was 85,080 BOE/day, a decrease of 4% from 88,590 BOE/day in the fourth quarter of 2017. Production decreased in North Dakota as a result of downtime related to completions activities on adjacent properties, along with the expected decrease in volumes with wells coming on-stream toward the end of the quarter. The decrease in crude oil volumes was offset slightly by higher natural gas production in the Marcellus due to improved regional prices. We are well positioned to meet our annual average production guidance ranges of 86,000 – 91,000 BOE/day and our crude oil and natural gas liquids guidance of 46,000 – 50,000 bbls/day, with second quarter crude oil and natural gas liquids production of 48,000 – 50,000 bbls/day.
Capital expenditures of $151.5 million in the first quarter were in line with our expectations. The majority of our capital spending was directed to our crude oil properties, primarily in North Dakota. We are maintaining our 2018 annual capital spending guidance of between $535 and $585 million.
ENERPLUS 2018 Q1 REPORT 7
Operating costs for the quarter increased to $53.8 million or $7.02/BOE from $52.1 million or $6.39/BOE in the fourth quarter of 2017. Cash G&A expenses for the first quarter were $13.2 million or $1.72/BOE compared to $12.6 million or $1.55/BOE in the fourth quarter of 2017. The increase in operating costs and cash G&A expenses on a per BOE basis was primarily due to lower production volumes. We are maintaining our annual guidance targets of $7.00/BOE for operating costs and $1.65/BOE for cash G&A expenses.
We continued to add to our commodity hedge positions during the quarter. As of May 2, 2018, we had approximately 67% of our forecasted crude oil production, net of royalties, hedged for the remainder of 2018, and approximately 66% and 19% of our crude oil production, net of royalties, hedged in 2019 and 2020, respectively, based on 2018 forecasted production. We have also hedged approximately 21% of our forecasted natural gas production, net of royalties, for the remainder of 2018.
We recorded net income of $29.6 million and adjusted funds flow of $155.2 million in the first quarter of 2018, compared to $15.3 million and $199.6 million, respectively, in the fourth quarter of 2017. Net income in the fourth quarter was impacted by the re-measurement of our U.S. deferred tax assets as a result of the reduction in the U.S. federal income tax rate in 2017. Both fourth quarter net income and adjusted funds flow benefited from a $50.1 million U.S. Alternative Minimum Tax (“AMT”) credit carryover, which we expect to realize in 2018.
At March 31, 2018, our total debt net of cash was $292.0 million and our net debt to adjusted funds flow ratio was 0.5x.
RESULTS OF OPERATIONS
Average daily production for the first quarter totaled 85,080 BOE/day, compared to production of 88,590 BOE/day in the fourth quarter of 2017. Crude oil and liquids production decreased by 5,294 bbls/day, primarily due to lower North Dakota volumes, where we experienced downtime due to completions activities on adjacent properties, along with the expected timing of wells coming on-stream later in the quarter. As a result of improved realized prices, we did not have any production curtailments in the Marcellus during the quarter, which contributed to a 4% increase in natural gas production compared to the fourth quarter of 2017.
Production in the first quarter was consistent with production of 84,937 BOE/day for the same period of the prior year. Our increased capital program in North Dakota resulted in an increase of approximately 9,000 BOE/day of liquids production along with slightly higher Marcellus natural gas production. These increases were offset by the divestment of non-core Canadian properties throughout 2017 and the first quarter of 2018 with associated production of approximately 8,300 BOE/day.
Our crude oil and natural gas liquids weighting increased to 49% in the first quarter of 2018, from 43% for the same period of 2017, due to increased capital spending on our North Dakota crude oil asset and the divestment of non-core natural gas weighted properties.
Average daily production volumes for the three months ended March 31, 2018 and 2017 are outlined below:
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Three months ended March 31, |
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Average Daily Production Volumes |
|
2018 |
|
2017 |
|
% Change |
Crude oil (bbls/day) |
|
37,443 |
|
33,178 |
|
13% |
Natural gas liquids (bbls/day) |
|
4,085 |
|
3,158 |
|
29% |
Natural gas (Mcf/day) |
|
261,310 |
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291,607 |
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(10%) |
Total daily sales (BOE/day) |
|
85,080 |
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84,937 |
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0% |
We are well positioned to meet our annual average production guidance ranges of 86,000 – 91,000 BOE/day and our crude oil and natural gas liquids guidance of 46,000 – 50,000 bbls/day, with second quarter crude oil and natural gas liquids production of 48,000 – 50,000 bbls/day.
8 ENERPLUS 2018 Q1 REPORT
Pricing
The prices received for our crude oil and natural gas production directly impact our earnings, adjusted funds flow and financial condition. The following table compares average prices for the three months ended March 31, 2018 and 2017 and quarterly average prices for the periods indicated:
Pricing (average for the period) |
Q1 2018 |
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Q4 2017 |
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Q3 2017 |
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Q2 2017 |
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Q1 2017 |
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Benchmarks |
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WTI crude oil (US$/bbl) |
$ |
62.87 |
|
$ |
55.40 |
|
$ |
48.20 |
|
$ |
48.29 |
|
$ |
51.92 |
AECO natural gas – monthly index ($/Mcf) |
|
1.85 |
|
|
1.96 |
|
|
2.04 |
|
|
2.77 |
|
|
2.94 |
AECO natural gas – daily index ($/Mcf) |
|
2.08 |
|
|
1.69 |
|
|
1.45 |
|
|
2.78 |
|
|
2.69 |
NYMEX natural gas – last day (US$/Mcf) |
|
3.00 |
|
|
2.93 |
|
|
3.00 |
|
|
3.18 |
|
|
3.32 |
USD/CDN average exchange rate |
|
1.26 |
|
|
1.27 |
|
|
1.25 |
|
|
1.34 |
|
|
1.32 |
USD/CDN period end exchange rate |
|
1.29 |
|
|
1.26 |
|
|
1.25 |
|
|
1.30 |
|
|
1.33 |
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Enerplus selling price(1) |
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Crude oil ($/bbl) |
$ |
69.67 |
|
$ |
65.91 |
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$ |
54.21 |
|
$ |
55.66 |
|
$ |
57.53 |
Natural gas liquids ($/bbl) |
|
28.13 |
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32.26 |
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26.22 |
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|
25.14 |
|
|
37.76 |
Natural gas ($/Mcf) |
|
3.50 |
|
|
3.03 |
|
|
2.58 |
|
|
3.48 |
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|
3.63 |
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Average differentials |
|
|
|
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|
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MSW Edmonton – WTI (US$/bbl) |
$ |
(5.89) |
|
$ |
(1.14) |
|
$ |
(2.89) |
|
$ |
(2.26) |
|
$ |
(3.54) |
WCS Hardisty – WTI (US$/bbl) |
|
(24.28) |
|
|
(12.27) |
|
|
(9.94) |
|
|
(11.13) |
|
|
(14.58) |
Transco Leidy monthly – NYMEX (US$/Mcf) |
|
(0.67) |
|
|
(1.32) |
|
|
(1.29) |
|
|
(0.60) |
|
|
(0.63) |
TGP Z4 300L monthly – NYMEX (US$/Mcf) |
|
(0.76) |
|
|
(1.40) |
|
|
(1.36) |
|
|
(0.66) |
|
|
(0.70) |
AECO monthly – NYMEX (US$/Mcf) |
|
(1.44) |
|
|
(1.40) |
|
|
(1.39) |
|
|
(1.13) |
|
|
(1.10) |
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|
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Enerplus realized differentials(1)(2) |
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|
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Canada crude oil – WTI (US$/bbl) |
$ |
(20.82) |
|
$ |
(10.47) |
|
$ |
(9.29) |
|
$ |
(11.02) |
|
$ |
(12.76) |
Canada natural gas – NYMEX (US$/Mcf) |
|
(0.52) |
|
|
(0.56) |
|
|
(1.00) |
|
|
(0.51) |
|
|
(0.56) |
Bakken crude oil – WTI (US$/bbl) |
|
(3.27) |
|
|
(1.61) |
|
|
(3.24) |
|
|
(5.43) |
|
|
(5.59) |
Marcellus natural gas – NYMEX (US$/Mcf) |
|
(0.21) |
|
|
(0.81) |
|
|
(1.02) |
|
|
(0.64) |
|
|
(0.60) |
(1)Excluding transportation costs, royalties and commodity derivative instruments.
(2)Based on a weighted average differential for the period.
CRUDE OIL AND NATURAL GAS LIQUIDS
Our average realized crude oil price increased by 6% from the fourth quarter of 2017 to average $69.67/bbl. In comparison, benchmark WTI crude oil prices increased by 13% due to lower global crude oil inventories and uncertainty as to when the Organization of the Petroleum Exporting Countries (“OPEC”) production agreement will end. This price strength was partially offset by weaker crude oil differentials in both the U.S. and Canada as Canadian crude was restricted due to pipeline egress limitations.
Our realized Bakken price differential to WTI increased by US$1.66/bbl from the fourth quarter of 2017 to average US$3.27/bbl below WTI as stronger WTI prices continue to drive growth in North American crude oil supply. Although this resulted in an increase in differentials for light sweet crude oil in both Canada and the U.S. during the quarter, the overall price received for our Bakken production increased by 11% due to the strength in WTI benchmark prices. As a result of the significant improvement in WTI prices, we are revising our expected 2018 average U.S. Bakken crude oil differential to US$3.50/bbl below WTI based on a WTI price of US$65.00/bbl.
Our realized price differential for our Canadian crude oil production increased by US$10.35/bbl compared to the previous quarter. Canadian crude oil prices deteriorated in the quarter due to pipeline apportionments and continued pipeline flow restrictions following the late 2017 service disruption on the Keystone pipeline. Our realized price for natural gas liquids averaged $28.13/bbl during the period, a decrease of 13% compared to the previous quarter primarily due to weakness in benchmark prices, particularly in propane markets.
NATURAL GAS
Our average realized natural gas price during the first quarter increased by 16% compared to the fourth quarter of 2017 to average $3.50/Mcf, due to a significant improvement in realized prices for our Marcellus production. Comparatively, benchmark NYMEX natural gas prices increased by 2% during the quarter.
ENERPLUS 2018 Q1 REPORT 9
Our realized Marcellus sales price differential, excluding transportation and gathering costs, improved considerably from the fourth quarter of 2017 to average US$0.21/Mcf below NYMEX. This outperformed the Benchmark monthly Transco Leidy price which averaged US$0.67/Mcf below NYMEX during the quarter. Our Marcellus portfolio benefitted from the impacts of a colder than normal winter, particularly in early January of 2018, when record cold weather resulted in price spikes in key consumption regions in the U.S. We expect our Marcellus differential to increase during the remainder of 2018 as a portion of our sales portfolio is tied to New York markets that are typically weaker during the summer months. We continue to expect our Marcellus differentials to average US$0.40/Mcf below NYMEX for 2018.
Although benchmark AECO gas prices remained weak due to delivery limitations on export pipelines out of the basin, our realized Canadian natural gas price differential averaged US$0.52/Mcf below NYMEX. We continue to benefit from our multi-year term AECO physical sales contracts, which have an average fixed basis differential of US$0.63/Mcf below NYMEX.
FOREIGN EXCHANGE
The USD/CDN exchange rate was 1.29 USD/CDN at March 31, 2018, and averaged 1.26 USD/CDN during the first quarter of 2018, compared to an exchange rate of 1.26 USD/CDN at December 31, 2017 and an average exchange rate of 1.27 USD/CDN during the fourth quarter of 2017. The majority of our oil and natural gas sales are based on U.S. dollar denominated indices, and a stronger Canadian dollar relative to the U.S. dollar decreases the amount of our realized sales. Because we report in Canadian dollars, the stronger Canadian dollar also decreases our U.S. dollar denominated costs, capital spending and the interest cost on our U.S. dollar denominated debt.
Price Risk Management
We have a price risk management program that considers our overall financial position and the economics of our capital expenditures.
As of May 2, 2018, we have hedged approximately 21,500 bbls/day of our expected crude oil production for the remainder of 2018, which represents approximately 67% of our forecasted crude oil production, after royalties. For 2019 and 2020, we are hedged on approximately 21,300 bbls/day or 66% and 6,000 bbls/day or 19%, respectively, of our 2018 forecasted crude oil production, after royalties. Our crude oil hedges are predominantly three way collars, which consist of a sold put, a purchased put and a sold call. When WTI prices settle below the sold put strike price, the three way collars provide a limited amount of protection above the WTI settled price equal to the difference between the strike price of the purchased and sold puts. Overall, we expect our crude oil related hedging contracts to protect a significant portion of our funds flow.
As of May 2, 2018, we have hedged approximately 37,800 Mcf/day of our forecasted natural gas production for the remainder of 2018. This represents approximately 21% of our forecasted natural gas production, after royalties.
