Report of Foreign Issuer (6-k)

 

 

 

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 August, 2019

 

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COMMISSION FILE NUMBER 1‑15150

 

 

The Dome Tower

Suite 3000, 333 – 7th Avenue S.W.

Calgary, Alberta

Canada T2P 2Z1

 

(403) 298‑2200

 

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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 Second Quarter ended June  30, 2019

 

EXHIBIT 99.2 — Unaudited Consolidated Financial Statements for the Second Quarter ended June  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.

 

	ENERPLUS CORPORATION
	BY:	/s/ David A. McCoy
		David A. McCoy
		Vice President, General Counsel & Corporate Secretary

 

 

DATE:  August 9, 2019

        MD&A

Exhibit 99.1

 

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

 

The following discussion and analysis of financial results is dated August 8, 2019 and is to be read in conjunction with:

 

·

the unaudited interim condensed consolidated financial statements of Enerplus Corporation (“Enerplus” or the “Company”) as at and for the three and six months ended June  30, 2019 and 2018 (the “Interim Financial Statements”);

·

the audited consolidated financial statements of Enerplus as at December 31, 2018 and 2017 and for the years ended December 31, 2018, 2017 and 2016; and

·

our MD&A for the year ended December 31, 2018 (the “Annual MD&A”).

The following MD&A contains forward-looking information and statements. We refer you to the end of the MD&A under “Forward-Looking Information and Statements” for further information. The following MD&A also contains financial measures that do not have a standardized meaning as prescribed by accounting principles generally accepted in the United States of America (“U.S. GAAP”). See “Non-GAAP Measures” at the end of the MD&A for further information.

 

BASIS OF PRESENTATION

 

The Interim Financial Statements and Notes 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 in 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 second quarter averaged 100,694 BOE/day, an increase of 14% compared to the first quarter of 2019 and exceeded our second quarter guidance of 97,500 to 100,000 BOE/day.  Our crude oil and natural gas liquids production increased by 16% to 52,861 bbls/day from 45,488 bbls/day in the first quarter of 2019, meeting the high end of our second quarter crude oil and natural gas liquids production guidance range of 51,500 to 53,000 bbls/day. The increase in our liquids production was primarily due to our 24.7 net wells brought on-stream during the period in North Dakota. Our natural gas production increased by 11% or 28,432 Mcf/day from the first quarter of 2019 to 287,000 Mcf/day due to outperformance in our Marcellus properties. As a result of higher production in the Marcellus, we are increasing our average annual production guidance range to 99,000 to 102,000 BOE/day (from 97,000 to 101,000 BOE/day). We are also narrowing our average annual crude oil and natural gas liquids guidance to 54,000 to 55,500 bbls/day (from 53,500 to 56,000 bbls/day).  

 

Capital expenditures during the second quarter of $207.2 million were in line with our expectations, with approximately 80% of our capital spending directed to our North Dakota crude oil properties. We are narrowing our 2019 annual capital spending guidance range to $610 – $630 million from $590 – $630 million.

 

ENERPLUS 2019 Q2 REPORT               1

        

Operating expenses for the quarter were $71.8 million or $7.84/BOE compared to  $69.8 million or $8.75/BOE in the first quarter of 2019. The decrease on a per BOE basis was mainly due to increased production in the second quarter of 2019. We are reducing our annual operating cost guidance of $8.00/BOE to $7.90/BOE for 2019, due to the increase in our average annual production guidance.

 

Cash G&A expenses for the second quarter were $11.5 million or $1.26/BOE, a decrease of 19% on a per BOE basis from $1.55/BOE in the first quarter of 2019. Cash G&A expenses decreased on a per BOE basis, primarily due to higher production volumes during the period. We are reducing our annual guidance of $1.50/BOE to $1.45/BOE for cash G&A expenses for the year.

