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, 2016

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, 2016

EXHIBIT 99.2 — Unaudited Consolidated Financial Statements for the Third Quarter ended September 30, 2016

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 14, 2016

Exhibit 99.1

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

The following discussion and analysis of financial results is dated November 10, 2016 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 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. 

Where applicable, natural gas has been converted to barrels of oil equivalent (“BOE”) based on 6 Mcf:1 BOE and oil and natural gas liquids (“NGL”) have been converted to thousand cubic feet of gas equivalent (“Mcfe”) based on 0.167 bbl:1 Mcfe. 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 peers. 

OVERVIEW

During the third quarter, we continued to improve our profitability through further cost reductions and strong operational results. Based on the success of our ongoing asset divestment program and our second quarter equity issue, we have a strong balance sheet and are repositioned for growth in 2017.

Average daily production for the third quarter was 92,077 BOE/day, compared to our annual average production guidance range of 92,000 – 94,000 BOE/day. Production decreased 2% from the second quarter largely due to the June 2016 sale of non-core Canadian properties with production of approximately 2,300 BOE/day. The decrease in Canadian volumes was offset by strong performance in the U.S., where production increased 3% compared to the second quarter. We are reaffirming our 2016 annual average production guidance of 93,000 BOE/day, the mid-point of our previous guidance range, with approximately 43,000 – 44,000 bbls/day of crude oil and natural gas liquids.

Our capital spending for the third quarter was $60.3 million, or $151.7 million year to date, with the majority directed to our North Dakota crude oil properties. We are maintaining our 2016 annual capital spending guidance of $215 million.    

Operating expenses for the third quarter came in below guidance of $7.90/BOE, totaling $56.2 million or $6.64/BOE. The decrease in operating costs was mainly due to continued improvement in cost structures, reduced activity levels and the ongoing divestment of higher cost Canadian properties. As a result, we are reducing our annual guidance for operating expenses to $7.50/BOE from $7.90/BOE. Cash G&A expenses were also below guidance, totaling $13.4 million or $1.58/BOE compared to guidance of $1.95/BOE, primarily due to the continued reduction in staff levels and ongoing cost saving efforts. Accordingly, we are revising our annual cash G&A expense guidance to $1.80/BOE from $1.95/BOE.

Our commodity hedging program continued to provide funds flow protection, contributing cash gains of $10.0 million in the third quarter.  Since the second quarter, we have increased our downside protection. As of November 1, 2016, we have approximately 56% of our forecasted crude oil production, net of royalties, hedged in 2017 and approximately 12% of our forecasted net crude oil production hedged in 2018 and the first quarter of 2019.  We have also hedged approximately 22% of our forecasted natural gas production, net of royalties, in 2017.

We recorded funds flow of $80.1 million and a net loss of $100.7 million for the quarter. Third quarter earnings were impacted by a non-cash impairment charge of $61.0 million and a non-cash valuation allowance on our deferred tax asset as a result of the decline in the twelve month trailing average commodity prices.

Our asset divestment program and proceeds from our second quarter equity issuance have allowed us to reduce our debt levels by 46% year to date, strengthening our balance sheet and improving our financial flexibility. Subsequent to the quarter, we entered into an agreement to acquire a Canadian waterflood property with current production of approximately 3,800 BOE/day, which we expect to close in November, for consideration of approximately $110 million, net of anticipated closing adjustments.

2017 PRELIMINARY OUTLOOK

As a result of our improving cost structures and strong capital efficiencies, we plan to accelerate our crude oil growth in 2017 with a capital spending program of approximately $400 million. The majority of our capital spending will be focused on our North Dakota crude oil properties, where we have secured a second drilling rig commencing operations in January 2017.  We expect this capital spending to result in meaningful liquids growth, with a 15% increase in crude oil and liquids volumes from the fourth quarter of 2016 to the fourth quarter of 2017, and a 25% increase in North Dakota production over the same period. At US$50/bbl WTI and US$3.00/Mcf NYMEX,  we expect our capital spending program and dividends to be approximately balanced with internally generated cash flow. Based on the expected increase in liquids production, we estimate our 2017 operating expenses will be approximately $8.00/BOE. 

We expect to provide further details of our 2017 guidance in late 2016.

RESULTS OF OPERATIONS

Production

Average daily production for the third quarter totaled 92,077 BOE/day, in line with our expectations. Compared to production in the second quarter of 2016 of 93,659 BOE/day, production decreased 2% primarily due to the June 2016 sale of non-core Canadian assets with production of approximately 2,300 BOE/day. Lower Canadian volumes were offset by higher U.S. production, which increased 3% as a result of strong performance in Marcellus and North Dakota.