The following is a summary of our financial contracts in place at May 2, 2018, expressed as a percentage of our forecasted 2018 net production volumes:
|
WTI Crude Oil (US$/bbl)(1) |
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|
Apr 1, 2018 – |
May 1, 2018 – |
Jul 1, 2018 – |
Oct 1, 2018 – |
Jan 1, 2019 – |
Apr 1, 2019 – |
Jan 1, 2020 – |
|
Apr 30, 2018 |
Jun 30, 2018 |
Sep 30, 2018 |
Dec 31, 2018 |
Mar 31, 2019 |
Dec 31, 2019 |
Dec 31, 2020 |
Swaps |
|
|
|
|
|
|
|
Sold Swaps |
$ 55.38 |
$ 57.20 |
$ 53.73 |
$ 53.73 |
$ 53.73 |
— |
— |
% |
16% | 19% | 9% | 9% | 9% |
— |
— |
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Three Way Collars |
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Sold Puts |
$ 42.92 |
$ 42.92 |
$ 42.71 |
$ 42.74 |
$ 44.05 |
$ 44.26 |
$ 46.67 |
% |
47% | 47% | 56% | 62% | 50% | 68% | 19% |
Purchased Puts |
$ 52.90 |
$ 52.90 |
$ 52.53 |
$ 52.48 |
$ 53.69 |
$ 54.17 |
$ 56.00 |
% |
47% | 47% | 56% | 62% | 50% | 68% | 19% |
Sold Calls |
$ 61.73 |
$ 61.73 |
$ 61.22 |
$ 61.10 |
$ 63.44 |
$ 64.83 |
$ 70.33 |
% |
47% | 47% | 56% | 62% | 50% | 68% | 19% |
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(1) |
Based on weighted average price (before premiums) assuming average annual production of 88,500 BOE/day, which is the mid-point of our annual 2018 guidance, less royalties and production taxes of 25%. A portion of the sold puts are settled annually rather than monthly. |
10 ENERPLUS 2018 Q1 REPORT
|
NYMEX Natural Gas (US$/Mcf)(1) |
|
|
Apr 1, 2018 – |
Nov 1, 2018 – |
|
Oct 31, 2018 |
Dec 31, 2018 |
Collars |
|
|
Purchased Puts |
$ 2.75 |
$ 2.75 |
% |
22% | 16% |
Sold Calls |
$ 3.38 |
$ 3.47 |
% |
22% | 16% |
(1) |
Based on weighted average price (before premiums) assuming average annual production of 88,500 BOE/day, which is the mid-point of our annual 2018 guidance, less royalties and production taxes of 25%. A portion of the sold puts are settled annually rather than monthly. |
ACCOUNTING FOR PRICE RISK MANAGEMENT
Commodity Risk Management Gains/(Losses) |
|
Three months ended March 31, |
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($ millions) |
|
2018 |
|
2017 | ||
Cash gains/(losses): |
|
|
|
|
|
|
Crude oil |
|
$ |
(6.4) |
|
$ |
(1.0) |
Natural gas |
|
|
16.5 |
|
|
7.6 |
Total cash gains/(losses) |
|
$ |
10.1 |
|
$ |
6.6 |
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|
|
|
|
|
|
Non-cash gains/(losses): |
|
|
|
|
|
|
Crude oil |
|
$ |
(29.9) |
|
$ |
44.4 |
Natural gas |
|
|
(0.7) |
|
|
6.6 |
Total non-cash gains/(losses) |
|
$ |
(30.6) |
|
$ |
51.0 |
Total gains/(losses) |
|
$ |
(20.5) |
|
$ |
57.6 |
|
|
Three months ended March 31, |
||||
(Per BOE) |
|
2018 |
|
2017 | ||
Total cash gains/(losses) |
|
$ |
1.33 |
|
$ |
0.86 |
Total non-cash gains/(losses) |
|
|
(3.99) |
|
|
6.67 |
Total gains/(losses) |
|
$ |
(2.66) |
|
$ |
7.53 |
During the first quarter of 2018, we realized cash losses of $6.4 million on our crude oil contracts and cash gains of $16.5 million on our natural gas contracts. In comparison, during the first quarter of 2017, we realized cash losses of $1.0 million on our crude oil contracts and cash gains of $7.6 million on our natural gas contracts. Cash losses on crude oil contracts were primarily due to crude oil prices rising above the sold call strike price on our three way collar hedge positions. Cash gains recorded in the quarter on our natural gas contracts included a gain of $15.1 million on the unwind of a portion of our AECO-NYMEX basis physical contracts.
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 the end of the first quarter of 2018, the fair value of our crude oil contracts was in a net liability position of $64.1 million, while the fair value of our natural gas contracts was in a net asset position of $1.0 million. For the three months ended March 31, 2018, the change in the fair value of our crude oil contracts and natural gas contracts represented losses of $29.9 million and $0.7 million, respectively.
Revenues
|
|
Three months ended March 31, |
||||
($ millions) |
|
2018 |
|
2017 | ||
Oil and natural gas sales |
|
$ |
328.5 |
|
$ |
277.7 |
Royalties |
|
|
(63.5) |
|
|
(49.9) |
Oil and natural gas sales, net of royalties |
|
$ |
265.0 |
|
$ |
227.8 |
Oil and natural gas sales, net of royalties for the three months ended March 31, 2018, were $265.0 million an increase of 16% from the same period in 2017. The increase in revenue was a result of the improvement in crude oil prices compared to the prior year, along with a higher crude oil and natural gas liquids weighting of 49% compared to 43%.
ENERPLUS 2018 Q1 REPORT 11
Royalties and Production Taxes
|
|
Three months ended March 31, |
||||
($ millions, except per BOE amounts) |
|
2018 |
|
2017 | ||
Royalties |
|
$ |
63.5 |
|
$ |
49.9 |
Per BOE |
|
$ |
8.30 |
|
$ |
6.53 |
|
|
|
|
|
|
|
Production taxes |
|
$ |
16.1 |
|
$ |
10.4 |
Per BOE |
|
$ |
2.11 |
|
$ |
1.36 |
Royalties and production taxes |
|
$ |
79.6 |
|
$ |
60.3 |
Per BOE |
|
$ |
10.41 |
|
$ |
7.89 |
|
|
|
|
|
|
|
Royalties and production taxes (% of oil and natural gas sales) |
|
|
24% |
|
|
22% |
Royalties are paid to government entities, land owners and mineral rights owners. Production taxes include state production taxes, Pennsylvania impact fees, freehold mineral taxes and Saskatchewan resource surcharges. A large percentage of our production is from U.S. properties where royalty rates are generally less sensitive to commodity price levels. During the three months ended March 31, 2018, royalties and production taxes increased to $79.6 million from $60.3 million for the same period in 2017 primarily due to higher crude oil prices and a greater weighting of our production coming from our U.S. properties, which have a combined royalty and production tax rate of approximately 26%. Royalties and production taxes averaged 24% of crude oil and natural gas sales before transportation in the first three months of 2018 compared to 22% for the same period in 2017.
We are maintaining our annual average royalty and production tax rate guidance of 25% for 2018.
|
|
Three months ended March 31, |
||||
($ millions, except per BOE amounts) |
|
2018 |
|
2017 | ||
Cash operating expenses |
|
$ |
53.8 |
|
$ |
50.3 |
Non-cash (gains)/losses(1) |
|
|
— |
|
|
0.1 |
Total operating expenses |
|
$ |
53.8 |
|
$ |
50.4 |
Per BOE |
|
$ |
7.02 |
|
$ |
6.59 |
(1)Non-cash (gains)/losses on fixed price electricity swaps.
For the three months ended March 31, 2018, operating expenses were $53.8 million or $7.02/BOE compared to our annual guidance of $7.00/BOE. Operating costs increased by $3.4 million compared to the same period in 2017 mainly due to a greater proportion of our production coming from crude oil and natural gas liquids offset by the divestment of higher operating cost Canadian properties throughout 2017 and the first quarter of 2018.
We are maintaining our annual operating cost guidance of $7.00/BOE.
Transportation Costs
|
|
Three months ended March 31, |
||||
($ millions, except per BOE amounts) |
|
2018 |
|
2017 | ||
Transportation costs |
|
$ |
26.9 |
|
$ |
29.6 |
Per BOE |
|
$ |
3.52 |
|
$ |
3.88 |
For the three months ended March 31, 2018, transportation costs were $26.9 million or $3.52/BOE compared to our annual guidance of $3.60/BOE. During the same period in 2017 transportation costs were $29.6 million or $3.88/BOE. The decrease is primarily due to the divestment of non-core Canadian natural gas properties in 2017 and a stronger Canadian dollar during the first quarter of 2018, which lowered the cost of our U.S. transportation expenses.
We are maintaining our annual guidance for transportation costs of $3.60/BOE.
12 ENERPLUS 2018 Q1 REPORT
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 March 31, 2018 |
|||||||
Netbacks by Property Type |
|
Crude Oil |
|
Natural Gas |
|
Total |
|||
Average Daily Production |
|
44,050 BOE/day |
|
246,180 Mcfe/day |
|
85,080 BOE/day |
|||
Netback(1) $ per BOE or Mcfe |
|
(per BOE) |
|
(per Mcfe) |
|
(per BOE) |
|||
Oil and natural gas sales |
|
$ |
62.99 |
|
$ |
3.56 |
|
$ |
42.91 |
Royalties and production taxes |
|
|
(16.47) |
|
|
(0.65) |
|
|
(10.41) |
Cash operating expenses |
|
|
(10.79) |
|
|
(0.50) |
|
|
(7.02) |
Transportation costs |
|
|
(2.07) |
|
|
(0.84) |
|
|
(3.52) |
Netback before hedging |
|
$ |
33.66 |
|
$ |
1.57 |
|
$ |
21.96 |
Cash gains/(losses) |
|
|
(1.61) |
|
|
0.75 |
|
|
1.33 |
Netback after hedging |
|
$ |
32.05 |
|
$ |
2.32 |
|
$ |
23.29 |
Netback before hedging ($ millions) |
|
$ |
133.4 |
|
$ |
34.8 |
|
$ |
168.2 |
Netback after hedging ($ millions) |
|
$ |
127.0 |
|
$ |
51.3 |
|
$ |
178.3 |
|
|
Three months ended March 31, 2017 |
|||||||
Netbacks by Property Type |
|
Crude Oil |
|
Natural Gas |
|
Total |
|||
Average Daily Production |
|
40,393 BOE/day |
|
267,264 Mcfe/day |
|
84,937 BOE/day |
|||
Netback(1) $ per BOE or Mcfe |
|
(per BOE) |
|
(per Mcfe) |
|
(per BOE) |
|||
Oil and natural gas sales |
|
$ |
49.14 |
|
$ |
4.12 |
|
$ |
36.33 |
Royalties and production taxes |
|
|
(12.58) |
|
|
(0.60) |
|
|
(7.89) |
Cash operating expenses |
|
|
(10.26) |
|
|
(0.54) |
|
|
(6.57) |
Transportation costs |
|
|
(2.50) |
|
|
(0.85) |
|
|
(3.88) |
Netback before hedging |
|
$ |
23.80 |
|
$ |
2.13 |
|
$ |
17.99 |
Cash gains/(losses) |
|
|
(0.26) |
|
|
0.31 |
|
|
0.86 |
Netback after hedging |
|
$ |
23.54 |
|
$ |
2.44 |
|
$ |
18.85 |
Netback before hedging ($ millions) |
|
$ |
86.4 |
|
$ |
51.1 |
|
$ |
137.5 |
Netback after hedging ($ millions) |
|
$ |
85.5 |
|
$ |
58.6 |
|
$ |
144.1 |
(1)See “Non-GAAP Measures” in this MD&A.
Crude oil netbacks per BOE before hedging were higher for the three months ended March 31, 2018 compared to the same period in 2017 primarily due to higher crude oil sales and improved realized prices. Natural gas netbacks before hedging were lower for the first quarter of 2018 compared to the same period in 2017 mainly due to lower production with the divestment of non-core Canadian natural gas properties and weaker realized prices. For the three months ended March 31, 2018, our crude oil properties accounted for 79% of our netback before hedging, compared to 63% during the same period in 2017.