 

During the second quarter of 2019, our Bakken crude oil price differential improved to US$3.00/bbl below WTI, compared to US$3.25/bbl below WTI in the first quarter of 2019. Our Marcellus natural gas differential widened to US$0.57/Mcf below NYMEX in the second quarter, compared to US$0.13/Mcf above NYMEX in the first quarter of 2019, due to lower gas prices and a decline in weather-related demand. In addition, our first quarter Marcellus natural gas prices benefited from fixed basis sales at markedly higher levels than the settled benchmarks. We are reducing our full year U.S. Bakken crude oil differential outlook to US$3.25/bbl below WTI from US$4.00/bbl and revising our full year Marcellus natural gas sales price differential outlook to US$0.35/Mcf below NYMEX from US$0.30/Mcf.

 

As of August 7, 2019, we had approximately 66% of our forecasted crude oil production, net of royalties, hedged for 2019, and approximately 43% of our crude oil production, net of royalties, hedged in 2020, based on 2019 forecasted net production.

 

We reported net income of $85.1 million in the second quarter of 2019 compared to $19.2 million in the first quarter of 2019. The increase is primarily the result of a $34.0 million increase to revenue, net of royalties, resulting from higher production and a $28.6 million unrealized gain on commodity derivative instruments, compared to an unrealized loss of $95.4 million in the first quarter of 2019.

 

In the second quarter of 2019, cash flow from operations increased to $237.0 million, compared to $109.0 million in the first quarter of 2019 due to higher production and changes to 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 second quarter increased to $186.0 million from $168.8 million in the first quarter of 2019, as a result of increased production and a  current tax recovery of $13.9 million, compared to $5.5 million in the prior period.

 

During the quarter, we repurchased and cancelled 6,626,783 common shares under our Normal Course Issuer Bid (“NCIB”) for total consideration of $70.6 million.

 

At June 30, 2019, our total debt net of cash was $359.0 million and our net debt to adjusted funds flow ratio was 0.5x.

RESULTS OF OPERATIONS

 

Production

 

Average daily production for the second quarter totaled 100,694 BOE/day, an increase of 12,111 BOE/day or 14% compared to first quarter production of 88,583 BOE/day, exceeding our second quarter average production guidance range of 97,500 to 100,000 BOE/day. Crude oil and natural gas liquids production increased by 16% to 52,861 bbls/day from the first quarter,  meeting the high end of our second quarter crude oil and natural gas liquids guidance range of 51,500 to 53,000 bbls/day. The increase was due to the 24.7 net wells coming on-stream in North Dakota during the second quarter compared to 3.5 in the prior period. Our natural gas production increased by 11% to 287,000 Mcf/day when compared to our first quarter production of 258,568 Mcf/day, due to strong well performance in our Marcellus properties, where 1.6 net wells were brought on-steam during the period. During the second quarter, we completed the sale of certain Canadian assets with associated production of approximately 350 bbls/day.

 

For the three and six months ended June 30, 2019, total production increased by 7,811 BOE/day or 8%, and 5,668 BOE/day or 6%, respectively, when compared to the same periods in 2018.  Our liquids growth is largely due to our continued capital investment in North Dakota and our increased natural gas production is due to strong well performance in the Marcellus.

 

Our crude oil and natural gas liquids weighting increased to 52% in the first six months of 2019, from 51% for the same period of 2018, due to continued investment in our North Dakota crude oil properties.

 

2               ENERPLUS 2019 Q2 REPORT

        

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

 

		Three months ended June 30,						Six months ended June 30,
Average Daily Production Volumes		2019		2018		% Change		2019		2018		% Change
Crude oil (bbls/day)		48,141		45,242		6%		44,642		41,364		8%
Natural gas liquids (bbls/day)		4,720		4,808		(2%)		4,552		4,449		2%
Natural gas (Mcf/day)		287,000		256,995		12%		272,863		259,141		5%
Total daily sales (BOE/day)		100,694		92,883		8%		94,671		89,003		6%

 

As a result of strong well performance, we are increasing our average annual production guidance to 99,000 – 102,000 BOE/day from 97,000 – 101,000 BOE/day and narrowing our average annual crude oil and natural gas liquids guidance to 54,000 – 55,500 bbls/day from 53,500 – 56,000 bbls/day. 

