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, 2017

 

 

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, 2017

 

EXHIBIT 99.2 — Unaudited Consolidated Financial Statements for the Third Quarter ended September 30, 2017

 

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, 2017

Exhibit 99.1

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

The following discussion and analysis of financial results is dated November 8, 2017 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. 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 peers. 

OVERVIEW

Production for the third quarter averaged 79,128 BOE/day, a decrease of 8% compared to the second quarter. The decrease reflects the full quarter impact of Canadian asset divestments which closed in the second quarter for 5,600 BOE/day, as well as production curtailment in the Marcellus due to weakness in regional pricing. In North Dakota, 8.6 net wells were brought on-stream late in the third quarter modestly impacting production. However, these wells are expected to support our crude oil and liquids growth in the fourth quarter. We are reaffirming our annual average crude oil and natural gas liquids guidance of 40,500 bbls/day, the mid-point of our previous guidance range of 39,500 – 41,500 bbls/day, and narrowing our fourth quarter average crude oil and natural gas liquids range to 45,000 – 46,000 bbls/day from 43,000 – 48,000 bbls/day. As a result of price-related curtailments in the Marcellus of approximately 25,000 Mcf/day in September and 35,000 Mcf/day in October, we are revising our annual average production guidance to 84,000 BOE/day, the lower end of our previous range of 84,000 – 86,000 BOE/day, and narrowing our fourth quarter 2017 average production guidance range to 86,000 – 88,000 BOE/day from 86,000 – 91,000 BOE/day.  

 

Capital expenditures totaled $119.1 million in the third quarter, or $341.2 million year to date, with the majority of the third quarter spending directed to our North Dakota crude oil properties. We are maintaining our 2017 annual capital spending guidance of $450 million. 

 

Operating costs for the quarter increased to $6.71/BOE from $5.83/BOE in the second quarter of 2017, mainly due to the decrease in our Marcellus natural gas production volumes which have lower associated operating costs, as well as higher gas facility charges and well servicing costs on our crude oil properties. We are increasing our annual operating cost guidance to $6.50/BOE from $6.40/BOE, primarily as a result of the Marcellus curtailment. We are also reducing our annual guidance for transportation costs to $3.70/BOE from $3.90/BOE.

 

Cash G&A expenses for the third quarter were $11.7 million or $1.61/BOE, in line with $12.0 million during the second quarter and an increase on a per BOE basis, due to lower production volumes. We are lowering our annual cash G&A expense guidance to $1.70/BOE from $1.75/BOE due to continued cost savings year to date.

 

We continued to add to our commodity hedge positions during the quarter. As of November 8, 2017, we have approximately 72% of our forecasted crude oil production, net of royalties, hedged for the remainder of 2017, and approximately 70% and 36% of our crude oil production, net of royalties, hedged in 2018 and 2019, respectively, based on 2017 forecasted production. We have also hedged approximately 25% of our forecasted natural gas production, net of royalties, for the remainder of 2017 and approximately 13% of our natural gas production, net of royalties, for 2018 based on 2017 forecasted production.

 

We recorded net income of $16.1 million and adjusted funds flow of $90.4 million in the third quarter, compared to $129.3 million and $114.2 million, respectively, in the second quarter of 2017. Net income and funds flow decreased from the second quarter with lower realized commodity prices and lower production volumes. Net income in the second quarter of 2017 also included a gain of $78.4 million on the divestment of certain Canadian properties. 

 

At September 30, 2017, our total debt net of cash was $318.3 million and our net debt to adjusted funds flow ratio was 0.7x.  Subsequent to the quarter end, we completed a one year extension of our senior, unsecured, covenant-based bank credit facility, which now matures on October 31, 2020.

RESULTS OF OPERATIONS

Production

Production in the third quarter of 2017 decreased 14% to 79,128 BOE/day from average production levels of 92,077 BOE/day during the same period in 2016, due to the sale of non-core properties from the fourth quarter of 2016 through the second quarter of 2017 with associated production of approximately 12,300 BOE/day.  This decrease was somewhat offset by our November 2016 Canadian waterflood acquisition and increased capital spending commencing in January of 2017 to reinitiate growth on our North Dakota Bakken asset. 