General and Administrative (“G&A”) Expenses
Total G&A expenses include cash G&A expenses and share-based compensation (“SBC”) charges related to our long-term incentive plans (“LTI plans”). See Note 11 and Note 14 to the Interim Financial Statements for further details.
|
|
Three months ended March 31, |
||||
($ millions) |
|
2018 |
|
2017 | ||
Cash: |
|
|
|
|
|
|
G&A expense |
|
$ |
13.2 |
|
$ |
14.3 |
Share-based compensation expense |
|
|
1.9 |
|
|
0.2 |
|
|
|
|
|
|
|
Non-Cash: |
|
|
|
|
|
|
Share-based compensation expense |
|
|
9.1 |
|
|
8.1 |
Equity swap loss/(gain) |
|
|
(1.0) |
|
|
0.9 |
Total G&A expenses |
|
$ |
23.2 |
|
$ |
23.5 |
ENERPLUS 2018 Q1 REPORT 13
|
|
Three months ended March 31, |
||||
(Per BOE) |
|
2018 |
|
2017 | ||
Cash: |
|
|
|
|
|
|
G&A expense |
|
$ |
1.72 |
|
$ |
1.87 |
Share-based compensation expense |
|
|
0.25 |
|
|
0.02 |
|
|
|
|
|
|
|
Non-Cash: |
|
|
|
|
|
|
Share-based compensation expense |
|
|
1.19 |
|
|
1.06 |
Equity swap loss/(gain) |
|
|
(0.13) |
|
|
0.12 |
Total G&A expenses |
|
$ |
3.03 |
|
$ |
3.07 |
For the three months ended March 31, 2018, cash G&A expenses were $13.2 million or $1.72/BOE compared to $14.3 million or $1.87/BOE for the same period in 2017. The decrease in cash G&A expenses from the prior year was primarily due to the impact of reductions in staff levels throughout 2017 as we continued to focus our business through asset divestments.
During the quarter, we reported cash SBC expense of $1.9 million due to the grant of additional deferred share units and the increase in our share price on outstanding deferred share units. In comparison, during the same period of 2017, we recorded cash SBC expense of $0.2 million. We recorded non-cash SBC of $9.1 million or $1.19/BOE in the first quarter of 2018, which was in line with $8.1 million or $1.06/BOE during the same period in 2017.
We have hedges in place on the outstanding cash-settled grants under our LTI plans. In the first quarter we recorded a non-cash mark-to-market gain of $1.0 million on these hedges due to the increase in our share price. As of March 31, 2018 we had 470,000 units hedged at a weighted average price of $16.89 per share.
We are maintaining our annual cash G&A guidance of $1.65/BOE.
Interest Expense
For the three months ended March 31, 2018, we recorded total interest expense of $9.1 million compared to $10.1 million for the same period in 2017. The decrease in interest expense for the three month period was primarily due to the impact of a strengthening Canadian dollar on our U.S. dollar denominated interest expense, along with the payment of our first installment of US$22 million on our US$110 million senior notes, which carry a higher coupon rate, during the second quarter of 2017.
At March 31, 2018, we were undrawn on our $800 million bank credit facility and our debt balance consisted entirely of fixed interest rate senior notes with a weighted average interest rate of 4.8%. See Note 8 to the Interim Financial Statements for further details.
Foreign Exchange
|
|
Three months ended March 31, |
||||
($ millions) |
|
2018 |
|
2017 | ||
Realized: |
|
|
|
|
|
|
Foreign exchange (gain)/loss on settlements |
|
$ |
0.1 |
|
$ |
0.1 |
Translation of U.S. dollar cash held in Canada (gain)/loss |
|
|
(7.3) |
|
|
— |
Unrealized (gain)/loss |
|
|
17.6 |
|
|
(3.9) |
Total foreign exchange (gain)/loss |
|
$ |
10.4 |
|
$ |
(3.8) |
USD/CDN average exchange rate |
|
|
1.26 |
|
|
1.32 |
USD/CDN period end exchange rate |
|
|
1.29 |
|
|
1.33 |
For the three months ended March 31, 2018, we recorded a net foreign exchange loss of $10.4 million compared to a gain of $3.8 million for the same period in 2017. Realized gains and losses include day-to-day transactions recorded in foreign currencies, and the translation of our U.S. dollar denominated cash held in Canada, while unrealized gains and losses are recorded on the translation of our U.S. dollar denominated debt and working capital at each period end. Comparing the period end exchange rate at March 31, 2018 to December 31, 2017, the Canadian dollar weakened relative to the U.S. dollar, resulting in an unrealized loss of $17.6 million. See Note 12 to the Interim Financial Statements for further details.
14 ENERPLUS 2018 Q1 REPORT
Capital Investment
|
|
Three months ended March 31, |
||||
($ millions) |
|
2018 |
|
2017 | ||
Capital spending |
|
$ |
151.5 |
|
$ |
120.4 |
Office capital |
|
|
1.4 |
|
|
0.1 |
Sub-total |
|
|
152.9 |
|
|
120.5 |
Property and land acquisitions |
|
$ |
12.3 |
|
$ |
2.5 |
Property divestments |
|
|
(7.0) |
|
|
0.9 |
Sub-total |
|
|
5.3 |
|
|
3.4 |
Total (1) |
|
$ |
158.2 |
|
$ |
123.9 |
(1) |
Excludes changes in non-cash investing working capital. See Note 17(b) to the Interim Financial Statements for further details. |
Capital spending for the three months ended March 31, 2018, totaled $151.5 million compared to the $120.4 million for the same period in 2017. The increase in spending is in line with our strategy to deliver production and liquids growth through 2018. During the quarter we spent $121.5 million on our U.S. crude oil properties, $16.8 million on our Marcellus natural gas assets and $12.1 million on our Canadian waterflood properties.
In the first quarter, we completed $12.3 million in property and land acquisitions which included minor acquisitions of leases and undeveloped land. During the first quarter, property divestments totaled $7.0 million primarily related to an acreage swap in North Dakota and the divestment of non-core properties in N.W. Alberta with associated production of approximately 600 BOE/day.
We continue to expect annual capital spending of $535 to $585 million.
Depletion, Depreciation and Accretion (“DD&A”)
|
|
Three months ended March 31, |
||||
($ millions, except per BOE amounts) |
|
2018 |
|
2017 | ||
DD&A expense |
|
$ |
64.0 |
|
$ |
60.6 |
Per BOE |
|
$ |
8.36 |
|
$ |
7.92 |
DD&A of property, plant and equipment (“PP&E”) is recognized using the unit-of-production method based on proved reserves. For the three months ended March 31, 2018, DD&A increased compared to the same period of 2017 as a result of an increased weighting of U.S. production with higher depletion rates.
In connection with our operations, we incur abandonment and reclamation costs related to assets such as surface leases, wells, facilities and pipelines. Total asset retirement obligations included on our balance sheet are based on our net ownership interest and management’s estimate of costs to abandon and reclaim such assets and the timing of the cost to be incurred in future periods. We have estimated the net present value of our asset retirement obligation to be $118.6 million at March 31, 2018, compared to $117.7 million at December 31, 2017. For the three months ended March 31, 2018, asset retirement obligation settlements were $3.3 million compared to $2.5 million during the same period in 2017. As a result of our divestments in the first quarter of 2018, we have reduced our asset retirement obligation by $3.7 million. See Note 9 to the Interim Financial Statements for further details.
|
|
Three months ended March 31, |
||||
($ millions) |
|
2018 |
|
2017 | ||
Current tax expense/(recovery) |
|
$ |
0.1 |
|
$ |
0.1 |
Deferred tax expenses/(recovery) |
|
|
12.4 |
|
|
28.8 |
Total tax expense/(recovery) |
|
$ |
12.5 |
|
$ |
28.9 |
We recorded a total tax expense of $12.5 million during the first quarter of 2018 compared to $28.9 million for the same period in 2017. The decrease in the total tax expense is due to lower overall income in 2018, as well as a reduction to the U.S. federal income tax rate to 21% from 35% effective January 1, 2018 with the enactment of the U.S. Tax Cuts and Jobs Act. See Note 13 to the Interim Financial Statements for further details.
ENERPLUS 2018 Q1 REPORT 15
LIQUIDITY AND CAPITAL RESOURCES
There are numerous factors that influence how we assess our liquidity and leverage, including commodity price cycles, capital spending levels, acquisition and divestment plans, hedging and dividend levels. We also assess our leverage relative to our most restrictive debt covenant under our bank credit facility 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 March 31, 2018, our senior debt to adjusted EBITDA ratio was 1.2x and our net debt to adjusted funds flow ratio was 0.5x. 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 our liquidity.
Total debt net of cash at March 31, 2018 was $292.0 million, a decrease of 10% compared to $325.8 million at December 31, 2017. Total debt was comprised of $688.4 million of senior notes less $396.4 million in cash. At March 31, 2018, we were undrawn on our $800 million bank credit facility.
Our adjusted payout ratio, which is calculated as cash dividends plus capital and office expenditures divided by adjusted funds flow, was 103% for the three months ended March 31, 2018, compared to 107% for the same period in 2017.
Our working capital deficiency, excluding cash and current deferred financial assets and liabilities, increased to $162.6 million at March 31, 2018 from $107.6 million at December 31, 2017. We expect to finance our working capital deficit and our ongoing working capital requirements through cash, adjusted funds flow and our bank credit facility. We have sufficient liquidity to meet our financial commitments, as disclosed under “Commitments” in the Annual MD&A.
At March 31, 2018, we were in compliance with all covenants under our bank credit facility and outstanding senior notes. Our bank credit facility and senior note purchase agreements have been filed under our SEDAR profile at www.sedar.com.
The following table lists our financial covenants as at March 31, 2018:
Covenant Description |
|
|
|
March 31, 2018 |
Bank Credit Facility: |
|
Maximum Ratio |
|
|
Senior debt to adjusted EBITDA (1) |
|
3.5x |
|
1.2x |
Total debt to adjusted EBITDA (1) |
|
4.0x |
|
1.2x |
Total debt to capitalization |
|
50% |
|
21% |
|
|
|
|
|
Senior Notes: |
|
Maximum Ratio |
|
|
Senior debt to adjusted EBITDA (1)(2) |
|
3.0x - 3.5x |
|
1.2x |
Senior debt to consolidated present value of total proved reserves(3) |
|
60% |
|
26% |
|
|
Minimum Ratio |
|
|
Adjusted EBITDA to interest |
|
4.0x |
|
16.4x |
Definitions
“Senior debt” is calculated as the sum of drawn amounts on our bank credit facility, outstanding letters of credit and the principal amount of senior notes.
“Adjusted EBITDA” is calculated as net income less interest, taxes, depletion, depreciation, amortization, 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 March 31, 2018 was $171.7 million and $619.5 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 $1.1 billion adjustment related to our adoption of U.S. GAAP.
Footnotes
(1)See “Non-GAAP Measures” in this MD&A for a reconciliation of adjusted EBITDA to net income.
(2)Senior debt to adjusted EBITDA for the senior notes may increase to 3.5x for a period of 6 months for the senior notes, after which the ratio decreases to 3.0x.
(3)Senior debt to consolidated present value of total proved reserves is calculated annually on December 31 based on before tax reserves at forecast prices discounted at 10%.
Dividends
|
|
Three months ended March 31, |
||||
($ millions, except per share amounts) |
|
2018 |
|
2017 | ||
Dividends to shareholders |
|
$ |
7.3 |
|
$ |
7.2 |
Per weighted average share (Basic) |
|
$ |
0.03 |
|
$ |
0.03 |
During the three months ended March 31, 2018, we reported total dividends of $7.3 million or $0.03 per share compared to $7.2 million or $0.03 per share for the same period in 2017.
The dividend is part of our strategy to create shareholder value. We continue to monitor commodity prices and economic conditions and are prepared to make adjustments as necessary.
16 ENERPLUS 2018 Q1 REPORT
Shareholders’ Capital
|
|
Three months ended March 31, |
||||
|
|
2018 |
|
2017 | ||
Share capital ($ millions) |
|
$ |
3,411.9 |
|
$ |
3,386.9 |
|
|
|
|
|
|
|
Common shares outstanding (thousands) |
|
|
244,773 |
|
|
242,129 |
Weighted average shares outstanding – basic (thousands) |
|
|
243,874 |
|
|
241,285 |
Weighted average shares outstanding – diluted (thousands) |
|
|
249,191 |
|
|
246,358 |
During the first quarter, a total of 2,644,000 shares were issued pursuant to our stock option plan and treasury-settled LTI plans and $23.5 million was transferred from paid-in capital to share capital (2017 – 1,646,000; $21.0 million). For further details, see Note 14 to the Interim Financial Statements.
On March 21, 2018, Enerplus announced the acceptance of its Normal Course Issuer Bid (“the bid”) by the Toronto Stock Exchange (“TSX”). The bid allows Enerplus to purchase up to 17,095,598 common shares on the TSX, the New York Stock Exchange and/or alternative Canadian trading systems over a period of twelve months commencing on March 26, 2018. All common shares purchased under the bid will be cancelled. For the period ended March 31, 2018, no common shares were purchased.
At May 2, 2018, we had 244,823,365 common shares outstanding. In addition, an aggregate of 11,866,379 common shares may be issued to settle outstanding grants under the Performance Share Unit (“PSU”), Restricted Share Unit, and stock option plans, assuming the maximum payout multiplier of 2.0 times for the PSUs.