 

Pricing

 

The prices received for our 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 from the first half of 2019 to the first half of 2018 and other periods indicated:

	Six months ended June 30,
Pricing (average for the period)	2019			2018			Q2 2019			Q1 2019				Q4 2018			Q3 2018			Q2 2018
Benchmarks
WTI crude oil (US$/bbl)	$	57.36		$	65.37		$	59.81		$	54.90		$	58.81		$	69.50		$	67.88
Brent (ICE) crude oil (US$/bbl)		66.11			71.04			68.32			63.90			68.08			75.97			74.90
NYMEX natural gas – last day (US$/Mcf)		2.89			2.90			2.64			3.15			3.64			2.90			2.80
USD/CDN average exchange rate		1.33			1.28			1.34			1.33			1.32			1.31			1.29
USD/CDN period end exchange rate		1.31			1.31			1.31			1.33			1.36			1.29			1.31
Enerplus selling price(1)
Crude oil ($/bbl)	$	70.82		$	75.34		$	74.42		$	66.56		$	64.18		$	83.98		$	79.98
Natural gas liquids ($/bbl)		18.53			30.36			17.96			19.15			26.72			25.95			32.23
Natural gas ($/Mcf)		3.46			3.09			2.63			4.38			4.28			3.22			2.68
Average differentials
Bakken DAPL – WTI (US$/bbl)	$	(2.64)		$	(2.37)		$	(2.36)		$	(2.93)		$	(9.22)		$	(0.97)		$	(2.78)
Brent (ICE) – WTI (US$/bbl)		8.75			5.67			8.51			9.00			9.27			6.47			7.02
MSW Edmonton – WTI (US$/bbl)		(4.74)			(5.67)			(4.63)			(4.85)			(26.30)			(6.83)			(5.45)
WCS Hardisty – WTI (US$/bbl)		(11.48)			(21.78)			(10.67)			(12.29)			(39.43)			(22.25)			(19.27)
Transco Leidy monthly – NYMEX (US$/Mcf)		(0.33)			(0.79)			(0.43)			(0.22)			(0.39)			(0.61)			(0.91)
Transco Z6 Non-New York monthly – NYMEX (US$/Mcf)		0.68			1.46			(0.31)			1.67			0.20			(0.12)			(0.18)
Enerplus realized differentials(1)(2)
Bakken crude oil – WTI (US$/bbl)	$	(3.10)		$	(3.34)		$	(3.00)		$	(3.25)		$	(5.60)		$	(2.54)		$	(3.42)
Marcellus natural gas – NYMEX (US$/Mcf)		(0.25)			(0.45)			(0.57)			0.13			(0.34)			(0.48)			(0.69)
Canada crude oil – WTI (US$/bbl)		(10.21)			(18.52)			(9.99)			(10.42)			(33.27)			(16.61)			(16.31)

(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 sales price for the second quarter of 2019 averaged $74.42/bbl, an increase of 12% compared to the previous quarter, and directionally in line with changes in WTI benchmark pricing. Both Bakken and Canadian crude oil price differentials improved slightly from the first quarter of 2019.  Our realized Bakken price differential improved by 8% during the quarter to average US$3.00/bbl below WTI. 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 our firm capacity on the Dakota Access Pipeline.  For the remainder of 2019, we have physical sales contracts in place for an average of 26,300 bbls/day of Bakken crude oil production with fixed differentials averaging approximately US$2.66/bbl below WTI.  Based on year to date price realizations and an improved outlook for Bakken differentials in the second half of the year, we are revising our full year Bakken differential guidance to US$3.25/bbl below WTI (from US$4.00/bbl).

 

Our realized price differential for our Canadian crude oil production improved by US$0.43/bbl compared to the previous quarter. Canadian crude oil prices continue to be supported by the Alberta Government production curtailment program. We have fixed differential hedges in place for 1,500 bbls/day of our Canadian heavy crude oil production at an average differential of US$14.83/bbl below WTI for the remainder of 2019.

 

ENERPLUS 2019 Q2 REPORT               3

        

Our realized price for natural gas liquids averaged $17.96/bbl during the second quarter, which represents a 6% decrease compared to the previous quarter. The reduction is mainly due to the continued deterioration in propane and butane pricing.