 

Our crude oil and natural gas liquids weighting increased during the third quarter to 49% from 48% in the second quarter of 2017 and from 46% for the three months ended September 30, 2016.

 

Average daily production volumes for the three and nine months ended September 30, 2017 and 2016 are outlined below:

 

 

We are on track to meet our crude oil and natural gas liquids guidance ranges annually and for the fourth quarter. We are reaffirming the mid-point of our annual average liquids guidance at 40,500 to bbls/day and narrowing our fourth quarter average crude oil and natural gas liquids range to 45,000 – 46,000 bbls/day from 43,000 – 48,000 bbls/day. As a result of price-related curtailment in the Marcellus of approximately 25,000 Mcf/day in September and 35,000 Mcf/day in October, we are revising our annual average production guidance to 84,000 BOE/day, the lower end of our previous range of 84,000 – 86,000 BOE/day, and narrowing our fourth quarter average production guidance target to 86,000 – 88,000 BOE/day from 86,000 – 91,000 BOE/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 average prices for the nine months ended September 30, 2017 and 2016 and quarterly average prices for the periods indicated:

 

(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 decreased by 3% during the quarter to average $54.21/bbl. The strengthening of the Canadian dollar largely offset the improvement in realized crude oil differentials from the second quarter, with WTI prices essentially unchanged.   

 

Bakken price differentials to WTI improved by US$2.19/bbl during the quarter to average US$3.24/bbl below WTI. Spot Bakken prices strengthened considerably throughout the quarter due to the improved egress capacity out of the basin, on-going Canadian synthetic crude oil supply outages, and incremental demand from refineries for light barrels due to on-going market disruption during an active hurricane season. Accordingly, we are narrowing our expected realized Bakken differential to US$2.00/bbl below WTI for the remainder of 2017, and expect the differential to average US$4.00/bbl below WTI for the full year.  

 

Our realized price differential for our Canadian crude oil production improved by 16% compared to the previous quarter, due largely to strength in Canadian heavy crude oil benchmark prices which were impacted by ongoing regional oil sands production outages. Our realized price for natural gas liquids averaged $26.22/bbl during the period, an increase of 4% compared to the previous quarter. Natural gas liquids prices strengthened during the third quarter primarily due to improved propane market fundamentals.

 

NATURAL GAS

 

Our average realized natural gas price during the third quarter decreased by 26% compared to the second quarter to average $2.58/Mcf. Benchmark NYMEX natural gas prices decreased by 6% during the quarter. Both AECO and Marcellus prices decreased more than the NYMEX benchmark due to considerable weakness in their respective basis markets. 

 

Our realized Marcellus sales price differential, excluding transportation and gathering, widened during the quarter to average US$1.02/Mcf below NYMEX. This outperformed the Benchmark monthly Transco Leidy price which averaged US$1.29/Mcf below NYMEX during the third quarter. Marcellus pricing weakened during the quarter due to cooler than average weather in the northeast United States, and incremental supply coming onstream during the quarter in expectation of flowing on the

subsequently delayed Rover pipeline. Rover capacity is being brought online in stages throughout the fall of 2017, with full capacity not expected to be in service until the end of the first quarter of 2018. We expect Marcellus differentials to average US$1.05/Mcf below NYMEX for the remainder of 2017, and to average US$0.80/Mcf below NYMEX for the full year.      

 

AECO gas prices have been extremely weak, particularly in the day markets, due to delivery restrictions on export pipelines. In the third quarter, our realized Canadian natural gas sales differential averaged US$1.00/Mcf below NYMEX.  Enerplus continues to benefit from the active management of our AECO basis risk where we have sold the majority of our Canadian production under multi-year fixed AECO basis differential contracts at prices higher than those currently realized in the spot market.

 

FOREIGN EXCHANGE

 

The Canadian dollar strengthened considerably during the third quarter to average 1.25 USD/CDN compared to average rates of 1.34 USD/CDN during the second quarter of 2017 and 1.31 USD/CDN during the third quarter of 2016. 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 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 and the economics of our capital expenditures. 

