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, 2019

 

 

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 ☒

 

 

 

 

 

EXHIBIT INDEX

 

EXHIBIT 99.1 — Management’s Discussion and Analysis for the Third Quarter ended September  30, 2019

 

EXHIBIT 99.2 — Unaudited Consolidated Financial Statements for the Third Quarter ended September  30, 2019

 

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 8, 2019

Exhibit 99.1

 

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

 

The following discussion and analysis of financial results is dated November 7, 2019 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. Unless otherwise stated, 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. 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 January 1, 2019, Enerplus adopted ASC 842 - Leases. The most significant impact was the recognition of right-of-use (“ROU”) assets and lease liabilities on the Condensed Consolidated Balance Sheet for operating leases and additional note disclosures. See Notes 3(a) and 10 to the Interim Financial Statements for further details.

OVERVIEW

 

Production for the third quarter averaged 107,181 BOE/day, an increase of 6% compared to second quarter production of 100,694 BOE/day. Crude oil and natural gas liquids production increased by 14% from the second quarter to 60,121 bbls/day with 8.1 net wells brought on stream in North Dakota and the full quarter impact of wells brought on stream near the end of the second quarter. We are narrowing our average annual production guidance range to 100,000 to 101,000 BOE/day from 99,000 to 102,000 BOE/day and narrowing our average annual crude oil and natural gas liquids guidance range to 54,250 to 54,750 bbls/day from 54,000 to 55,500 bbls/day.  We are also providing additional fourth quarter average production guidance of 103,000 to 107,000 BOE/day and fourth quarter crude oil and natural gas liquids production guidance of 58,000 to 60,000 bbls/day.

 

During the third quarter, capital expenditures totaled $151.5 million, with approximately 90% of capital spending directed to U.S. crude oil properties in North Dakota and the DJ Basin. We expect total 2019 annual capital spending of $625 million, compared to the previous guidance range of $610 to $630 million. Capital activity for the remainder of the year will largely be focused on drilling in North Dakota.

 

 

Operating expenses and cash General & Administrative (“G&A”) expenses were in line with the prior quarter, at $69.6 million and $11.7 million, respectively. As a result of production growth, operating and G&A expenses decreased on a per BOE basis to $7.06/BOE and $1.19/BOE, respectively, compared to $7.84/BOE and $1.26/BOE, respectively, during the second quarter of 2019. We are maintaining our annual operating expense guidance of $7.90/BOE and reducing our annual cash G&A expense guidance to $1.40/BOE from $1.45/BOE. 

 

Our Bakken crude oil price differential widened to US$3.61/bbl below WTI during the third quarter, compared to US$3.00/bbl below WTI in the second quarter of 2019, due to increasing production in the region. Accordingly, we are revising our full year U.S. Bakken crude oil differential outlook to US$3.60/bbl from US$3.25/bbl below WTI. We continue to expect a full year Marcellus natural gas sales price differential of US$0.35/Mcf below NYMEX.

 

As of November 6, 2019, we had approximately 66% of forecasted crude oil production, net of royalties, hedged for 2019, and approximately 43% of crude oil production, net of royalties, hedged in 2020, based on 2019 forecasted net production.

 

We reported net income of $65.2 million in the third quarter of 2019 compared to $85.1 million in the second quarter of 2019. The decrease was primarily the result of fluctuations in the USD/CDN foreign exchange rate, which resulted in a $7.1 million foreign exchange loss in the third quarter compared to a gain of $12.3 million in the second quarter of 2019.

 

During the third quarter of 2019, cash flow from operations decreased to $159.8 million, compared to $237.0 million in the second quarter of 2019, due to changes in working capital, most notably, the receipt of the first Alternative Minimum Tax (“AMT”) refund of $57.2 million in the second quarter of 2019. Adjusted funds flow in the third quarter decreased to $175.3 million from $186.0 million in the second quarter of 2019, primarily due to a current tax recovery of $13.9 million recorded in the second quarter.

 

During the quarter, we repurchased and cancelled 7,145,070 common shares under our Normal Course Issuer Bid (“NCIB”) for total consideration of $64.8 million.

 

At September 30, 2019, total debt net of cash was $521.4 million and our net debt to adjusted funds flow ratio was 0.7x.