 

NATURAL GAS

 

Our average realized natural gas price during the second quarter of 2019 decreased by 40% compared to the first quarter of 2019, to average $2.63/Mcf, while NYMEX benchmark pricing decreased by 16%. With a significant portion of our sales tied to the Transco Zone 6 Non-New York market, the change in seasonal demand from winter to spring drove lower quarter over quarter pricing in this region. This along with our first quarter physical sales at markedly higher levels than the settled benchmarks resulted in a decline in our realized sales price in the second quarter when compared to the first quarter of 2019. As expected, our realized Marcellus sales differential widened to US$0.57/Mcf below NYMEX during the second quarter. We are revising our full year differential guidance for the Marcellus of US$0.30/Mcf below NYMEX to US$0.35/Mcf. We continue to expect our realized prices to improve from current levels as seasonal heating demand increases significantly in the New York markets during the fourth quarter. 

 

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 six months of 2019 with an average exchange rate of 1.33 US/CDN compared to 1.28 US/CDN for the same period in 2018. However, when compared to the exchange rate at December 31, 2018, the Canadian dollar strengthened relative to the U.S. dollar.

 

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 August 7, 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 off 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 $0.51/Mcf on our original NYMEX hedges through this term. 

 

The following is a summary of our financial contracts in place at August 7, 2019, expressed as a percentage of our anticipated net production volumes:

 

		WTI Crude Oil (US$/bbl)(1)
		Jul 1, 2019 –		Oct 1, 2019 –		Jan 1, 2020 –
		Sep 30, 2019		Dec 31, 2019		Dec 31, 2020
Three Way Collars(2)
Sold Puts		$ 44.64		$ 44.64		—
%		66%		66%		—
Purchased Puts		$ 54.81		$ 54.81		—
%		66%		66%		—
Sold Calls		$ 65.95		$ 65.99		—
%		66%		66%		—
Put Spreads(2)
Sold Puts		—		—		$ 46.88
%		—		—		43%
Purchased Puts		—		—		$ 57.50
%		—		—		43%

(1)

Based on weighted average price (before premiums) assuming average annual production of 100,500 BOE/day, which is the mid-point of our annual 2019 guidance, less royalties and production taxes of 25%. A portion of the sold puts are settled annually rather than monthly.

(2)

The total average deferred premium on outstanding hedges is US$2.00/bbl from July 1, 2019 to December 31, 2020.

4               ENERPLUS 2019 Q2 REPORT

        

		NYMEX Natural Gas (US$/Mcf)(1)
		Jul 1, 2019 –	Aug 1, 2019 –
		Jul 31, 2019	Oct 31, 2019
Swaps
Sold Swaps		$ 2.85	$ 2.85
%		44%	44%
Bought Swaps		$ 2.34	$ 2.34
%		29%	44%

(1)

Based on weighted average price (before premiums) assuming average annual production of 100,500 BOE/day, which is the mid-point of our annual 2019 guidance, less royalties and production taxes of 25%.

 

ACCOUNTING FOR PRICE RISK MANAGEMENT

Commodity Risk Management Gains/(Losses)		Three months ended June 30,						Six months ended June 30,
($ millions)		2019			2018			2019			2018
Cash gains/(losses):
Crude oil		$	(5.9)		$	(20.1)		$	(7.8)		$	(26.4)
Natural gas			4.7			0.8			17.2			17.3
Total cash gains/(losses)		$	(1.2)		$	(19.3)		$	9.4		$	(9.1)
Non-cash gains/(losses):
Crude oil		$	23.6		$	(70.9)		$	(63.3)		$	(100.8)
Natural gas			5.0			(0.8)			(3.5)			(1.5)
Total non-cash gains/(losses)		$	28.6		$	(71.7)		$	(66.8)		$	(102.3)
Total gains/(losses)		$	27.4		$	(91.0)		$	(57.4)		$	(111.4)

 

		Three months ended June 30,						Six months ended June 30,
(Per BOE)		2019			2018			2019			2018
Total cash gains/(losses)		$	(0.13)		$	(2.28)		$	0.55		$	(0.57)
Total non-cash gains/(losses)			3.12			(8.48)			(3.90)			(6.35)
Total gains/(losses)		$	2.99		$	(10.76)		$	(3.35)		$	(6.92)

 