SELECTED CANADIAN AND U.S. FINANCIAL RESULTS
|
|
Three months ended March 31, 2018 |
|
Three months ended March 31, 2017 |
||||||||||||||
($ millions, except per unit amounts) |
|
Canada |
|
U.S. |
|
Total |
|
Canada |
|
U.S. |
|
Total |
||||||
Average Daily Production Volumes(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/day) |
|
|
9,513 |
|
|
27,930 |
|
|
37,443 |
|
|
12,907 |
|
|
20,271 |
|
|
33,178 |
Natural gas liquids (bbls/day) |
|
|
1,247 |
|
|
2,838 |
|
|
4,085 |
|
|
1,405 |
|
|
1,753 |
|
|
3,158 |
Natural gas (Mcf/day) |
|
|
33,132 |
|
|
228,178 |
|
|
261,310 |
|
|
68,542 |
|
|
223,065 |
|
|
291,607 |
Total average daily production (BOE/day) |
|
|
16,282 |
|
|
68,798 |
|
|
85,080 |
|
|
25,736 |
|
|
59,201 |
|
|
84,937 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pricing(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (per bbl) |
|
$ |
52.82 |
|
$ |
75.41 |
|
$ |
69.67 |
|
$ |
51.67 |
|
$ |
61.26 |
|
$ |
57.53 |
Natural gas liquids (per bbl) |
|
|
45.11 |
|
|
20.66 |
|
|
28.13 |
|
|
37.09 |
|
|
38.30 |
|
|
37.76 |
Natural gas (per Mcf) |
|
|
3.12 |
|
|
3.56 |
|
|
3.50 |
|
|
3.65 |
|
|
3.62 |
|
|
3.63 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital spending |
|
$ |
13.2 |
|
$ |
138.3 |
|
$ |
151.5 |
|
$ |
25.0 |
|
$ |
95.4 |
|
$ |
120.4 |
Acquisitions |
|
|
1.1 |
|
|
11.2 |
|
|
12.3 |
|
|
1.5 |
|
|
1.0 |
|
|
2.5 |
Divestments |
|
|
(0.9) |
|
|
(6.1) |
|
|
(7.0) |
|
|
0.9 |
|
|
— |
|
|
0.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Netback(3) Before Hedging |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales |
|
$ |
60.7 |
|
$ |
267.8 |
|
$ |
328.5 |
|
$ |
87.2 |
|
$ |
190.5 |
|
$ |
277.7 |
Royalties |
|
|
(9.9) |
|
|
(53.6) |
|
|
(63.5) |
|
|
(11.9) |
|
|
(38.0) |
|
|
(49.9) |
Production taxes |
|
|
(0.8) |
|
|
(15.3) |
|
|
(16.1) |
|
|
(1.1) |
|
|
(9.3) |
|
|
(10.4) |
Cash operating expenses |
|
|
(20.6) |
|
|
(33.2) |
|
|
(53.8) |
|
|
(26.6) |
|
|
(23.7) |
|
|
(50.3) |
Transportation costs |
|
|
(3.0) |
|
|
(23.9) |
|
|
(26.9) |
|
|
(4.4) |
|
|
(25.2) |
|
|
(29.6) |
Netback before hedging |
|
$ |
26.4 |
|
$ |
141.8 |
|
$ |
168.2 |
|
$ |
43.2 |
|
$ |
94.3 |
|
$ |
137.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments loss/(gain) |
|
$ |
20.5 |
|
$ |
— |
|
$ |
20.5 |
|
$ |
(57.6) |
|
$ |
— |
|
$ |
(57.6) |
General and administrative expense(4) |
|
|
15.4 |
|
|
7.8 |
|
|
23.2 |
|
|
17.8 |
|
|
5.7 |
|
|
23.5 |
Current income tax expense/(recovery) |
|
|
— |
|
|
0.1 |
|
|
0.1 |
|
|
— |
|
|
0.1 |
|
|
0.1 |
(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.
(4)Includes share-based compensation.
ENERPLUS 2018 Q1 REPORT 17
QUARTERLY FINANCIAL INFORMATION
|
|
Oil and Natural Gas |
|
|
|
|
Net Income/(Loss) Per Share |
|||||
($ millions, except per share amounts) |
|
Sales, Net of Royalties |
|
Net Income/(Loss) |
|
Basic |
|
Diluted |
||||
2018 |
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
265.0 |
|
$ |
29.6 |
|
$ |
0.12 |
|
$ |
0.12 |
Total 2018 |
|
$ |
265.0 |
|
$ |
29.6 |
|
$ |
0.12 |
|
$ |
0.12 |
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
Fourth Quarter |
|
$ |
271.1 |
|
$ |
15.3 |
|
$ |
0.06 |
|
$ |
0.06 |
Third Quarter |
|
|
196.1 |
|
|
16.1 |
|
|
0.07 |
|
|
0.07 |
Second Quarter |
|
|
225.7 |
|
|
129.3 |
|
|
0.53 |
|
|
0.52 |
First Quarter |
|
|
227.8 |
|
|
76.3 |
|
|
0.32 |
|
|
0.31 |
Total 2017 |
|
$ |
920.7 |
|
$ |
237.0 |
|
$ |
0.98 |
|
$ |
0.96 |
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
Fourth Quarter |
|
$ |
217.4 |
|
$ |
840.3 |
|
$ |
3.49 |
|
$ |
3.43 |
Third Quarter |
|
|
188.3 |
|
|
(100.7) |
|
|
(0.42) |
|
|
(0.42) |
Second Quarter |
|
|
174.3 |
|
|
(168.5) |
|
|
(0.77) |
|
|
(0.77) |
First Quarter |
|
|
142.7 |
|
|
(173.7) |
|
|
(0.84) |
|
|
(0.84) |
Total 2016 |
|
$ |
722.7 |
|
$ |
397.4 |
|
$ |
1.75 |
|
$ |
1.72 |
Oil and natural gas sales, net of royalties, decreased slightly in the first quarter of 2018 compared to the fourth quarter of 2017 due to decreased production volumes offset by higher realized prices. Net income increased in the first quarter of 2018 due to the higher deferred income tax expense recorded in the fourth quarter of 2017 as a result of re-measurement of our U.S. deferred tax assets for the U.S. federal income tax rate reduction. Oil and natural gas sales, net of royalties, increased in 2017 compared to 2016 due to an increase in realized commodity prices, offset by a decrease in production due to non-core asset divestments. Net income for 2017 decreased from 2016, due to lower gains recorded on asset divestments, along with an increase in deferred tax expense. Net income was higher in the second quarter of 2017 due to a $78.4 million gain recorded on the divestment of certain Canadian assets.
2018 UPDATED GUIDANCE
Our 2018 guidance is summarized below. We have included second quarter 2018 crude oil and natural gas liquids production guidance of 48,000 – 50,000 bbls/day and revised our 2018 average U.S. Bakken crude oil differential to US$3.50/bbl below WTI.
All other guidance targets remain unchanged. This guidance does not include any additional acquisitions or divestments.
Summary of 2018 Expectations |
|
Target |
Capital spending |
|
$535 – $585 million |
Average second quarter crude oil and natural gas liquids production |
|
48,000 - 50,000 bbls/day |
Average annual production |
|
86,000 – 91,000 BOE/day |
Average annual crude oil and natural gas liquids production |
|
46,000 – 50,000 bbls/day |
Average royalty and production tax rate (% of gross sales, before transportation) |
|
25% |
Operating expenses |
|
$7.00/BOE |
Transportation costs |
|
$3.60/BOE |
Cash G&A expenses |
|
$1.65/BOE |
2018 Differential/Basis Outlook(1) |
|
Target |
Average U.S. Bakken crude oil differential (compared to WTI crude oil) |
|
US$(3.50)/bbl (from US$(2.50)/bbl) |
Average Marcellus natural gas sales price differential (compared to NYMEX natural gas) |
|
US$(0.40)/Mcf |
(1) |
Excludes transportation costs. |
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 our crude oil and natural gas assets. Netback is calculated as oil and natural gas sales less royalties, production taxes, cash operating expenses and transportation costs.
18 ENERPLUS 2018 Q1 REPORT
Calculation of Netback |
|
Three months ended March 31, |
||||
($ millions) |
|
2018 |
|
2017 | ||
Oil and natural gas sales |
|
$ |
328.5 |
|
$ |
277.7 |
Less: |
|
|
|
|
|
|
Royalties |
|
|
(63.5) |
|
|
(49.9) |
Production taxes |
|
|
(16.1) |
|
|
(10.4) |
Cash operating expenses(1) |
|
|
(53.8) |
|
|
(50.3) |
Transportation costs |
|
|
(26.9) |
|
|
(29.6) |
Netback before hedging |
|
$ |
168.2 |
|
$ |
137.5 |
Cash gains/(losses) on derivative instruments |
|
|
10.1 |
|
|
6.6 |
Netback after hedging |
|
$ |
178.3 |
|
$ |
144.1 |
(1)Total operating expenses have been adjusted to exclude a non-cash loss of $0.1 million for the three months ended March 31, 2017 (Three months ended March 31, 2018 – nil).
“Adjusted funds flow” is used by Enerplus and is useful to investors and securities analysts in analyzing operating performance, leverage and liquidity. Adjusted funds flow is calculated as net cash from operating activities before asset retirement obligation expenditures and changes in non-cash operating working capital.
Reconciliation of Cash Flow from Operating Activities to Adjusted Funds Flow |
|
Three months ended March 31, |
||||
($ millions) |
|
2018 |
|
2017 | ||
Cash flow from operating activities |
|
$ |
159.3 |
|
$ |
127.9 |
Asset retirement obligation expenditures |
|
|
3.3 |
|
|
2.5 |
Changes in non-cash operating working capital |
|
|
(7.4) |
|
|
(10.5) |
Adjusted funds flow |
|
$ |
155.2 |
|
$ |
119.9 |
“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 any outstanding bank credit facility balance, minus cash and restricted cash.
“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 a trailing twelve months of adjusted funds flow. This measure is not equivalent to debt to earnings before interest, taxes, depreciation, amortization, 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 our adjusted payout ratio as cash dividends plus capital and office expenditures divided by adjusted funds flow.
Calculation of Adjusted Payout Ratio |
|
Three months ended March 31, |
||||
($ millions) |
|
2018 |
|
2017 | ||
Dividends |
|
$ |
7.3 |
|
$ |
7.2 |
Capital and office expenditures |
|
|
152.9 |
|
|
120.5 |
Sub-total |
|
$ |
160.2 |
|
$ |
127.7 |
Adjusted funds flow |
|
$ |
155.2 |
|
$ |
119.9 |
Adjusted payout ratio (%) |
|
|
103% |
|
|
107% |
ENERPLUS 2018 Q1 REPORT 19
“Adjusted EBITDA” is used by Enerplus and its lenders to determine compliance with financial covenants under its bank credit facility and outstanding senior notes.
Reconciliation of Net Income to Adjusted EBITDA(1) |
|
|
|
($ millions) |
|
March 31, 2018 |
|
Net income/(loss) |
|
$ |
190.3 |
Add: |
|
|
|
Interest |
|
|
37.7 |
Current and deferred tax expense/(recovery) |
|
|
65.7 |
DD&A and asset impairment |
|
|
254.2 |
Other non-cash charges(2) |
|
|
75.9 |
Sub-total |
|
$ |
623.8 |
Adjustment for material acquisitions and divestments(3) |
|
|
(4.3) |
Adjusted EBITDA |
|
$ |
619.5 |
(1) |
Adjusted EBITDA is calculated based on the trailing four quarters. Balances above at March 31, 2018 include the three months ended March 31, 2018 and the second, third and fourth quarter of 2017. |
(2) |
Includes the change in fair value of commodity derivatives, fixed price electricity swaps and equity swaps, non-cash SBC, and unrealized foreign exchange gains/losses. |
(3) |
EBITDA is adjusted for material acquisitions or divestments during the period with net proceeds greater than $50 million as if that acquisition or disposition had been made at the beginning of the period. |
In addition, the Company uses certain financial measures within the “Overview” and “Liquidity and Capital Resources” sections 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”, “maximum 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 its bank credit facility and outstanding senior notes. Calculation of such terms is described under the “Liquidity and Capital Resources” section of this MD&A.
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 March 31, 2018, 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 January 1, 2018 and ended March 31, 2018 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 current Annual Information Form (“AIF”), 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 2018 average production volumes and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting our adjusted funds flow; anticipated production volumes subject to curtailment; the results from our drilling program and the timing of related production; oil and natural gas prices and differentials and our commodity risk management program in 2018 and in the future; expectations regarding our realized oil and natural gas prices; future royalty rates on our production and future production taxes; anticipated cash G&A, share-based compensation and financing expenses; operating and transportation costs; capital spending levels in 2018 and impact thereof on our production levels; potential future asset and goodwill impairments, as well as relevant factors that may affect such impairments; 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 our ability to comply with debt covenants under our bank credit facility and outstanding senior notes and to negotiate relief if required; our future acquisitions and dispositions, expecting timing thereof and use of proceeds therefrom; and the amount of future cash dividends that we may pay to our shareholders.
