ERF Enerplus Corporation

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 NOVEMBER, 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 Third Quarter ended September  30, 2018

EXHIBIT 99.2 — Unaudited Consolidated Financial Statements for the Third Quarter ended September  30, 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.

DATE: November 9, 2018

Exhibit 99.1

MANAGEMENT’S DISCUSSION AND ANALYSIS (“MD&A”)       

The following discussion and analysis of financial results is dated November 8, 2018 and is to be read in conjunction with:

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 thereto have been prepared in accordance with U.S. GAAP, including the prior period comparatives. All amounts are stated in Canadian dollars unless otherwise specified and all note references relate to the notes included in the Interim Financial Statements. Certain prior period amounts have been 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.  

OVERVIEW

Production for the third quarter averaged 96,861 BOE/day, a 4% increase compared to the second quarter of 2018. Our crude oil and natural gas liquids production increased by 7% to 53,430 bbls/day from 50,050 bbls/day in the second quarter of 2018. The increase in production is primarily due to strong well performance in North Dakota with 18.1 net wells coming on-stream during the third quarter as well as 3.2 net wells coming on-stream in Colorado. As a result, we are revising our average annual production guidance range to 92,500 – 93,000 BOE/day, the high end of our previous range of 91,000 – 93,000 BOE/day. We are also revising our average annual crude oil and liquids guidance range to 49,500 – 50,000 bbls/day, the high end of our previous range of 49,000 – 50,000 bbls/day and guiding to a fourth quarter average crude oil and liquids production range of 53,500 – 54,500 bbls/day.

Capital expenditures totaled $193.3 million for the third quarter and $521.8 million year to date, in line with our expectations. Approximately 75% of our capital spending year to date has been directed to our North Dakota crude oil properties. We are maintaining our annual capital spending guidance of $585 million. Capital activity for the remainder of the year will be largely focused on drilling in North Dakota in preparation for the 2019 program. 

Operating costs for the quarter decreased to $6.81/BOE from $7.20/BOE in the second quarter, primarily due to our North Dakota operations where we saw reduced well service activity and lower gas handling costs in the third quarter. We are maintaining our annual operating cost guidance of $7.00/BOE.

Cash G&A expenses for the third quarter were $1.35/BOE, a decrease of 6% from $1.44/BOE in the second quarter of 2018. Cash G&A expenses per BOE decreased from the second quarter with higher production during the period. We are lowering our annual guidance target for cash G&A expenses to $1.50/BOE from $1.55/BOE.

As of October 30, 2018, we had approximately 68% of our forecasted crude oil production, net of royalties, hedged for the remainder of 2018, and approximately 68% and 47% of our crude oil production, net of royalties, hedged in 2019 and 2020, respectively, based on 2018 forecasted net production. We have also hedged approximately 17% of our forecasted natural gas production, net of royalties, for the remainder of 2018.  In addition, we have physical sales contracts in place in the Bakken for 20,250 bbls/day of production at an average differential of US$2.53/bbl below WTI for the fourth quarter of 2018, and on 16,000 bbls/day of production in 2019 averaging approximately US$3.00/bbl below WTI. 

We recorded net income of $86.9 million and adjusted funds flow of $210.4 million in the third quarter of 2018, compared to $12.4 million and $173.7 million, respectively, in the second quarter of 2018. Net income in the third quarter increased with higher realized commodity prices and production, as well as lower non-cash mark-to-market losses recorded on our commodity derivative instruments.

During the quarter, we repurchased and cancelled 544,300 common shares under our Normal Course Issuer Bid (“NCIB”).

At September 30, 2018, our total debt net of cash was $313.6 million and our net debt to adjusted funds flow ratio was 0.4x.   

RESULTS OF OPERATIONS

Production

Average daily production for the third quarter totaled 96,861 BOE/day, an increase of 3,978 BOE/day or 4% compared to the second quarter of 2018. Crude oil and natural gas liquids production increased by 7%, primarily due to our successful capital program focused on our U.S. crude oil properties. Natural gas production also increased in the period with less downtime and pipeline maintenance in the Marcellus when compared to the second quarter.