During the second quarter of 2019, we realized cash losses of $5.9 million on our crude oil contracts and cash gains of $4.7 million on our natural gas contracts. In comparison, during the second quarter of 2018, we realized cash losses of $20.1 million on our crude oil contracts and cash gains of $0.8 million on our natural gas contracts. Cash losses in the second quarter of 2019 on our crude oil contracts were primarily due to premiums paid on expiring three-way collars. Cash gains on our natural gas contracts were primarily due to 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 the end of the second quarter of 2019, the fair value of our crude oil contracts was in a net asset position of $17.2 million and the fair value of our natural gas contracts was in a net asset position of $7.4 million. For the three and six months ended June 30, 2019, the change in the fair value of our crude oil contracts represented gains of $23.6 million and losses of $63.3 million, respectively, and our natural gas contracts represented gains of $5.0 million and losses of $3.5 million, respectively.

Revenues

 

		Three months ended June 30,						Six months ended June 30,
($ millions)		2019			2018			2019			2018
Oil and natural gas sales		$	403.2		$	406.8		$	759.6		$	735.3
Royalties			(81.7)			(79.4)			(150.7)			(142.9)
Oil and natural gas sales, net of royalties		$	321.5		$	327.4		$	608.9		$	592.4

 

Oil and natural gas sales, net of royalties, for the three and six months ended June 30, 2019, were $321.5 million and $608.9 million, respectively, a decrease of 2% and an increase of 3% from the same periods in 2018. The decrease in revenue during the second quarter of 2019 was a result of lower crude oil and natural gas liquids prices,  partially offset by higher production volumes compared to the same period in 2018. The increase in revenue during the six month period ended June 30, 2019 was a result of higher production volumes and natural gas prices, partially offset by lower crude oil and natural gas liquids prices compared to the same period in 2018.

ENERPLUS 2019 Q2 REPORT               5

        

Royalties and Production Taxes

 

		Three months ended June 30,						Six months ended June 30,
($ millions, except per BOE amounts)		2019			2018			2019			2018
Royalties		$	81.7		$	79.4		$	150.7		$	142.9
Per BOE		$	8.92		$	9.40		$	8.79		$	8.87
Production taxes		$	21.4		$	22.6		$	36.1		$	38.8
Per BOE		$	2.34		$	2.68		$	2.11		$	2.41
Royalties and production taxes		$	103.1		$	102.0		$	186.8		$	181.7
Per BOE		$	11.26		$	12.08		$	10.90		$	11.28
Royalties and production taxes (% of oil and natural gas sales)			26%			25%			25%			25%

 

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 six months ended June 30, 2019, royalties and production taxes increased slightly to $103.1 million and $186.8 million, respectively, from $102.0 million and $181.7 million for the same periods in 2018, primarily due to higher U.S. crude oil sales.

 

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

Operating Expenses

 

		Three months ended June 30,						Six months ended June 30,
($ millions, except per BOE amounts)		2019			2018			2019			2018
Cash operating expenses		$	71.8		$	61.0		$	141.6		$	114.7
Non-cash (gains)/losses(1)			—			(0.1)			—			(0.1)
Total operating expenses		$	71.8		$	60.9		$	141.6		$	114.6
Per BOE		$	7.84		$	7.20		$	8.26		$	7.12

(1)

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

 

For the three and six months ended June 30, 2019, operating expenses were $71.8 million or $7.84/BOE and $141.6 million or $8.26/BOE, respectively, representing an increase of $10.9 million and $27.0 million from the same periods in 2018. The increase is mainly attributable to our higher North Dakota crude oil and natural gas liquids volumes, higher gas facility charges and well service activity in 2019.

 

We are reducing our annual operating cost guidance of $8.00/BOE to $7.90/BOE. 

 

Transportation Costs

 

		Three months ended June 30,						Six months ended June 30,
($ millions, except per BOE amounts)		2019			2018			2019			2018
Transportation costs		$	36.8		$	30.1		$	68.1		$	57.0
Per BOE		$	4.02		$	3.56		$	3.97		$	3.54

 

For the three and six months ended June  30, 2019, transportation costs were $36.8 million or $4.02/BOE and $68.1 million or $3.97/BOE, respectively, compared to our annual guidance of $4.00/BOE. During the same periods in 2018, transportation costs were $30.1 million or $3.56/BOE and $57.0 million or $3.54/BOE. The increase is due to additional crude oil firm transportation commitments that provide access to sell a portion of our production at the U.S. Gulf Coast or Brent pricing that commenced March 1, 2019 and a weaker Canadian dollar when compared to the prior periods. 