20 ENERPLUS 2018 Q1 REPORT
The forward-looking information contained in this MD&A reflects several material factors and expectations and assumptions of Enerplus including, without limitation: that we will conduct our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; that lack of adequate infrastructure will not result in curtailment of production and/or reduced realized prices beyond our current expectations; current commodity price, differentials and cost assumptions; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve and contingent resource volumes; 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 negotiate debt covenant relief under our bank credit facility and outstanding senior notes if required; the availability of third party services; and the extent of our liabilities. In addition, our updated 2018 guidance contained in this MD&A is based on the following prices for the first quarter: a WTI price of US$65.00/bbl, a NYMEX price of US$3.00/Mcf, an AECO price of $2.00/GJ and a USD/CDN exchange rate of 1.27. Enerplus believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.
The forward-looking information included in this 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: continued low commodity prices environment or further volatility in commodity prices; changes in realized prices of Enerplus’ products; changes in the demand for or supply of our products; unanticipated operating results, results from our capital spending activities or production declines; curtailment of our production due to low realized prices or lack of adequate infrastructure; changes in tax or environmental laws, royalty rates or other regulatory matters; 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; and certain other risks detailed from time to time in our public disclosure documents (including, without limitation, those risks identified in our AIF, our Annual MD&A and Form 40-F as at December 31, 2017).
The forward-looking information contained in this MD&A speak 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.
ENERPLUS 2018 Q1 REPORT 21
STATEMENTS
Exhibit 99.2
Condensed Consolidated Balance Sheets
(CDN$ thousands) unaudited |
|
Note |
|
March 31, 2018 |
|
December 31, 2017 |
||
Assets |
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
|
$ |
396,395 |
|
$ |
346,548 |
Accounts receivable |
|
4 |
|
|
135,988 |
|
|
130,576 |
Deferred financial assets |
|
15 |
|
|
2,561 |
|
|
3,852 |
Other current assets |
|
|
|
|
4,282 |
|
|
5,902 |
|
|
|
|
|
539,226 |
|
|
486,878 |
Property, plant and equipment: |
|
|
|
|
|
|
|
|
Oil and natural gas properties (full cost method) |
|
5 |
|
|
1,005,222 |
|
|
889,967 |
Other capital assets, net |
|
5 |
|
|
10,673 |
|
|
10,064 |
Property, plant and equipment |
|
|
|
|
1,015,895 |
|
|
900,031 |
Goodwill |
|
|
|
|
643,553 |
|
|
638,878 |
Deferred income tax asset |
|
13 |
|
|
566,317 |
|
|
569,937 |
Income tax receivable |
|
13 |
|
|
51,356 |
|
|
50,108 |
Total Assets |
|
|
|
$ |
2,816,347 |
|
$ |
2,645,832 |
|
|
|
|
|
|
|
|
|
Liabilities |
|
|
|
|
|
|
|
|
Current liabilities |
|
|
|
|
|
|
|
|
Accounts payable |
|
7 |
|
$ |
272,039 |
|
$ |
213,978 |
Dividends payable |
|
|
|
|
2,448 |
|
|
2,421 |
Current portion of long-term debt |
|
8 |
|
|
28,345 |
|
|
27,656 |
Deferred financial liabilities |
|
15 |
|
|
50,153 |
|
|
28,642 |
|
|
|
|
|
352,985 |
|
|
272,697 |
Deferred financial liabilities |
|
15 |
|
|
16,727 |
|
|
9,907 |
Long-term debt |
|
8 |
|
|
660,028 |
|
|
644,723 |
Asset retirement obligation |
|
9 |
|
|
118,645 |
|
|
117,736 |
|
|
|
|
|
795,400 |
|
|
772,366 |
Total Liabilities |
|
|
|
|
1,148,385 |
|
|
1,045,063 |
|
|
|
|
|
|
|
|
|
Shareholders’ Equity |
|
|
|
|
|
|
|
|
Share capital – authorized unlimited common shares, no par value Issued and outstanding: March 31, 2018 – 245 million shares December 31, 2017 – 242 million shares |
|
14 |
|
|
3,411,878 |
|
|
3,386,946 |
Paid-in capital |
|
|
|
|
60,951 |
|
|
75,375 |
Accumulated deficit |
|
|
|
|
(2,102,359) |
|
|
(2,124,676) |
Accumulated other comprehensive income/(loss) |
|
|
|
|
297,492 |
|
|
263,124 |
|
|
|
|
|
1,667,962 |
|
|
1,600,769 |
Total Liabilities & Shareholders' Equity |
|
|
|
$ |
2,816,347 |
|
$ |
2,645,832 |
|
|
|
|
|
|
|
|
|
Contingencies |
|
16 |
|
|
|
|
|
|
The accompanying notes to the Condensed Consolidated Financial Statements are an integral part of these statements.
22 ENERPLUS 2018 Q1 REPORT
Condensed Consolidated Statements of Income/(Loss) and Comprehensive Income/(Loss)
|
|
|
|
Three months ended |
||||
|
|
|
|
March 31, |
||||
(CDN$ thousands, except per share amounts) unaudited |
|
Note |
|
2018 |
|
2017 | ||
Revenues |
|
|
|
|
|
|
|
|
Oil and natural gas sales, net of royalties |
|
10 |
|
$ |
265,020 |
|
$ |
227,816 |
Commodity derivative instruments gain/(loss) |
|
15 |
|
|
(20,464) |
|
|
57,562 |
|
|
|
|
|
244,556 |
|
|
285,378 |
Expenses |
|
|
|
|
|
|
|
|
Operating |
|
|
|
|
53,761 |
|
|
50,381 |
Transportation |
|
|
|
|
26,921 |
|
|
29,628 |
Production taxes |
|
|
|
|
16,135 |
|
|
10,364 |
General and administrative |
|
11 |
|
|
23,224 |
|
|
23,493 |
Depletion, depreciation and accretion |
|
|
|
|
64,046 |
|
|
60,580 |
Interest |
|
|
|
|
9,103 |
|
|
10,141 |
Foreign exchange (gain)/loss |
|
12 |
|
|
10,371 |
|
|
(3,858) |
Other expense/(income) |
|
|
|
|
(1,183) |
|
|
(485) |
|
|
|
|
|
202,378 |
|
|
180,244 |
Income/(Loss) before taxes |
|
|
|
|
42,178 |
|
|
105,134 |
Current income tax expense/(recovery) |
|
13 |
|
|
66 |
|
|
74 |
Deferred income tax expense/(recovery) |
|
13 |
|
|
12,475 |
|
|
28,767 |
Net Income/(Loss) |
|
|
|
$ |
29,637 |
|
$ |
76,293 |
|
|
|
|
|
|
|
|
|
Other Comprehensive Income/(Loss) |
|
|
|
|
|
|
|
|
Change in cumulative translation adjustment |
|
|
|
|
34,368 |
|
|
(10,302) |
Total Comprehensive Income/(Loss) |
|
|
|
$ |
64,005 |
|
$ |
65,991 |
|
|
|
|
|
|
|
|
|
Net income/(Loss) per share |
|
|
|
|
|
|
|
|
Basic |
|
14 |
|
$ |
0.12 |
|
$ |
0.32 |
Diluted |
|
14 |
|
$ |
0.12 |
|
$ |
0.31 |
The accompanying notes to the Condensed Consolidated Financial Statements are an integral part of these statements.
ENERPLUS 2018 Q1 REPORT 23
Condensed Consolidated Statements of Changes in Shareholders’ Equity
|
|
|
Three months ended |
|||
March 31, |
||||||
(CDN$ thousands) unaudited |
|
2018 |
|
2017 | ||
Share Capital |
|
|
|
|
|
|
Balance, beginning of year |
|
$ |
3,386,946 |
|
$ |
3,365,962 |
Share-based compensation – settled |
|
|
23,389 |
|
|
20,984 |
Stock Option Plan - cash |
|
|
1,429 |
|
|
— |
Stock Option Plan - exercised |
|
|
114 |
|
|
— |
Balance, end of period |
|
$ |
3,411,878 |
|
$ |
3,386,946 |
|
|
|
|
|
|
|
Paid-in Capital |
|
|
|
|
|
|
Balance, beginning of year |
|
$ |
75,375 |
|
$ |
73,783 |
Share-based compensation – settled |
|
|
(23,389) |
|
|
(20,984) |
Share-based compensation – non-cash |
|
|
9,079 |
|
|
8,120 |
Stock Option Plan - exercised |
|
|
(114) |
|
|
— |
Balance, end of period |
|
$ |
60,951 |
|
$ |
60,919 |
|
|
|
|
|
|
|
Accumulated Deficit |
|
|
|
|
|
|
Balance, beginning of year |
|
$ |
(2,124,676) |
|
$ |
(2,332,641) |
Net income/(loss) |
|
|
29,637 |
|
|
76,293 |
Dividends declared |
|
|
(7,320) |
|
|
(7,242) |
Balance, end of period |
|
$ |
(2,102,359) |
|
$ |
(2,263,590) |
|
|
|
|
|
|
|
Accumulated Other Comprehensive Income/(Loss) |
|
|
|
|
|
|
Balance, beginning of year |
|
$ |
263,124 |
|
$ |
353,401 |
Change in cumulative translation adjustment |
|
|
34,368 |
|
|
(10,302) |
Balance, end of period |
|
$ |
297,492 |
|
$ |
343,099 |
Total Shareholders’ Equity |
|
$ |
1,667,962 |
|
$ |
1,527,374 |
The accompanying notes to the Condensed Consolidated Financial Statements are an integral part of these statements.
24 ENERPLUS 2018 Q1 REPORT
Condensed Consolidated Statements of Cash Flows
|
|
|
|
Three months ended |
||||
|
|
|
|
March 31, |
||||
(CDN$ thousands) unaudited |
|
Note |
|
2018 |
|
2017 | ||
Operating Activities |
|
|
|
|
|
|
|
|
Net income/(loss) |
|
|
|
$ |
29,637 |
|
$ |
76,293 |
Non-cash items add/(deduct): |
|
|
|
|
|
|
|
|
Depletion, depreciation and accretion |
|
|
|
|
64,046 |
|
|
60,580 |
Changes in fair value of derivative instruments |
|
15 |
|
|
29,622 |
|
|
(49,929) |
Deferred income tax expense/(recovery) |
|
13 |
|
|
12,475 |
|
|
28,767 |
Foreign exchange (gain)/loss on debt and working capital |
|
12 |
|
|
17,649 |
|
|
(3,911) |
Share-based compensation |
|
14 |
|
|
9,079 |
|
|
8,120 |
Translation of U.S. dollar cash held in Canada |
|
12 |
|
|
(7,346) |
|
|
— |
Asset retirement obligation expenditures |
|
9 |
|
|
(3,331) |
|
|
(2,541) |
Changes in non-cash operating working capital |
|
17 |
|
|
7,469 |
|
|
10,544 |
Cash flow from/(used in) operating activities |
|
|
|
|
159,300 |
|
|
127,923 |
|
|
|
|
|
|
|
|
|
Financing Activities |
|
|
|
|
|
|
|
|
Dividends |
|
17 |
|
|
(7,294) |
|
|
(7,226) |
Bank credit facility |
|
|
|
|
— |
|
|
(19,229) |
Proceeds from the issuance of shares |
|
14 |
|
|
1,429 |
|
|
— |
Cash flow from/(used in) financing activities |
|
|
|
|
(5,865) |
|
|
(26,455) |
|
|
|
|
|
|
|
|
|
Investing Activities |
|
|
|
|
|
|
|
|
Capital and office expenditures |
|
17 |
|
|
(108,212) |
|
|
(94,171) |
Property and land acquisitions |
|
|
|
|
(6,190) |
|
|
(2,536) |
Property divestments |
|
|
|
|
888 |
|
|
(899) |
Cash flow from/(used in) investing activities |
|
|
|
|
(113,514) |
|
|
(97,606) |
Effect of exchange rate changes on cash and cash equivalents |
|
|
|
|
9,926 |
|
|
(3,569) |
Change in cash and cash equivalents |
|
|
|
|
49,847 |
|
|
293 |
Cash and cash equivalents, beginning of period |
|
|
|
|
346,548 |
|
|
393,305 |
Cash and cash equivalents, end of period |
|
|
|
$ |
396,395 |
|
$ |
393,598 |
The accompanying notes to the Condensed Consolidated Financial Statements are an integral part of these statements.