Production in the third quarter of 2016 decreased 17% from production levels of 110,794 BOE/day in the same period of 2015 primarily due to the sale of non-core properties from the fourth quarter of 2015 to date in 2016 with production of approximately 11,800 BOE/day. Natural gas production decreased 68,195 Mcf/day or 19% compared to the third quarter of 2015, with a 48% decrease in Canadian natural gas volumes due to divestments, price related shut-ins and decline due to lower overall spending. This reduction was offset by strong Marcellus production, which decreased only 2% despite lower capital spending. Crude oil and liquids production decreased 15% over the same period primarily due to fewer wells coming on-stream in North Dakota during the third quarter of 2016 compared to the same period in 2015, as well as divestments and lower capital spending in 2016.  

Our crude oil and natural gas liquids production accounted for 46% of our total average daily production in the third quarter of 2016 compared to 45% in the same period of 2015 as a significant portion of divestments were non-core Canadian natural gas assets.

Average daily production volumes for the three and nine months ended September 30, 2016 and 2015 are outlined below:

We are reaffirming our annual average production guidance of 93,000 BOE/day, the mid-point of our previous guidance range of 92,000 – 94,000 BOE/day.  We are revising our crude oil and natural gas liquids production guidance to 43,000 – 44,000 bbls/day, from 43,000 – 45,000 bbls/day, primarily due to weather related delays to completions activity in North Dakota. We continue to expect fourth quarter production of 89,000 BOE/day. Volumes in the fourth quarter are expected to be impacted by approximately 1,500 BOE/day of curtailed production in the Marcellus due to low natural gas prices and a 1,000 BOE/day decrease in Canadian gas production as a result of price related shut-ins and minor third quarter asset divestments. These reductions are expected to be offset by strong North Dakota production and the Canadian waterflood acquisition, with a projected closing date of November 2016.

Pricing

The prices received for our crude oil and natural gas production directly impact our earnings, funds flow and financial condition. The following table compares average prices for the nine months ended September 30, 2016 and 2015 and quarterly average prices for other periods indicated:

(1)Before transportation costs, royalties and commodity derivative instruments.

CRUDE OIL AND NATURAL GAS LIQUIDS

Our average realized crude oil price during the period was $47.93/bbl, an increase of 3% compared to the prior quarter despite the benchmark WTI price declining slightly. This was due primarily to the continued narrowing of the differentials for our U.S. crude oil production. Declining regional production and strong local refinery demand resulted in our Bakken differential improving by 22% quarter over quarter to average US$6.39/bbl below WTI for the third quarter.  Canadian crude oil prices and differentials were essentially flat compared to the second quarter. Our third quarter realized natural gas liquids price fell by 12% compared to the second quarter, in-line with the changes in benchmark liquids prices over the same period.

NATURAL GAS

Our average realized natural gas price during the third quarter was $2.12/Mcf, 42% higher when compared to the prior quarter due to much stronger U.S. and Canadian benchmark prices but offset slightly by seasonally weaker Marcellus differentials. NYMEX and AECO monthly natural gas prices in the quarter improved by 44% and 76%, respectively compared to the previous quarter as very warm weather in the U.S. increased gas demand at a time when U.S. gas production continued to decline.

A significant portion of our Canadian gas production is sold under fixed AECO basis differential contracts.  In the third quarter our realized Canadian gas price differential was 7% wider than in the second quarter, averaging US$0.92/Mcf below NYMEX, however the AECO monthly differential benchmark price widened by 14% over the same period.

As expected, our third quarter realized Marcellus sales price differential was weaker than the previous quarter, averaging US$1.19/Mcf below NYMEX or 57% wider than the second quarter. This was due to high regional storage inventories combined with unplanned pipeline restrictions. In August, we began transporting an incremental 15% of our Marcellus production out of the region to markets in the southern United States. This long-term firm transportation commitment allows us to access a market that trades closer to the NYMEX price. We estimate this pipeline capacity has improved our overall Marcellus realized price differential by approximately US$0.13/Mcf since the beginning of August.

FOREIGN EXCHANGE

The USD/CDN exchange rate was 1.31 USD/CDN at September 30, 2016, and averaged 1.31 USD/CDN during the third quarter compared to 1.29 USD/CDN during the second quarter. The majority of our oil and natural gas sales are based on U.S. dollar denominated indices, and a weaker Canadian dollar relative to the U.S. dollar increases the amount of our realized sales. Because we report in Canadian dollars, the fluctuations in the Canadian dollar also impact our U.S. dollar denominated costs, capital spending and the reported value of our U.S. dollar denominated debt.

Price Risk Management

We have a price risk management program that considers our overall financial position, the economics of our capital program and potential acquisitions.  Since our second quarter, we have added additional floor protection on a portion of our oil and natural gas production extending to the first quarter of 2019 using both three way collars and swaps.