 

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

6               ENERPLUS 2019 Q2 REPORT

        

Netbacks

 

The crude oil and natural gas classifications below contain properties according to their dominant production category. These properties may include associated crude oil, natural gas or natural gas liquids volumes which have been converted to the equivalent BOE/day or Mcfe/day and as such, the revenue per BOE or per Mcfe may not correspond with the average selling price under the “Pricing” section of this MD&A.

 

		Three months ended June 30, 2019
Netbacks by Property Type		Crude Oil			Natural Gas			Total
Average Daily Production		56,602 BOE/day			264,554 Mcfe/day			100,694 BOE/day
Netback(1) $ per BOE or Mcfe		(per BOE)			(per Mcfe)			(per BOE)
Oil and natural gas sales		$	65.29		$	2.78		$	44.00
Royalties and production taxes			(17.51)			(0.54)			(11.26)
Cash operating expenses			(12.54)			(0.30)			(7.84)
Transportation costs			(3.02)			(0.88)			(4.02)
Netback before hedging		$	32.22		$	1.06		$	20.88
Cash hedging gains/(losses)			(1.14)			0.19			(0.13)
Netback after hedging		$	31.08		$	1.25		$	20.75
Netback before hedging ($ millions)		$	166.0		$	25.5		$	191.5
Netback after hedging ($ millions)		$	160.1		$	30.2		$	190.3

 

 

		Three months ended June 30, 2018
Netbacks by Property Type		Crude Oil			Natural Gas			Total
Average Daily Production		53,624 BOE/day			235,554 Mcfe/day			92,883 BOE/day
Netback(1) $ per BOE or Mcfe		(per BOE)			(per Mcfe)			(per BOE)
Oil and natural gas sales		$	71.65		$	2.67		$	48.13
Royalties and production taxes			(18.66)			(0.51)			(12.08)
Cash operating expenses			(10.95)			(0.35)			(7.21)
Transportation costs			(2.41)			(0.86)			(3.56)
Netback before hedging		$	39.63		$	0.95		$	25.28
Cash hedging gains/(losses)			(4.12)			0.04			(2.28)
Netback after hedging		$	35.51		$	0.99		$	23.00
Netback before hedging ($ millions)		$	193.4		$	20.3		$	213.7
Netback after hedging ($ millions)		$	173.3		$	21.1		$	194.4

 

		Six months ended June 30, 2019
Netbacks by Property Type		Crude Oil			Natural Gas			Total
Average Daily Production		52,767 BOE/day			251,426 Mcfe/day			94,671 BOE/day
Netback(1) $ per BOE or Mcfe		(per BOE)			(per Mcfe)			(per BOE)
Oil and natural gas sales		$	62.64		$	3.55		$	44.33
Royalties and production taxes			(16.32)			(0.68)			(10.90)
Cash operating expenses			(13.19)			(0.34)			(8.26)
Transportation costs			(2.90)			(0.89)			(3.97)
Netback before hedging		$	30.23		$	1.64		$	21.20
Cash hedging gains/(losses)			(0.82)			0.38			0.55
Netback after hedging		$	29.41		$	2.02		$	21.75
Netback before hedging ($ millions)		$	288.6		$	74.5		$	363.1
Netback after hedging ($ millions)		$	280.8		$	91.7		$	372.5

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

 

 

 

 

 

 

 

 

 

 

ENERPLUS 2019 Q2 REPORT               7

        