ENERPLUS 2018 Q1 REPORT 25
NOTES
Notes to Condensed Consolidated Financial Statements
(unaudited)
1)REPORTING ENTITY
These interim Condensed Consolidated Financial Statements (“interim Consolidated Financial Statements”) and notes present the financial position and results of Enerplus Corporation (“The Company” or “Enerplus”) including its Canadian and U.S. subsidiaries. Enerplus is a North American crude oil and natural gas exploration and development company. Enerplus is publicly traded on the Toronto and New York stock exchanges under the ticker symbol ERF. Enerplus’ head office is located in Calgary, Alberta, Canada.
2)BASIS OF PREPARATION
Enerplus’ interim Consolidated Financial Statements present its results of operations and financial position under accounting principles generally accepted in the United States of America (“U.S. GAAP”) for the three months ended March 31, 2018 and the 2017 comparative periods. Certain information and notes normally included with the annual audited Consolidated Financial Statements have been condensed or have been disclosed on an annual basis only. Accordingly, these interim Condensed Consolidated Financial Statements should be read in conjunction with Enerplus’ audited Consolidated Financial Statements as of December 31, 2017. There are no differences in the use of estimates or judgments between these interim Condensed Consolidated Financial Statements and the audited Consolidated Financial Statements and notes thereto for the year ended December 31, 2017.
These unaudited interim Consolidated Financial Statements reflect, in the opinion of Management, all normal and recurring adjustments necessary to present fairly the financial position and results of the Company as at and for the periods presented.
3) ACCOUNTING POLICY CHANGES
a) Recently adopted accounting standards
Enerplus adopted ASC 606 Revenue from contracts with customers effective January 1, 2018 as detailed below. Enerplus used the modified retrospective method to adopt the new standard, with ASC 606 applied to all contracts not yet completed as of the date of adoption and the cumulative effect on comparative periods reflected as an adjustment to opening retained earnings. The adoption of the new standard had no impact on the interim Consolidated Financial Statements, with the exception of the additional disclosures which are detailed in Note 10.
Revenue from the sale of crude oil, natural gas and natural gas liquids is measured based on the consideration specified in contracts with customers, net of sales and other similar taxes. Enerplus recognizes revenue when it satisfies a performance obligation by transferring control of the product to a customer. This is generally at the time the customer obtains legal title to the product and when it is physically transferred to the contractual delivery points.
Enerplus evaluates its arrangements with third parties and partners to determine if the Company acts as the principal or as an agent. In making this evaluation, management considers if Enerplus retains control of the product being delivered to the end customer. As part of this assessment, management considers whether the Company retains the economic benefits associated with the good being delivered to the end customer. Management also considers whether the Company has the primary responsibility for the delivery of the product, the ability to establish prices or the inventory risk. If Enerplus acts in the capacity of an agent rather than as a principal in a transaction, then the revenue is recognized on a net basis, only reflecting the fee, if any, realized by the Company from the transaction.
26 ENERPLUS 2018 Q1 REPORT
b) Future accounting changes
In future accounting periods, the Company will adopt the following Accounting Standards Updates (“ASU”) issued by the Financial Accounting Standards Board (“FASB”):
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The ASU introduced a lessee accounting model that requires lessees to recognize a right-of-use asset and related lease liability on the balance sheet for all leases, including operating leases. The standard does not apply to oil and gas exploration rights, intangible assets or inventory. The new standard also expands disclosures related to the amount, timing and uncertainty of cash flows arising from leases. The standard will be applied using a modified retrospective approach and provides for certain practical expedients at the date of adoption. The ASU is effective January 1, 2019. Enerplus does not expect to early adopt the standard. The Company is currently reviewing existing contracts to determine the impact to the Consolidated Financial Statements of adopting the new standard. The Company is also addressing system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new standard.
In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326). The ASU significantly changes how entities measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than a direct write down of the amortized cost basis. The new guidance is effective January 1, 2020, and will be applied using a modified retrospective approach. Enerplus does not expect to early adopt the standard and continues to assess the impact it will have on the Consolidated Financial Statements.
In January 2017, the FASB issued ASU 2017-04, Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment (Topic 350). This standard eliminates Step 2 of the goodwill impairment test and requires a goodwill impairment charge for the amount that the carrying amount of the reporting unit exceeds the reporting unit’s fair value. The updated guidance is effective January 1, 2020, and will be applied prospectively. Enerplus does not expect to early adopt the standard. The amended standard may affect goodwill impairment tests past the adoption date, the impact of which is not known.
In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815), making more hedging strategies eligible for hedge accounting. The new guidance is effective January 1, 2019, and will be applied prospectively. Hedge accounting continues to be an elective accounting policy choice. Enerplus does not currently apply hedge accounting. Enerplus is currently assessing the impact ASU 2017-12 would have on the Consolidated Financial Statements should it elect to apply hedge accounting.
4)ACCOUNTS RECEIVABLE
($ thousands) |
|
March 31, 2018 |
|
December 31, 2017 |
||
Accrued revenue |
|
$ |
112,407 |
|
$ |
102,051 |
Accounts receivable – trade |
|
|
25,846 |
|
|
30,787 |
Current income tax receivable |
|
|
1,210 |
|
|
1,190 |
Allowance for doubtful accounts |
|
|
(3,475) |
|
|
(3,452) |
Total accounts receivable, net of allowance for doubtful accounts |
|
$ |
135,988 |
|
$ |
130,576 |
5)PROPERTY, PLANT AND EQUIPMENT (“PP&E”)
|
|
|
|
|
Accumulated Depletion, |
|
|
|
|
As of March 31, 2018 |
|
|
|
|
Depreciation, and |
|
|
|
|
($ thousands) |
|
|
Cost |
|
Impairment |
|
|
Net Book Value |
|
Oil and natural gas properties |
|
$ |
13,929,294 |
|
$ |
(12,924,072) |
|
$ |
1,005,222 |
Other capital assets |
|
|
109,401 |
|
|
(98,728) |
|
|
10,673 |
Total PP&E |
|
$ |
14,038,695 |
|
$ |
(13,022,800) |
|
$ |
1,015,895 |
|
|
|
|
|
Accumulated Depletion, |
|
|
|
|
As of December 31, 2017 |
|
|
|
|
Depreciation, and |
|
|
|
|
($ thousands) |
|
|
Cost |
|
Impairment |
|
|
Net Book Value |
|
Oil and natural gas properties |
|
$ |
13,622,266 |
|
$ |
(12,732,299) |
|
$ |
889,967 |
Other capital assets |
|
|
107,582 |
|
|
(97,518) |
|
|
10,064 |
Total PP&E |
|
$ |
13,729,848 |
|
$ |
(12,829,817) |
|
$ |
900,031 |
ENERPLUS 2018 Q1 REPORT 27
6)ASSET IMPAIRMENT
There was no impairment recorded for the three months ended March 31, 2018 and 2017.
The following table outlines the 12-month average trailing benchmark prices and exchange rates used in Enerplus’ ceiling tests from March 31, 2017 through March 31, 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
AECO Natural |
|
|
|
WTI Crude Oil |
|
Exchange Rate |
|
Edm Light Crude |
|
U.S. Henry Hub |
|
Gas Spot |
||||
Period |
|
US$/bbl |
|
US$/CDN$ |
|
CDN$/bbl |
|
Gas US$/Mcf |
|
CDN$/Mcf |
||||
Q1 2018 |
|
$ |
53.49 |
|
1.28 |
|
$ |
64.57 |
|
$ |
3.00 |
|
$ |
2.17 |
Q4 2017 |
|
|
51.34 |
|
1.30 |
|
|
63.57 |
|
|
2.98 |
|
|
2.32 |
Q3 2017 |
|
|
49.81 |
|
1.32 |
|
|
61.63 |
|
|
3.05 |
|
|
2.66 |
Q2 2017 |
|
|
48.95 |
|
1.33 |
|
|
60.79 |
|
|
3.05 |
|
|
2.79 |
Q1 2017 |
|
|
47.61 |
|
1.31 |
|
|
58.02 |
|
|
2.77 |
|
|
2.41 |
7)ACCOUNTS PAYABLE
($ thousands) |
|
March 31, 2018 |
|
December 31, 2017 |
|||||||
Accrued payables |
|
$ |
141,569 |
|
$ |
96,743 |
|||||
Accounts payable - trade |
|
|
130,470 |
|
|
117,235 |
|||||
Total accounts payable |
|
$ |
272,039 |
|
$ |
213,978 |
8)DEBT
($ thousands) |
|
March 31, 2018 |
|
December 31, 2017 |
|||||
Current: |
|
|
|
|
|
|
|||
Senior notes |
|
$ |
28,345 |
|
$ |
27,656 |
|||
Long-term: |
|
|
|
|
|
|
|||
Bank credit facility |
|
$ |
— |
|
$ |
— |
|||
Senior notes |
|
|
660,028 |
|
|
644,723 |
|||
Total debt |
|
$ |
688,373 |
|
$ |
672,379 |
The terms and rates of the Company’s outstanding senior notes are provided below:
|
|
|
|
|
|
|
|
Original |
|
Remaining |
|
CDN$ Carrying |
|
|
|
Interest |
|
|
|
Coupon |
|
Principal |
|
Principal |
|
Value |
|
Issue Date |
|
Payment Dates |
|
Principal Repayment |
|
Rate |
|
($ thousands) |
|
($ thousands) |
|
($ thousands) |
|
September 3, 2014 |
|
March 3 and Sept 3 |
|
5 equal annual installments beginning September 3, 2022 |
|
3.79% |
|
US$200,000 |
|
US$105,000 |
|
$ |
135,283 |
May 15, 2012 |
|
May 15 and Nov 15 |
|
Bullet payment on May 15, 2019 |
|
4.34% |
|
CDN$30,000 |
|
CDN$30,000 |
|
|
30,000 |
May 15, 2012 |
|
May 15 and Nov 15 |
|
Bullet payment on May 15, 2022 |
|
4.40% |
|
US$20,000 |
|
US$20,000 |
|
|
25,768 |
May 15, 2012 |
|
May 15 and Nov 15 |
|
5 equal annual installments beginning May 15, 2020 |
|
4.40% |
|
US$355,000 |
|
US$298,000 |
|
|
383,943 |
June 18, 2009 |
|
June 18 and Dec 18 |
|
4 equal annual installments June 18, 2018 - 2021 |
|
7.97% |
|
US$225,000 |
|
US$88,000 |
|
|
113,379 |
|
|
|
|
|
|
Total carrying value |
|
$ |
688,373 |
9)ASSET RETIREMENT OBLIGATION
|
|
Three months ended |
|
Year ended |
||
($ thousands) |
|
March 31, 2018 |
|
December 31, 2017 |
||
Balance, beginning of year |
|
$ |
117,736 |
|
$ |
181,700 |
Change in estimates |
|
|
6,158 |
|
|
13,064 |
Property acquisitions and development activity |
|
|
325 |
|
|
1,322 |
Dispositions |
|
|
(3,718) |
|
|
(72,306) |
Settlements |
|
|
(3,331) |
|
|
(12,907) |
Accretion expense |
|
|
1,475 |
|
|
6,863 |
Balance, end of period |
|
$ |
118,645 |
|
$ |
117,736 |
Enerplus has estimated the present value of its asset retirement obligation to be $118.6 million at March 31, 2018 based on a total undiscounted liability of $318.7 million (December 31, 2017 – $117.7 million and $318.8 million, respectively). The asset retirement obligation was calculated using a weighted credit-adjusted risk-free rate of 5.70% (December 31, 2017 – 5.73%).
28 ENERPLUS 2018 Q1 REPORT
10)OIL AND NATURAL GAS SALES
|
|
Three months ended March 31, |
||||
($ thousands) |
|
2018 |
|
2017 | ||
Oil and natural gas sales |
|
$ |
328,552 |
|
$ |
277,745 |
Royalties(1) |
|
|
(63,532) |
|
|
(49,929) |
Oil and natural gas sales, net of royalties |
|
$ |
265,020 |
|
$ |
227,816 |
(1) |
Royalties above do not include production taxes which are reported separately on the Condensed Consolidated Statements of Income/(Loss). |
Oil and natural gas revenue by country and by product for the three months ended March 31, 2018 are as follows:
($ thousands) |
|
|
Total revenue, net of royalties(1) |
|
|
Crude oil(2) |
|
|
Natural gas(2) |
|
|
Natural gas liquids(2) |
|
|
Other(3) |
Canada |
|
$ |
50,774 |
|
$ |
35,985 |
|
$ |
9,640 |
|
$ |
4,059 |
|
$ |
1,090 |
United States |
|
|
214,246 |
|
|
151,224 |
|
|
58,595 |
|
|
4,427 |
|
|
— |
Total |
|
$ |
265,020 |
|
$ |
187,209 |
|
$ |
68,235 |
|
$ |
8,486 |
|
$ |
1,090 |
(1) |
Royalties above do not include production taxes which are reported separately on the Condensed Consolidated Statements of Income/(Loss). |
(2) |
U.S. sales of crude oil and natural gas relate primarily to our North Dakota and Marcellus properties, respectively. Canadian crude oil sales relate primarily to our waterflood properties. |
(3) |
Includes third party processing income. |
Enerplus sells the majority of its production pursuant to variable-price contracts. The transaction price for variable priced contracts is based on the commodity price, adjusted for quality, location or other factors, whereby each component of the pricing formula can be either fixed or variable, depending on the contract terms. Under the contracts, the Company is required to deliver a fixed or variable volume of crude oil, natural gas liquids or natural gas to the contract counterparty. Revenue is recognized when a unit of production is delivered to the contract counterparty. The amount of revenue recognized is based on the agreed transaction price, and any variability in revenue relates to the Company’s ability to deliver product. As a result, revenue is allocated to the production delivered in the period.