   

As of November 8, 2017, we have hedged 20,000 bbls/day of our expected crude oil production for the remainder of 2017, which represents approximately 72% of our 2017 forecasted crude oil production, after royalties. For 2018, we have hedged approximately 19,500  bbls/day, which represents approximately 70% of our 2017 forecasted crude oil production, after royalties. For 2019, we have hedged 10,000 bbls/day, which represents approximately 36% of our 2017 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 November 8, 2017, we have hedged 50,000 Mcf/day of our forecasted natural gas production for the remainder of 2017. This represents approximately 25% of our forecasted natural gas production, after royalties. For 2018 we have hedged 25,000 Mcf/day, which represents 13% of our 2017 forecasted natural gas production, after royalties.  

 

The following is a summary of our financial contracts in place at November 8, 2017, expressed as a percentage of our forecasted 2017 net production volumes:

 

ACCOUNTING FOR PRICE RISK MANAGEMENT

 

 

 

During the third quarter of 2017 we realized cash gains of $2.9 million on our crude oil contracts. In comparison, 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. The cash gains recorded in the quarter were due to crude oil contracts which provided floor protection above market prices.

 

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 2017, the fair value of our crude oil contracts was in a net asset position of $5.3 million, while the fair value of our natural gas contracts was in a net liability position of $0.1 million. For the three and nine months ended September 30, 2017, the change in the fair value of our crude oil contracts represented losses of $37.4 million and gains of $34.2 million, respectively, and our natural gas contracts represented gains of $0.3 million and $9.4 million, respectively.

Revenues

 

Oil and natural gas sales for the three and nine months ended September 30, 2017 were $241.9 million and $801.7 million, respectively, an increase of 5% and 31% from the same periods in 2016. The increase in revenue primarily resulted from higher commodity prices for both crude oil and natural gas compared to the same periods in 2016, which more than offset the impact of lower production volumes driven by asset divestments.

 

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, 2017, royalties and production taxes increased to $58.1 million and $188.6 million, respectively, from $52.5 million and $134.7 million for the same periods in 2016 primarily due to higher commodity 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 25%. Royalties and production taxes averaged 24% of crude oil and natural gas sales before transportation in the first nine months of 2017 compared to 22% for the same period in 2016.

 

We are maintaining our annual average royalty and production tax rate guidance of 24% for 2017.

Operating Expenses

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

 

For the three and nine months ended September 30, 2017, operating expenses were $48.8 million or $6.71/BOE and $145.0 million or $6.37/BOE, respectively, compared to our annual guidance of $6.40/BOE. Operating costs were lower by $7.4 million and $44.4 million, respectively, compared to the same periods in 2016 mainly due to the divestment of higher operating cost Canadian properties throughout 2016 and into 2017 along with cost savings initiatives. On a per BOE basis, operating costs for the nine months ended September 30, 2017 were 13% lower compared to the same period in 2016. However on a per BOE basis, the third quarter of 2017 increased slightly due to a decrease in Marcellus natural gas production volumes which have lower associated operating costs, as well as higher gas facility charges and well servicing costs on our crude oil properties.

 

We are increasing our annual operating cost guidance to $6.50/BOE from $6.40/BOE, primarily due to the impact of the Marcellus curtailment in September and October.   

Transportation Costs

 

For the three and nine months ended September 30, 2017, transportation costs were $26.3 million or $3.61/BOE and $85.1 million or $3.74/BOE, respectively, relative to our annual guidance target of $3.90/BOE. During the same periods in 2016 transportation costs were $28.8 million or $3.39/BOE and $78.9 million or $3.05/BOE, respectively. 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 that came into effect in August 2016, and a higher proportion of total production volumes from the U.S. which have higher associated transportation costs. 

 

We are revising our annual guidance for transportation costs to $3.70/BOE from $3.90/BOE due to the impact of the Marcellus curtailment, the lower USD/CDN foreign exchange rates on U.S. transportation costs, and increased North Dakota production sold on a netback basis.