For the three and nine months ended September 30, 2018, crude oil and liquids production increased by 14,504 bbls/day or 37% and 9,618 bbls/day or 25%, respectively, compared to the same periods in 2017. Production increased primarily due to higher spending in North Dakota where 34.3 net wells have been brought on-stream year to date. Natural gas production increased by 8% for the three months ended September 30, 2018 compared to the same period in 2017 with increased activity in the Marcellus as a result of stronger realized prices and additional pipeline capacity coming on-stream in the basin. For the nine-month period ending September 30, 2018, natural gas production decreased by 3% due to non-core Canadian asset divestments in 2017.

Our crude oil and natural gas liquids weighting increased to 55% in the third quarter of 2018, from 49% for the same period of 2017, as a result of growth from our North Dakota crude oil assets in 2018 and the divestment of non-core Canadian natural gas weighted properties in 2017.

Average daily production volumes for the three and nine months ended September 30, 2018 and 2017 are outlined below:

We are revising our average annual production guidance range to 92,500 – 93,000 BOE/day, the high end of our previous range of 91,000 – 93,000 BOE/day. We are also revising our average annual crude oil and liquids guidance range to 49,500 – 50,000 bbls/day, the high end of our previous range of 49,000 – 50,000 bbls/day, and guiding to a fourth quarter average crude oil and liquids production range of 53,500 – 54,500 bbls/day.

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 quarterly average prices for the nine months ended September 30, 2018 and 2017 and other periods indicated:

(1)Excluding transportation costs, royalties and the effects of commodity derivative instruments.

(2)Based on a weighted average differential for the period.

CRUDE OIL AND NATURAL GAS LIQUIDS

Our average realized crude oil price during the third quarter of 2018 increased by 5%, compared to the second quarter of 2018, averaging $83.98/bbl.  Crude oil prices were volatile during the third quarter, however, benchmark WTI crude oil prices increased by 2%. The volatility was largely related to concerns over trade conflict and supply uncertainty, due to ongoing geopolitical issues and growth in U.S. production. Continued strength in Bakken differentials offset lower prices realized for our Canadian crude oil production during the quarter.     

Our realized Bakken price differential improved by 26% during the quarter to average US$2.54/bbl below WTI and averaged US$3.03/bbl below WTI year to date. Subsequent to the quarter, a significant amount of Midwest U.S. refining capacity was taken off-line for scheduled seasonal maintenance. This resulted in weaker Bakken prices contracted for November and December versus previous months. We have physical sales contracts in place for approximately 20,250 bbls/day of Bakken crude oil production at an average differential of US$2.53/bbl below WTI for the fourth quarter that is expected to provide some protection from this short-term seasonal weakness in pricing. As a result of the weaker differentials in the fourth quarter, we are revising our full year Bakken differential guidance to average approximately US$3.80/bbl below WTI. For 2019, we have physical sales contracts in place for approximately 16,000 bbls/day of Bakken crude oil production with fixed differentials averaging approximately US$3.00/bbl below WTI.

Our realized price differential for our Canadian crude oil production widened by US$0.30/bbl compared to the second quarter of 2018. Canadian crude oil prices weakened significantly late in the third quarter as seasonal U.S. refinery maintenance and growing Canadian crude oil production placed constraints on Canadian pipeline capacity and increased demand for rail to transport production out of the region. We have fixed differential hedges in place for 3,000 bbl/day of our Canadian heavy crude oil production at an average differential of US$14.46/bbl below WTI for the remainder of 2018, which is expected to continue to provide some protection against this price weakness.

Our realized price for natural gas liquids averaged $25.95/bbl during the period, which represents a 19% decrease compared to the previous quarter, due to lower condensate prices in both the U.S. and Canada.