Crude oil, natural gas and natural gas liquids are sold under contracts of varying terms, including multi-year contracts. Revenues are typically collected in the month following production.
11)GENERAL AND ADMINISTRATIVE EXPENSE
|
|
Three months ended March 31, |
||||
($ thousands) |
|
2018 |
|
2017 | ||
General and administrative expense |
|
$ |
13,205 |
|
$ |
14,271 |
Share-based compensation expense(1) |
|
|
10,019 |
|
|
9,222 |
General and administrative expense |
|
$ |
23,224 |
|
$ |
23,493 |
(1) |
Includes cash and non-cash share-based compensation. |
12)FOREIGN EXCHANGE
|
|
Three months ended March 31, |
||||
($ thousands) |
|
2018 |
|
2017 | ||
Realized: |
|
|
|
|
|
|
Foreign exchange (gain)/loss |
|
$ |
68 |
|
$ |
53 |
Translation of U.S. dollar cash held in Canada (gain)/loss |
|
|
(7,346) |
|
|
— |
Unrealized: |
|
|
|
|
|
|
Translation of U.S. dollar debt and working capital (gain)/loss |
|
|
17,649 |
|
|
(3,911) |
Foreign exchange (gain)/loss |
|
$ |
10,371 |
|
$ |
(3,858) |
ENERPLUS 2018 Q1 REPORT 29
13)INCOME TAXES
|
|
Three months ended March 31, |
||||
($ thousands) |
|
2018 |
|
2017 | ||
Current tax expense/(recovery) |
|
|
|
|
|
|
United States |
|
$ |
66 |
|
$ |
74 |
Deferred tax expense/(recovery) |
|
|
|
|
|
|
Canada |
|
$ |
(5,510) |
|
$ |
13,619 |
United States |
|
|
17,985 |
|
|
15,148 |
|
|
|
12,475 |
|
|
28,767 |
Income tax expense/(recovery) |
|
$ |
12,541 |
|
$ |
28,841 |
The difference between the expected income taxes based on the statutory income tax rate and the effective income taxes for the current and prior period is impacted by the following: expected annual earnings, recognition or reversal of valuation allowance, foreign rate differentials for foreign operations, statutory and other rate differentials, non-taxable portions of capital gains and losses, and non-deductible share-based compensation. Our overall net deferred income tax asset was $566.3 million at March 31, 2018 (December 31, 2017 - $569.9 million).
At March 31, 2018, the Company had a $51.4 million income tax receivable related to the portion of the U.S. Alternative Minimum Tax (“AMT”) refund expected to be realized in 2018 (December 31, 2017 - $50.1 million).
14)SHAREHOLDERS’ EQUITY
a)Share Capital
|
|
Three months ended |
|
Year ended |
||||||
|
|
March 31, 2018 |
|
December 31, 2017 |
||||||
Authorized unlimited number of common shares issued: (thousands) |
|
Shares |
|
|
Amount |
|
Shares |
|
|
Amount |
Balance, beginning of year |
|
242,129 |
|
$ |
3,386,946 |
|
240,483 |
|
$ |
3,365,962 |
|
|
|
|
|
|
|
|
|
|
|
Issued for cash: |
|
|
|
|
|
|
|
|
|
|
Stock Option Plan |
|
105 |
|
|
1,429 |
|
— |
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
Non-cash: |
|
|
|
|
|
|
|
|
|
|
Share-based compensation – settled |
|
2,539 |
|
|
23,389 |
|
1,646 |
|
|
20,984 |
Stock Option Plan - exercised |
|
— |
|
|
114 |
|
— |
|
|
— |
Balance, end of period |
|
244,773 |
|
$ |
3,411,878 |
|
242,129 |
|
$ |
3,386,946 |
Dividends declared to shareholders for the three months ended March 31, 2018 was $7.3 million (2017 - $7.2 million).
b) Share-based Compensation
The following table summarizes Enerplus’ share-based compensation expense, which is included in General and Administrative expense on the Consolidated Statements of Income/(Loss):
|
|
Three months ended March 31, |
||||
($ thousands) |
|
2018 |
|
2017 | ||
Cash: |
|
|
|
|
|
|
Long-term incentive plans expense |
|
$ |
1,946 |
|
$ |
155 |
Non-cash: |
|
|
|
|
|
|
Long-term incentive plans |
|
|
9,079 |
|
|
8,120 |
Equity swap (gain)/loss |
|
|
(1,006) |
|
|
947 |
Share-based compensation expense |
|
$ |
10,019 |
|
$ |
9,222 |
30 ENERPLUS 2018 Q1 REPORT
i)Long-term Incentive (“LTI”) Plans
The following table summarizes the Performance Share Unit (“PSU”), Restricted Share Unit (“RSU”) and Deferred Share Unit (“DSU”) plan activity for the three months ended March 31, 2018:
For the three months ended March 31, 2018 |
|
Cash-settled LTI plans |
|
Equity-settled LTI plans |
|
Total |
||
(thousands of units) |
|
DSU |
|
PSU |
|
RSU |
|
|
Balance, beginning of year |
|
368 |
|
2,713 |
|
2,109 |
|
5,190 |
Granted |
|
76 |
|
1,449 |
|
790 |
|
2,315 |
Vested |
|
— |
|
(1,459) |
|
(1,080) |
|
(2,539) |
Forfeited |
|
— |
|
— |
|
(25) |
|
(25) |
Balance, end of period |
|
444 |
|
2,703 |
|
1,794 |
|
4,941 |
Cash-settled LTI Plans
For the three months ended March 31, 2018, the Company recorded cash share-based compensation expense of $1.9 million (March 31, 2017 - $0.2 million). For the three months ended March 31, 2018, the Company made cash payments of nil related to its cash-settled plans (March 31, 2017 – $0.1 million).
As of March 31, 2018, a liability of $6.4 million (December 31, 2017 - $4.5 million) with respect to the DSU plan has been recorded to Accounts Payable on the Consolidated Balance Sheets.
Equity-settled LTI Plans
For the three months ended March 31, 2018, the Company recorded non-cash share-based compensation expense of $9.1 million (2017 – $8.1 million).
The following table summarizes the cumulative share-based compensation expense recognized to-date which is recorded to Paid-in Capital on the Consolidated Balance Sheets. Unrecognized amounts will be recorded to non-cash share-based compensation expense over the remaining vesting terms.
At March 31, 2018 ($ thousands, except for years) |
|
PSU(1) |
|
RSU |
|
Total |
|||
Cumulative recognized share-based compensation expense |
|
$ |
19,446 |
|
$ |
6,620 |
|
$ |
26,066 |
Unrecognized share-based compensation expense |
|
|
13,896 |
|
|
9,984 |
|
|
23,880 |
Fair value |
|
$ |
33,342 |
|
$ |
16,604 |
|
$ |
49,946 |
Weighted-average remaining contractual term (years) |
|
|
1.9 |
|
|
1.7 |
|
|
|
(1) |
Includes estimated performance multipliers. |
ii)Stock Option Plan
The Company suspended the issuance of stock options in 2014. At March 31, 2018, all stock options are fully vested and any related non-cash share-based compensation expense has been fully recognized.
The following table summarizes the stock option plan activity for the three months ended March 31, 2018:
|
|
Number of Options |
|
Weighted Average |
|
Period ended March 31, 2018 |
|
(thousands) |
|
Exercise Price |
|
Options outstanding, beginning of year |
|
5,486 |
|
$ |
18.25 |
Exercised |
|
(105) |
|
|
13.66 |
Forfeited |
|
(19) |
|
|
22.71 |
Expired |
|
(638) |
|
|
30.20 |
Options outstanding, end of period |
|
4,724 |
|
$ |
16.72 |
Options exercisable, end of period |
|
4,724 |
|
$ |
16.72 |
At March 31, 2018, Enerplus had 4,723,746 options that were exercisable at a weighted average exercise price of $16.72 with a weighted average remaining contractual term of 1.5 years, giving an aggregate intrinsic value of $2.2 million (2017 – 2.3 years and nil). The intrinsic value of options exercised for the three months ended March 31, 2018 was $0.2 million (March 31, 2017 – nil).
ENERPLUS 2018 Q1 REPORT 31
c)Basic and Diluted Net Income/(Loss) Per Share
Net income/(loss) per share has been determined as follows:
|
|
Three months ended March 31, |
||||
(thousands, except per share amounts) |
|
2018 |
|
2017 | ||
Net income/(loss) |
|
$ |
29,637 |
|
$ |
76,293 |
|
|
|
|
|
|
|
Weighted average shares outstanding – Basic |
|
|
243,874 |
|
|
241,285 |
Dilutive impact of share-based compensation |
|
|
5,317 |
|
|
5,073 |
Weighted average shares outstanding – Diluted |
|
|
249,191 |
|
|
246,358 |
Net income/(loss) per share |
|
|
|
|
|
|
Basic |
|
$ |
0.12 |
|
$ |
0.32 |
Diluted |
|
$ |
0.12 |
|
$ |
0.31 |
15)FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
a)Fair Value Measurements
At March 31, 2018, the carrying value of cash, accounts receivable, accounts payable, and dividends payable approximated their fair value due to the short-term maturity of the instruments.
At March 31, 2018, senior notes had a carrying value of $688.4 million and a fair value of $697.1 million (December 31, 2017 - $672.4 million and $687.2 million, respectively).
The fair value of derivative contracts and the senior notes are considered a level 2 fair value measurement. There were no transfers between fair value hierarchy levels during the period.
b)Derivative Financial Instruments
The deferred financial assets and liabilities on the Consolidated Balance Sheets result from recording derivative financial instruments at fair value.
The following table summarizes the change in fair value for the three months ended March 31, 2018 and 2017:
|
|
Three months ended March 31, |
|
|
||||
Gain/(Loss) ($ thousands) |
|
2018 |
|
2017 |
|
Income Statement |
||
Electricity Swaps |
|
$ |
(16) |
|
$ |
(117) |
|
Operating expense |
Equity Swaps |
|
|
1,006 |
|
|
(947) |
|
G&A expense |
Commodity Derivative Instruments: |
|
|
|
|
|
|
|
|
Oil |
|
|
(29,855) |
|
|
44,358 |
|
Commodity derivative |
Gas |
|
|
(757) |
|
|
6,635 |
|
instruments |
Total |
|
$ |
(29,622) |
|
$ |
49,929 |
|
|
The following table summarizes the income statement effects of Enerplus’ commodity derivative instruments:
|
|
Three months ended March 31, |
||||
($ thousands) |
|
2018 |
|
2017 | ||
Change in fair value gain/(loss) |
|
$ |
(30,612) |
|
$ |
50,993 |
Net realized cash gain/(loss) |
|
|
10,148 |
|
|
6,569 |
Commodity derivative instruments gain/(loss) |
|
$ |
(20,464) |
|
$ |
57,562 |
32 ENERPLUS 2018 Q1 REPORT
The following table summarizes the fair values at the respective period ends:
|
|
March 31, 2018 |
|
December 31, 2017 |
||||||||||||||
|
|
Assets |
|
Liabilities |
|
Assets |
|
Liabilities |
||||||||||
($ thousands) |
|
Current |
|
Current |
|
Long-term |
|
Current |
|
Current |
|
Long-term |
||||||
Electricity Swaps |
|
$ |
— |
|
$ |
16 |
|
$ |
— |
|
$ |
— |
|
$ |
— |
|
$ |
— |
Equity Swaps |
|
|
— |
|
|
1,113 |
|
|
— |
|
|
— |
|
|
2,119 |
|
|
— |
Commodity Derivative Instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
1,608 |
|
|
49,024 |
|
|
16,727 |
|
|
2,142 |
|
|
26,523 |
|
|
9,907 |
Gas |
|
|
953 |
|
|
— |
|
|
— |
|
|
1,710 |
|
|
— |
|
|
— |
Total |
|
$ |
2,561 |
|
$ |
50,153 |
|
$ |
16,727 |
|
$ |
3,852 |
|
$ |
28,642 |
|
$ |
9,907 |
c)Risk Management
i)Market Risk
Market risk is comprised of commodity price, foreign exchange, interest rate and equity price risk.