 

RESULTS OF OPERATIONS

 

Production

 

Average daily production for the third quarter totaled 107,181 BOE/day, an increase of 6,487 BOE/day or 6% compared to second quarter production of 100,694 BOE/day. Crude oil and natural gas liquids production increased by 7,260 bbls/day or 14% from the second quarter to 60,121 bbls/day. We continued to see oil and natural gas liquids production growth in North Dakota, with 8.1 net wells coming on stream in the third quarter and a full quarter of production from the 24.7 net wells brought on stream in the second quarter. This was partially offset by the sale of certain Canadian assets with associated production of approximately 350 bbls/day in the second quarter. Natural gas production decreased 2% to 282,360 Mcf/day in the third quarter from 287,000 Mcf/day in the second quarter as a result of fewer wells brought on stream during the third quarter.

 

For the three and nine months ended September 30, 2019, total production increased by 10,320 BOE/day or 11%, and 7,237 BOE/day or 8%, respectively, when compared to the same periods in 2018. Production increased primarily due to our capital program in North Dakota and the DJ Basin, along with strong well performance in the Marcellus.

 

Our crude oil and natural gas liquids weighting increased to 56% in the third quarter of 2019 from 52% in the second quarter of 2019 and 55% in the third quarter of 2018.

 

Average daily production volumes for the three and nine months ended September 30, 2019 and 2018 are outlined below:

 

 

We are narrowing our average annual production guidance range to 100,000 to 101,000 BOE/day from 99,000 to 102,000 BOE/day and are narrowing our average annual crude oil and natural gas liquids guidance range to 54,250 to 54,750 bbls/day from 54,000 to 55,500 bbls/day. In addition, we expect fourth quarter average production of 103,000 to 107,000 BOE/day, including average crude oil and natural gas liquids production of 58,000 to 60,000 bbls/day.

 

Pricing

 

The prices received for crude oil and natural gas production directly impact our earnings, cash flow from operations, adjusted funds flow and financial condition. The following table compares quarterly average prices for the nine months ended September 30, 2019 and 2018 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 realized crude oil sales price for the third quarter of 2019 averaged $67.76/bbl, a decrease of 9% compared to the second quarter of 2019. The decrease exceeded the change in WTI pricing, which was due to weakening Bakken and Canadian crude price differentials during the third quarter. Our realized Bakken crude oil differential weakened by US$0.61/bbl during the quarter to average US$3.61/bbl below WTI with increased production in the region pressuring in-basin pricing. Our Bakken sales price consists of a combination of in-basin monthly spot and index sales, term physical sales with fixed differential pricing versus WTI and/or Brent, and sales at the U.S. Gulf Coast delivered via firm capacity on the Dakota Access Pipeline. Bakken differentials began to weaken late in the third quarter and into the fourth quarter due to weaker Brent and WTI differentials in the Gulf Coast, as well as weaker spot prices resulting from higher than expected regional production growth in North Dakota. For the remainder of 2019, we have physical sales contracts in place for an average of 24,800 bbls/day of North Dakota crude oil production with fixed differentials averaging approximately US$2.69/bbl below WTI. Based on year to date price realizations and wider than expected fourth quarter Bakken differentials, we are revising our full year Bakken crude oil differential guidance to US$3.60/bbl below WTI from US$3.25/bbl.

 

Our realized price differential for Canadian crude oil production widened by US$3.51/bbl compared to the previous quarter, in response to a reduction in the production curtailments imposed by the Alberta government. We have fixed differential financial hedges in place for 1,500 bbls/day of Canadian heavy crude oil production at an average differential of US$14.83/bbl below WTI for the remainder of 2019.

 

Our realized price for natural gas liquids averaged $5.97/bbl during the third quarter, an $11.99/bbl decrease compared to the second quarter. Liquids pricing weakened further during the quarter as both local and North American butane and propane markets continue to remain oversupplied in 2019.