NATURAL GAS

Our average realized natural gas price during the third quarter of 2018 increased by 20% compared to the second quarter of 2018, to average $3.22/Mcf. The increase was mainly due to continued improvement in Marcellus in basin prices. Our realized Marcellus sales differential, excluding transportation and gathering costs, averaged US$0.48/Mcf below NYMEX for the period. Strong demand for seasonal power generation resulted in lower than expected storage balances in the U.S., especially in the Northeastern region, which resulted in improved differentials. Further, basis differentials in the Marcellus continued to improve subsequent to the quarter as two new pipeline projects representing 2.7 Bcf/day of additional pipeline capacity were brought into service in early October. We are maintaining our full year differential guidance for the Marcellus of US$0.40/Mcf below NYMEX.

Benchmark AECO gas prices continue to remain weak during the third quarter of 2018 due to transportation constraints out of the basin. Our realized Canadian natural gas price differential averaged US$0.77/Mcf below NYMEX. We continue to benefit from our AECO/NYMEX physical sales contracts, which have an average fixed basis differential of US$0.63/Mcf below NYMEX.

FOREIGN EXCHANGE

Our oil and natural gas sales are impacted by foreign exchange fluctuations as the majority of our sales are based on U.S. dollar denominated benchmark indices. A stronger Canadian dollar decreases the amount of our realized sales, as well as the amount of our U.S. denominated costs, such as capital, interest on our U.S. denominated debt, and the value of our outstanding U.S. senior notes. 

The Canadian dollar was stronger during the first nine months with an average exchange rate of 1.29 USD/CDN compared to 1.31 USD/CDN for the same period in 2017. However, when comparing the exchange rate in the third quarter of 2018 to the second quarter, the Canadian dollar weakened relative to the U.S. dollar. This was due to concerns related to the impact of the ongoing North American Free Trade Agreement (“NAFTA”) negotiations, other U.S. policies related to trade, as well as interest rates in Canada and the U.S. that influenced the foreign exchange rate.    

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 October 30, 2018, we have hedged approximately 23,000 bbls/day of our expected crude oil production for the remainder of 2018, which represents approximately 68% of our forecasted crude oil production, after royalties. For 2019, we are hedged on 23,140 bbls/day, which represents approximately 68% of our 2018 forecasted crude oil production, after royalties.  For 2020, we have hedged 16,000 bbls/day, which represents 47% 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 October 30,  2018, we have hedged approximately 33,370 Mcf/day of our forecasted natural gas production for the remainder of 2018. This represents approximately 17% of our forecasted natural gas production, after royalties.

The following is a summary of our financial contracts in place at October 30, 2018, expressed as a percentage of our forecasted 2018 net production volumes:

ACCOUNTING FOR PRICE RISK MANAGEMENT

During the third quarter of 2018, we realized cash losses of $24.3 million on our crude oil contracts and cash gains of $0.4 million on our natural gas contracts. In comparison, during the third quarter of 2017, we realized cash gains of $2.9 million on our crude oil contracts. Cash losses on our crude oil contracts were primarily due to crude oil prices rising above the swap level and the sold call strike price on our three way collar hedge positions.

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 third quarter of 2018, the fair value of our crude oil contracts was in a net liability position of $165.0 million, and the fair value of our natural gas contracts was nil. For the three and nine months ended September 30, 2018, the change in the fair value of our crude oil contracts represented losses of $30.0 million and $130.8 million, respectively, and our natural gas contracts represented losses of $0.2 million and $1.7 million, respectively.

Revenues

Oil and natural gas sales, net of royalties for the three and nine months ended September 30, 2018, were $373.6 million and $966.0 million, respectively, an increase of 91% and 49% from the same periods in 2017. The increase in revenue was a result of the improvement in crude oil and natural gas prices in the period, along with higher production when compared to the prior year.