Commodity Price Risk:
Enerplus manages a portion of commodity price risk through a combination of financial derivative and physical delivery sales contracts. Enerplus’ policy is to enter into commodity contracts subject to a maximum of 80% of forecasted production volumes net of royalties and production taxes.
The following tables summarize the Corporation’s price risk management positions at May 2, 2018:
Crude Oil Instruments:
Instrument Type(1) |
|
bbls/day |
|
US$/bbl |
|
|
|
|
|
Apr 1, 2018 – Apr 30, 2018 |
|
|
|
|
WTI Swap |
|
5,000 |
|
55.38 |
WTI Purchased Put |
|
15,000 |
|
52.90 |
WTI Sold Call |
|
15,000 |
|
61.73 |
WTI Sold Put |
|
15,000 |
|
42.92 |
WCS Differential Swap (Sale) |
|
1,500 |
|
(14.75) |
WCS Differential Swap (Purchase) |
|
1,500 |
|
(25.50) |
|
|
|
|
|
May 1, 2018 – May 31, 2018 |
|
|
|
|
WTI Swap |
|
6,000 |
|
57.20 |
WTI Purchased Put |
|
15,000 |
|
52.90 |
WTI Sold Call |
|
15,000 |
|
61.73 |
WTI Sold Put |
|
15,000 |
|
42.92 |
WCS Differential Swap (Sale) |
|
3,000 |
|
(14.46) |
|
|
|
|
|
Jun 1, 2018 – Jun 30, 2018 |
|
|
|
|
WTI Swap |
|
6,000 |
|
57.20 |
WTI Purchased Put |
|
15,000 |
|
52.90 |
WTI Sold Call |
|
15,000 |
|
61.73 |
WTI Sold Put |
|
15,000 |
|
42.92 |
WCS Differential Swap (Sale) |
|
4,000 |
|
(14.62) |
|
|
|
|
|
Jul 1, 2018 – Sep 30, 2018 |
|
|
|
|
WTI Swap |
|
3,000 |
|
53.73 |
WTI Purchased Put |
|
18,000 |
|
52.53 |
WTI Sold Call |
|
18,000 |
|
61.22 |
WTI Sold Put |
|
18,000 |
|
42.71 |
WCS Differential Swap (Sale) |
|
3,000 |
|
(14.46) |
|
|
|
|
|
Oct 1, 2018 – Dec 31, 2018 |
|
|
|
|
WTI Swap |
|
3,000 |
|
53.73 |
WTI Purchased Put |
|
20,000 |
|
52.48 |
WTI Sold Call |
|
20,000 |
|
61.10 |
WTI Sold Put |
|
20,000 |
|
42.74 |
WCS Differential Swap (Sale) |
|
3,000 |
|
(14.46) |
|
|
|
|
|
ENERPLUS 2018 Q1 REPORT 33
Jan 1, 2019 – Mar 31, 2019 |
|
|
|
|
WTI Swap |
|
3,000 |
|
53.73 |
WTI Purchased Put |
|
16,000 |
|
53.69 |
WTI Sold Call |
|
16,000 |
|
63.44 |
WTI Sold Put |
|
16,000 |
|
44.05 |
WCS Differential Swap (Sale) |
|
1,500 |
|
(14.17) |
|
|
|
|
|
Apr 1, 2019 – Jun 30, 2019 |
|
|
|
|
WTI Purchased Put |
|
22,000 |
|
54.17 |
WTI Sold Call |
|
22,000 |
|
64.85 |
WTI Sold Put |
|
22,000 |
|
44.26 |
|
|
|
|
|
Jul 1, 2019 – Sep 30, 2019 |
|
|
|
|
WTI Purchased Put |
|
22,000 |
|
54.17 |
WTI Sold Call |
|
22,000 |
|
64.80 |
WTI Sold Put |
|
22,000 |
|
44.26 |
|
|
|
|
|
Oct 1, 2019 – Dec 31, 2019 |
|
|
|
|
WTI Purchased Put |
|
22,000 |
|
54.17 |
WTI Sold Call |
|
22,000 |
|
64.85 |
WTI Sold Put |
|
22,000 |
|
44.26 |
|
|
|
|
|
Jan 1, 2020 – Dec 31, 2020 |
|
|
|
|
WTI Purchased Put |
|
6,000 |
|
56.00 |
WTI Sold Call |
|
6,000 |
|
70.33 |
WTI Sold Put |
|
6,000 |
|
46.67 |
(1) |
Transactions with a common term have been aggregated and presented at a weighted average price/bbl. |
Natural Gas Instruments:
Instrument Type(1) |
|
MMcf/day |
|
US$/Mcf |
|
|
|
|
|
Apr 1, 2018 – Oct 31, 2018 |
|
|
|
|
NYMEX Purchased Put |
|
40.0 |
|
2.75 |
NYMEX Sold Call |
|
40.0 |
|
3.38 |
|
|
|
|
|
Nov 1, 2018 – Dec 31, 2018 |
|
|
|
|
NYMEX Purchased Put |
|
30.0 |
|
2.75 |
NYMEX Sold Call |
|
30.0 |
|
3.47 |
(1) |
Transactions with a common term have been aggregated and presented at a weighted average price/Mcf. |
Electricity Instruments:
Instrument Type |
|
MWh |
|
CDN$/Mwh |
|
|
|
|
|
Apr 1, 2018 – Apr 30, 2018 |
|
|
|
|
AESO Power Swap(1) |
|
3.0 |
|
59.25 |
|
|
|
|
|
May 1, 2018 – Jun 30, 2018 |
|
|
|
|
AESO Power Swap(1) |
|
5.0 |
|
57.55 |
|
|
|
|
|
Jul 1, 2018 – Aug 30, 2018 |
|
|
|
|
AESO Power Swap(1) |
|
2.0 |
|
55.00 |
(1) |
Alberta Electrical System Operator (“AESO”) fixed pricing. |
Foreign Exchange Risk:
Enerplus is exposed to foreign exchange risk in relation to its U.S. operations, U.S. dollar denominated senior notes, cash deposits and working capital. Additionally, Enerplus’ crude oil sales and a portion of its natural gas sales are based on U.S. dollar indices. To mitigate exposure to fluctuations in foreign exchange, Enerplus may enter into foreign exchange derivatives. At March 31, 2018, Enerplus did not have any foreign exchange derivatives outstanding.
Interest Rate Risk:
As of March 31, 2018, all of Enerplus’ debt was based on fixed interest rates, and Enerplus had no interest rate derivatives outstanding.
34 ENERPLUS 2018 Q1 REPORT
Equity Price Risk:
Enerplus is exposed to equity price risk in relation to its long-term incentive plans detailed in Note 14. Enerplus has entered into various equity swaps maturing 2018 and has effectively fixed the future settlement cost on 470,000 shares at weighted average price of $16.89 per share.
ii)Credit Risk
Credit risk represents the financial loss Enerplus would experience due to the potential non-performance of counterparties to its financial instruments. Enerplus is exposed to credit risk mainly through its joint venture, marketing and financial counterparty receivables.
Enerplus mitigates credit risk through credit management techniques including conducting financial assessments to establish and monitor counterparties’ credit worthiness, setting exposure limits, monitoring exposures against these limits and obtaining financial assurances such as letters of credit, parental guarantees or third party credit insurance where warranted. Enerplus monitors and manages its concentration of counterparty credit risk on an ongoing basis.
Enerplus’ maximum credit exposure at the balance sheet date consists of the carrying amount of its non-derivative financial assets and the fair value of its derivative financial assets. At March 31, 2018, approximately 87% of Enerplus’ marketing receivables were with companies considered investment grade.
Enerplus actively monitors past due accounts and takes the necessary actions to expedite collection, which can include withholding production, netting amounts of future payments or seeking other remedies including legal action. Should Enerplus determine that the ultimate collection of a receivable is in doubt, it will provide the necessary provision in its allowance for doubtful accounts with a corresponding charge to earnings. If Enerplus subsequently determines an account is uncollectable the account is written off with a corresponding charge to the allowance account. Enerplus’ allowance for doubtful accounts balance at March 31, 2018 was $3.5 million (December 31, 2017 - $3.5 million).
iii)Liquidity Risk & Capital Management
Liquidity risk represents the risk that Enerplus will be unable to meet its financial obligations as they become due. Enerplus mitigates liquidity risk through actively managing its capital, which it defines as debt (net of cash and restricted cash) and shareholders’ capital. Enerplus’ objective is to provide adequate short and long term liquidity while maintaining a flexible capital structure to sustain the future development of its business. Enerplus strives to balance the portion of debt and equity in its capital structure given its current oil and natural gas assets and planned investment opportunities.
Management monitors a number of key variables with respect to its capital structure, including debt levels, capital spending plans, dividends, access to capital markets, and acquisition and divestment activity.
At March 31, 2018, Enerplus was in full compliance with all covenants under the bank credit facility and outstanding senior notes.
16) CONTINGENCIES
Enerplus is subject to various legal claims and actions arising in the normal course of business. Although the outcome of such claims and actions cannot be predicted with certainty, the Company does not expect these matters to have a material impact on the Consolidated Financial Statements. In instances where the Company determines that a loss is probable and the amount can be reasonably estimated, an accrual is recorded.
17)SUPPLEMENTAL CASH FLOW INFORMATION
a)Changes in Non-Cash Operating Working Capital
|
|
Three months ended March 31, |
||||
($ thousands) |
|
2018 |
|
2017 | ||
Accounts receivable |
|
$ |
(6,637) |
|
$ |
21,672 |
Other current assets |
|
|
1,621 |
|
|
(4,311) |
Accounts payable |
|
|
12,485 |
|
|
(6,817) |
|
|
$ |
7,469 |
|
$ |
10,544 |
ENERPLUS 2018 Q1 REPORT 35
b)Changes in Other Non-Cash Working Capital
|
|
Three months ended March 31, |
||||
($ thousands) |
|
2018 |
|
2017 | ||
Non-cash financing activities(1) |
|
$ |
26 |
|
$ |
16 |
Non-cash investing activities(2) |
|
|
44,660 |
|
|
26,322 |
(1) |
Relates to changes in dividends payable and included in dividends on the Consolidated Statements of Cash Flows. |
(2) |
Relates to changes in accounts payable for capital and office expenditures and included in capital and office expenditures on the Consolidated Statements of Cash Flows. |
c)Other
|
|
Three months ended March 31, |
||||
($ thousands) |
|
2018 |
|
2017 | ||
Income taxes paid/(received) |
|
$ |
(85) |
|
$ |
65 |
Interest paid |
|
|
3,256 |
|
|
3,644 |
36 ENERPLUS 2018 Q1 REPORT
Exhibit 99.3
FORM 52‑109F2
CERTIFICATION OF INTERIM FILINGS
FULL CERTIFICATE
I, Ian C. Dundas, President and Chief Executive Officer of Enerplus Corporation, certify the following:
1.Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Enerplus Corporation (the “issuer”) for the interim period ended March 31, 2018.
2.No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.
3.Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.
4.Responsibility: The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52‑109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.
5.Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer and I have, as at the end of the period covered by the interim filings
(a)designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that
(i)material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and
(ii)information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and
(b)designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.
5.1Control framework: The control framework the issuer’s other certifying officer and I used to design the issuer’s ICFR is Internal Control — Integrated Framework (2013 Framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
5.2ICFR — material weakness relating to design: N/A
5.3Limitation on scope of design: N/A
6.Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on January 1, 2018 and ended on March 31, 2018 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.
Date: May 3, 2018
/s/ Ian C. Dundas |
|
Ian C. Dundas |
|
Exhibit 99.4
FORM 52‑109F2
CERTIFICATION OF INTERIM FILINGS
FULL CERTIFICATE
I, Jodine J. Jenson Labrie, Senior Vice President and Chief Financial Officer of Enerplus Corporation, certify the following:
1.Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Enerplus Corporation (the “issuer”) for the interim period ended March 31, 2018.
2.No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.
3.Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.
4.Responsibility: The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52‑109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.
5.Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer and I have, as at the end of the period covered by the interim filings
(a)designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that
(i)material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and
(ii)information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and
(b)designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.
5.1Control framework: The control framework the issuer’s other certifying officer and I used to design the issuer’s ICFR is Internal Control — Integrated Framework (2013 Framework) issued by The Committee of Sponsoring Organizations of the Treadway Commission.
5.2ICFR — material weakness relating to design: N/A
5.3Limitation on scope of design: N/A
6.Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on January 1, 2018 and ended on March 31, 2018 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.
Date: May 3, 2018
/s/ Jodine J. Jenson Labrie |
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Jodine J. Jenson Labrie |
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