 

 

NATURAL GAS

 

Our average realized natural gas price during the third quarter of 2019 decreased by 19% compared to the second quarter of 2019 to average $2.13/Mcf, while NYMEX benchmark pricing decreased by 16%. Our realized Marcellus sales differential averaged US$0.44/Mcf below NYMEX during the third quarter.  Pricing in U.S. Northeast markets was relatively weak during the quarter, particularly in September, after a cooler than normal summer allowed more gas to be injected into storage.  Based on year to date realizations and our fourth quarter pricing outlook, we are maintaining our full year differential guidance for the Marcellus of US$0.35/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 weaker Canadian dollar increases 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 weaker during the first nine months of 2019 with an average exchange rate of 1.33 USD/CDN compared to 1.29 USD/CDN for the same period in 2018. However, when compared to the exchange rate of 1.36 USD/CDN at December 31, 2018, the Canadian dollar strengthened relative to the U.S. dollar, closing the third quarter at 1.32 USD/CDN. 

 

Price Risk Management

 

We have a price risk management program that considers our overall financial position and the economics of our capital program. 

   

As of November 6, 2019, we have hedged 24,500 bbls/day of crude oil, which represents approximately 66% of our forecasted crude oil production, after royalties, for the remainder of 2019. For 2020, we have hedged 16,000 bbls/day, which represents approximately 43% of crude oil production, after royalties, based on our 2019 forecast. Our crude oil hedges in 2019 are all three-way collars which consist of a sold put, a purchased put and a sold call. Our crude oil hedges in 2020 are all put spreads with no cap on upside participation. With both three-way collars and put spreads, if WTI prices settle below the sold put strike price, these positions 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 cash flow from operating activities and adjusted funds flow.

 

We have entered into offsetting purchase transactions on our NYMEX natural gas hedges through October 2019. This has effectively locked in gains of US$0.51/Mcf on our original NYMEX hedges through this term.

 

The following is a summary of our financial contracts in place at November 6, 2019, expressed as a percentage of our anticipated net production volumes:

 

 

ACCOUNTING FOR PRICE RISK MANAGEMENT

 

 

During the third quarter of 2019, we realized cash losses of $2.5 million on crude oil contracts and cash gains of $7.7 million on natural gas contracts. In comparison, during the third quarter of 2018, we realized cash losses of $24.3 million on crude oil contracts and cash gains of $0.4 million on natural gas contracts. Cash losses in the third quarter of 2019 on crude oil contracts were primarily due to premiums paid on expiring three-way collars. For the same period, cash gains on natural gas contracts resulted from natural gas prices falling below the swap level.

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 September 30, 2019, the fair value of crude oil contracts was in a net asset position of $37.7 million and the fair value of our natural gas contracts was in a net asset position of $1.9 million. For the three and nine months ended September 30, 2019, the change in the fair value of our crude oil contracts resulted in a gain of $20.5 million and a  loss of $42.8 million, respectively, and our natural gas contracts resulted in a loss of $5.5 million and $9.1 million, respectively.

Revenues

 

 

Oil and natural gas sales, net of royalties, for the three and nine months ended September 30, 2019, were $318.9 million and $927.8 million, respectively, a decrease of 15% and 4% from the same periods in 2018. The decrease in revenue during the three and nine months ended September 30, 2019 was a result of lower commodity prices, partially offset by higher production compared to the same periods in 2018.

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, 2019, royalties and production taxes decreased to $106.5 million and $293.2 million, respectively, from $119.4 million and $301.2 million for the same periods in 2018, primarily due to lower U.S. crude oil revenue.  

 

We are maintaining our annual average royalty and production tax rate guidance of 25% for 2019.

Operating Expenses

 

 

For the three and nine months ended September 30, 2019, operating expenses were $69.6 million or $7.06/BOE and $211.3 million or $7.83/BOE, respectively, representing an increase of $8.9 million and $36.0 million from the same periods in 2018. The increase is mainly attributable to higher North Dakota crude oil and natural gas liquids volumes, higher gas facility charges and well service activity in 2019.

 

We are maintaining our annual operating cost guidance of $7.90/BOE. 

 

Transportation Costs

 

 

For the three and nine months ended September 30, 2019, transportation costs were $39.0 million or $3.96/BOE and $107.1 million or $3.97/BOE, respectively. During the same periods in 2018, transportation costs were $33.0 million or $3.70/BOE and $90.1 million or $3.60/BOE. The increase is due to U.S. production growth and additional crude oil firm transportation commitments that commenced on March 1, 2019 and provide access to sell a portion of our North Dakota production at U.S. Gulf Coast or Brent pricing.

 

We are maintaining our annual guidance for transportation costs of $4.00/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.