Royalties and Production Taxes

Royalties are paid to government entities, land owners and mineral rights owners. Production taxes include state production taxes, Pennsylvania impact fees and freehold mineral taxes. A large percentage of our production is from U.S. properties where royalty rates are generally higher than in Canada and less sensitive to commodity price levels. During the three and nine months ended September 30, 2018, royalties and production taxes increased to $119.4 million and $301.2 million, respectively, from $58.1 million and $188.6 million for the same periods in 2017 primarily due to higher U.S. crude oil sales.

We are maintaining our annual average royalty and production tax rate guidance of 25% for 2018.

Operating Expenses

(1)Non-cash (gains)/losses on fixed price electricity swaps.

For the three and nine months ended September 30, 2018, operating expenses were $60.7 million ($6.81/BOE) and $175.3 million ($7.01/BOE) respectively, compared to our annual guidance of $7.00/BOE. Operating costs increased from $48.8 million ($6.71/BOE) and $145.0 million ($6.37/BOE), respectively, when compared to the same periods in 2017. The increases were due to a higher weighting of crude oil and liquids production, as well as higher repairs and maintenance and water handling rates.

We are maintaining our annual operating cost guidance of $7.00/BOE. 

Transportation Costs

For the three and nine months ended September 30, 2018, transportation costs were $33.0 million ($3.70/BOE) and $90.1 million ($3.60/BOE) respectively, compared to our annual guidance of $3.60/BOE. During the same periods in 2017, transportation costs were $26.3 million ($3.61/BOE) and $85.1 million ($3.74/BOE), respectively. The increase in costs on a per BOE basis for the three months ended September 30, 2018 was due to a weakening Canadian dollar when compared to the prior period. The decrease in costs on a per BOE basis for the nine months ended September 30, 2018 resulted from increased North Dakota natural gas and natural gas liquids production in the U.S. with minimal associated transportation costs. 

We are maintaining our annual guidance for transportation costs of $3.60/BOE.

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.

(1)See “Non-GAAP Measures” in this MD&A.

Crude oil netbacks before hedging for the three and nine months ended September 30, 2018 were higher compared to the same periods in 2017 primarily due to higher production and improved realized prices. For the three and nine months ended September 30, 2018, our crude oil properties accounted for 89% and 87% of our netback before hedging, respectively, compared to 85% and 75% for the three and nine-month periods ended 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.

For the three and nine months ended September 30, 2018, cash G&A expenses were $12.0 million ($1.35/BOE) and $37.3 million ($1.49/BOE), respectively, compared to $11.7 million ($1.61/BOE) and $37.9 million ($1.67/BOE) for the same periods in 2017. Cash G&A expenses were essentially flat but decreased on a per BOE basis for the three and nine months ended September 30, 2018 compared to the same periods in 2017, due to higher production. 

During the third quarter of 2018, we reported a cash SBC recovery of $0.2 million due to the decrease in our share price on outstanding deferred share units. We recorded non-cash SBC of $4.3 million or $0.48/BOE in the third quarter of 2018, which is consistent with an expense of $4.1 million or $0.57/BOE during the same period in 2017.

We have hedges in place on a portion of the outstanding cash-settled grants under our LTI plans. In the third quarter we recorded a non-cash mark-to-market loss of $0.2 million on these hedges due to the decrease in our share price. We had 195,000 units outstanding, hedged at a weighted average price of $20.60 per share at September 30, 2018.

We are lowering our annual cash G&A guidance to $1.50/BOE from $1.55/BOE due to higher annual average production.  

Interest Expense

For the three and nine months ended September 30, 2018, we recorded total interest expense of $8.6 million and $27.0 million, respectively, compared to $8.7 million and $29.0 million for the same periods in 2017. The decrease in interest expense for the nine months ended September 30, 2018 compared to the same period in 2017 was primarily due to the repayment of a portion of our 2009 senior notes which carry a higher coupon rate, along with the impact of a strengthening Canadian dollar on our U.S. dollar denominated interest expense.

At September 30, 2018, we were undrawn on our $800 million bank credit facility and our debt balance consisted of fixed interest rates, with a weighted average interest rate of 4.8%. See Note 8 to the Interim Financial Statements for further details.

Foreign Exchange