As of November 1, 2016, we have hedged approximately 13,300 bbls/day of our expected crude oil production for the remainder of 2016, which represents approximately 43% of our forecasted 2016 net crude oil production, after royalties.  For 2017, we have hedged 17,500 bbls/day, which represents approximately 56% of our forecasted net crude oil production, after royalties. We have also added hedges for 2018 and the first quarter of 2019 to protect the economics of a portion of our capital program.  When WTI prices settle below the sold put strike price in any given month, the three way collars provide protection above the WTI index prices 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 November 1, 2016, we have hedged approximately 50,000 Mcf/day of our forecasted natural gas production for the remainder of 2016. This represents approximately 26% of our forecasted natural gas production, after royalties. For 2017, we have hedged 50,000 Mcf/day, which represents approximately 22% of our forecasted net natural gas production, using three way collars. When NYMEX prices settle below the sold put strike price in any given month, the three way collars provide protection above the NYMEX index price equal to the difference between the strike price of the purchased and sold puts.

The following is a summary of our financial contracts in place at November 1, 2016, expressed as a percentage of our anticipated net production volumes:

ACCOUNTING FOR PRICE RISK MANAGEMENT

During the third quarter of 2016 we realized cash gains of $11.1 million on our crude oil contracts and cash losses of $1.1 million on our natural gas contracts. In comparison, during the third quarter of 2015 we realized cash gains of $36.6 million on our crude oil contracts and $17.5 million on our natural gas contracts. The cash gains were due to contracts which provided floor protection above market prices, while cash losses were a result of prices rising above our fixed swap positions.

As the forward markets for crude oil and natural gas fluctuate and new contracts are executed and 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 2016, the fair value of our crude oil contracts was in a net gain position of $7.3 million, while the fair value of our natural gas contracts was in a net loss position of $3.4 million. For the three and nine months ended September 30, 2016, the change in the fair value of our crude oil contracts resulted in losses of $1.7 million and $60.1 million, respectively, and our natural gas contracts resulted in gains of $3.8 million and losses of $7.4 million, respectively.

Revenues

Oil and natural gas sales for the three and nine months ended September 30, 2016 were $230.4 million and $613.6 million, respectively, a decrease of 16% and 25% from the same periods in 2015. The decrease in revenue during the third quarter was primarily a result of lower production volumes compared to the same period in 2015, while the nine month period was impacted by both a decrease in production and lower oil and natural gas prices compared to the same period in 2015.

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, 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 and nine months ended September 30, 2016, royalties and production taxes decreased to $52.5 million and $134.7 million, respectively, from $61.3 million and $172.1 million for the same periods in 2015, primarily due to lower production volumes, along with lower prices over the nine month period. Royalties and production taxes averaged 22% of oil and natural gas sales before transportation costs in the first nine months of 2016 compared to 21% for the same period in 2015 due to a greater portion of our production coming from our U.S. properties, which have an average combined royalty and production tax rate of approximately 25%.

We continue to expect an average royalty and production tax rate of 22% in 2016. We do not expect the Alberta modernized royalty framework to have a significant impact on our Canadian royalties.

Operating Expenses

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

For the three and nine months ended September 30, 2016, operating expenses were $56.2 million and $189.4 million, respectively, a decrease of 38% and 26% compared to the same periods in 2015. On a per BOE basis, operating costs for the three and nine months ended September 30, 2016 were $6.64/BOE and $7.31/BOE, respectively, beating our annual guidance of $7.90/BOE. The decrease in operating costs was mainly a result of our continued cost savings in repairs and maintenance and well servicing and the divestment of higher operating cost Canadian properties in the fourth quarter of 2015 and throughout 2016.

Based on cost improvements to date, we are lowering our 2016 guidance for operating expenses to $7.50/BOE from $7.90/BOE. Although our operating costs were below guidance during the third quarter, we expect fourth quarter expenses to increase on a per BOE basis due to lower fourth quarter production and a higher liquids weighting.  

Transportation Costs

For the three and nine months ended September 30, 2016, transportation costs were $28.8 million ($3.39/BOE) and $78.9 million ($3.05/BOE), respectively, compared to $30.9 million ($3.03/BOE) and $85.4 million ($2.94/BOE) for the same periods in 2015.

The increase in the cost per BOE is primarily due to additional firm transportation commitments, including 30,000 Mcf/day of additional interstate pipeline capacity from the Marcellus region to downstream connections at pricing of US$0.63/Mcf, plus variable costs, that came into effect in August 2016. 

We are updating our 2016 guidance for transportation costs to $3.15/BOE from $3.10/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 and natural gas netbacks per BOE after hedging were lower for the three and nine months ended September 30, 2016 compared to the same periods in 2015 primarily due to lower realized hedging gains, offset by significant improvements in our operating costs. Our crude oil properties accounted for the majority of our netback, both before and after hedging.

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”) and our stock option plan. See Note 10 and Note 14 to the Interim Financial Statements for further details.