 

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 were higher for both the three and nine months ended September 30, 2017 compared to the same periods in 2016 due to higher oil and natural gas prices, improvements in the sales price differentials in the North Dakota and Marcellus regions, along with reductions to our operating expenses due in part to the sale of non-core

Canadian assets.  For the three and nine month periods ended September 30, 2017, our crude oil properties accounted for 85% and 75%, respectively, of our netback before hedging, compared to 83% and 95% of our netback during the same periods in 2016.

 

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, 2017 cash G&A expenses were $11.7 million or $1.61/BOE and $37.9 million or $1.67/BOE, respectively, compared to $13.4 million or $1.58/BOE and $46.4 million or $1.79/BOE for the same periods in 2016. The decrease in cash G&A expenses from the prior year was primarily due to continued cost savings initiatives and the impact of reductions in staff levels throughout 2016 and early 2017 as we continue to focus our business through asset divestments.  

 

During the quarter, we reported cash SBC expense of $0.7 million due to our share price improvement. In comparison, during the same period of 2016, we recorded cash SBC expense of $0.2 million. We recorded non-cash SBC of $4.1 million or $0.57/BOE in the third quarter of 2017 compared to $2.9 million or $0.35/BOE during the same period in 2016. The increase in non-cash SBC was a result of an improvement in our performance multiplier based on our relative return in the Toronto Stock Exchange Oil and Gas Producers Index, which was partially offset by the impact of forfeitures due to reductions in staff over the past year.

 

We are reducing our annual cash G&A guidance to $1.70/BOE from $1.75/BOE due to further cost reductions. 

Interest Expense

For the three and nine months ended September 30, 2017, we recorded total interest expense of $8.7 million and $29.0 million, respectively, compared to $9.7 million and $34.3 million for the same periods in 2016. 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 during the second quarter of 2017. The decrease for the nine month period ended September 30, 2017 compared to the same period in 2016, was primarily due to the repurchase of US$267 million of senior notes during the first half of 2016.

 

At September 30, 2017, we were undrawn on our $800 million bank credit facility and our debt balance consisted of fixed interest rate senior notes with a weighted average interest rate of 4.8%. See Note 8 in the Interim Financial Statements for further details.

 

Foreign Exchange

 

 

For the three and nine months ended September 30, 2017, we recorded net foreign exchange gains of $17.6 million and $33.6 million, respectively, compared to a loss of $3.1 million and a gain of $50.9 million for the same periods in 2016. Realized gains and losses relate primarily to day-to-day transactions recorded in foreign currencies, along with 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. When comparing September 30, 2017 to December 31, 2016, the Canadian dollar strengthened relative to the U.S. dollar resulting in unrealized gains of $48.6 million. See Note 12 to the Interim Financial Statements for further details.

Capital Investment

 

Capital spending for the three and nine months ended September 30, 2017, totaled $119.1 million and $341.2 million, respectively, compared to the $60.3 million and $151.7 million for the same periods in 2016. The increased spending is in line with our strategy to re-initiate growth through an increased capital program in 2017. During the quarter we spent $92.4 million on our U.S. crude oil properties, $16.0 million on our Marcellus natural gas assets and $9.2 million on our Canadian waterflood properties.

 

Property divestments for the nine months ended September 30, 2017 were $57.6 million, consisting mainly of our second quarter divestment of our Brooks waterflood property and Canadian shallow gas assets. In comparison, we had divestments of $280.6 million during the same period in 2016, which was mainly related to the divestment of non-core properties in the Deep Basin and in N.W. Alberta. 

 

We continue to expect annual capital spending of $450 million.

Gain on Asset Sales and Note Repurchases

We recorded a gain of $78.4 million on the sale of Canadian properties for the first nine months of 2017. In comparison, gains of $219.8 million were recorded on asset divestments during the first nine months of 2016. Under full cost accounting rules, divestments of oil and natural gas properties are generally accounted for as adjustments to the full cost pool with no recognition of a gain or loss. However, if not recognizing a gain or loss on the transaction would significantly alter the relationship between a cost centre’s capitalized costs and proved reserves, then a gain or loss must be recognized. Gains and losses are evaluated on a case by case basis for each asset sale, and future sales may or may not result in such treatment.

 

For the nine month period ended September 30, 2016, we recorded gains of $19.3 million on the repurchase of US$267 million of our senior notes at a discount to par value.