 

 

 

 

 

 

 

 

 

 

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

 

Total netbacks before hedging for the three and nine months ended September 30, 2019 were lower compared to the same periods in 2018 primarily due to weaker realized prices, increased cash operating expenses and increased transportation.

 

For the three and nine months ended September 30, 2019, our crude oil properties accounted for 91% and 83% of our total netback before hedging, respectively, compared to 89% and 87% during the same periods in 2018.

 

General and Administrative (“G&A”) Expenses

 

Total G&A expenses include share-based compensation (“SBC”) charges related to our long-term incentive plans (“LTI plans”). See Note 12 and Note 15 to the Interim Financial Statements for further details.

 

 

 

For the three and nine months ended September 30, 2019, cash G&A expense was $11.7 million or $1.19/BOE and $35.5 million or $1.32/BOE, respectively, compared to $12.0 million or $1.35/BOE and $37.3 million or $1.49/BOE for the same periods in 2018. While total cash G&A expenses decreased, the more significant per BOE decrease was due to higher production when compared to the same periods in 2018.

 

During the third quarter of 2019, we reported a cash SBC expense of $0.1 million due to an  increase in our share price on outstanding deferred share units. In comparison, during the same period of 2018, we recorded a cash SBC recovery of $0.2 million due to a decrease in our share price on outstanding deferred share units. In the third quarter of 2019, we recorded  a non-cash SBC expense of $4.7 million or $0.48/BOE, consistent with $4.3 million or $0.48/BOE during the same period in 2018. 

 

We have hedges in place on a portion of the outstanding cash-settled grants under our LTI plans. Due to minimal share price movement over the third quarter of 2019, we recorded no mark-to-market gain or loss, compared to a loss of $0.2 million in the same period in 2018. At September 30, 2019, we had 264,000 units outstanding, hedged at a weighted average price of $17.82 per share.

 

Based on year-to-date spending, we are reducing our annual cash G&A guidance of $1.45/BOE to $1.40/BOE. 

Interest Expense

 

For the three and nine months ended September 30, 2019, we recorded total interest expense of $7.9 million and $25.0 million, respectively, compared to $8.6 million and $27.0 million for the same periods in 2018. The decrease in interest expense for the nine months ended September 30, 2019 compared to the same period in 2018 was primarily due to the repayment of a portion of 2009 senior notes which carry a higher coupon rate compared to the remaining senior notes outstanding.

 

At September 30, 2019, we were undrawn on our bank credit facility and our debt balance consisted of fixed interest rate senior notes with a weighted average interest rate of 4.7%. See Note 8 to the Interim Financial Statements for further details.

 

Foreign Exchange

 

 

For the three and nine months ended September 30, 2019, we recorded a foreign exchange loss of $7.1 million and a  gain of $17.1 million, respectively, compared to a  gain of $7.6 million and  a loss of $11.7 million for the same periods in 2018. Realized gains and losses relate primarily to day-to-day transactions recorded in foreign currencies, along with the translation of U.S. dollar denominated cash held in Canada, while unrealized gains and losses are recorded on the translation of U.S. dollar denominated debt and working capital at each period end. Comparing the period end exchange rate at September 30, 2019 to December 31, 2018, the Canadian dollar strengthened relative to the U.S. dollar, resulting in an unrealized gain of $25.0 million. See Note 13 to the Interim Financial Statements for further details.

Capital Investment

 

 

Capital spending for the three and nine months ended September 30, 2019 totaled $151.5 million and $519.5 million, respectively, compared to $193.3 million and $521.8 million for the same periods in 2018. The decrease in spending was due to lower completions activity in the third quarter of 2019 compared to the same period in 2018. During the third quarter of 2019, we invested $136.2 million in U.S. crude oil properties, $9.5 million in Marcellus natural gas assets and $6.2 million in Canadian waterflood properties. During the nine months ended September 30, 2019, we spent $5.1 million on line fill to meet the requirements of a multi-year transportation contract, which began in March 2019.

 

In the third quarter of 2019, we completed $13.3 million in property and land acquisitions, which consisted primarily of undeveloped land in North Dakota, compared to $1.7 million for the same period in 2018. Property divestments for the nine months ended September 30, 2019 were $9.9 million, which primarily related to the divestment of properties in Southeastern Saskatchewan with associated production of approximately 350 bbls/day.