		Six months ended June 30, 2018
Netbacks by Property Type		Crude Oil			Natural Gas			Total
Average Daily Production		48,890 BOE/day			240,678 Mcfe/day			89,003 BOE/day
Netback(1) $ per BOE or Mcfe		(per BOE)			(per Mcfe)			(per BOE)
Oil and natural gas sales		$	67.73		$	3.12		$	45.65
Royalties and production taxes			(17.67)			(0.58)			(11.28)
Cash operating expenses			(10.87)			(0.42)			(7.12)
Transportation costs			(2.26)			(0.86)			(3.54)
Netback before hedging		$	36.93		$	1.26		$	23.71
Cash hedging gains/(losses)			(2.99)			0.40			(0.57)
Netback after hedging		$	33.94		$	1.66		$	23.14
Netback before hedging ($ millions)		$	326.8		$	55.1		$	381.9
Netback after hedging ($ millions)		$	300.4		$	72.4		$	372.8

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

 

Crude oil netbacks before hedging for the three and six months ended June 30, 2019 were lower compared to the same periods in 2018 primarily due to weaker realized prices and higher operating and transportation expenses. Natural gas netbacks before hedging were higher for the three and six months ended June 30, 2019 compared to the same periods in 2018 mainly due to higher realized prices. For the three and six months ended June 30, 2019, our crude oil properties accounted for 87% and 79% of our total netback before hedging, respectively, compared to 91% and 86% 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.

 

		Three months ended June 30,						Six months ended June 30,
($ millions)		2019			2018			2019			2018
Cash:
G&A expense		$	11.5		$	12.1		$	23.9		$	25.3
Share-based compensation expense			(0.6)			0.5			0.7			2.4
Non-Cash:
Share-based compensation expense			4.3			5.0			12.3			14.1
Equity swap loss/(gain)			0.2			(0.4)			0.1			(1.4)
G&A expense			0.3			—			0.4			—
Total G&A expenses		$	15.7		$	17.2		$	37.4		$	40.4

 

		Three months ended June 30,						Six months ended June 30,
(Per BOE)		2019			2018			2019			2018
Cash:
G&A expense		$	1.26		$	1.44		$	1.39		$	1.57
Share-based compensation expense			(0.07)			0.05			0.04			0.16
Non-Cash:
Share-based compensation expense			0.47			0.59			0.72			0.87
Equity swap loss/(gain)			0.03			(0.04)			0.01			(0.09)
G&A expense			0.03			—			0.02			—
Total G&A expenses		$	1.72		$	2.04		$	2.18		$	2.51

 

For the three and six months ended June  30, 2019, cash G&A expenses were $11.5 million or $1.26/BOE and $23.9 million or $1.39/BOE, respectively, compared to $12.1 million or $1.44/BOE and $25.3 million or $1.57/BOE for the same periods in 2018. Cash G&A expenses decreased on a per BOE basis compared to the same periods in 2018, due to higher production. 

 

During the second quarter of 2019, we reported a  cash SBC recovery of $0.6 million due to the decrease in our share price on outstanding deferred share units. In comparison, during the same period of 2018, we recorded cash SBC expense of $0.5 million due to an increase in our share price on outstanding deferred share units.  We recorded non-cash SBC expense of $4.3 million or $0.47/BOE in the second quarter of 2019, a decrease from an expense of $5.0 million or $0.59/BOE during the same period in 2018. 

 

8               ENERPLUS 2019 Q2 REPORT

        

We have hedges in place on a portion of the outstanding cash-settled grants under our LTI plans. In the second 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, compared to a gain of $0.4 million recorded for the same period in 2018. We had 264,000 units outstanding, hedged at a weighted average price of $17.82 per share at June 30, 2019.

 

Based on higher annual production levels we are lowering our annual cash G&A guidance to $1.45/BOE from $1.50/BOE.  

Interest Expense

 

For the three and six months ended June 30, 2019, we recorded total interest expense of $8.7 million and $17.1 million, respectively, compared to $9.2 million and $18.4 million for the same periods in 2018. The decrease in interest expense for the three and six months ended June 30, 2019 compared to the same periods in 2018 was primarily due to the repayment of a portion of our 2009 and 2012 senior notes, partially offset by a weaker Canadian dollar on our U.S. dollar denominated interest expense.

 

At June 30, 2019, all of our debt was based on fixed interest rates, with a weighted average interest rate of 4.7%. See Note 8 to the Interim Financial Statements for further details.

 

Foreign Exchange

 

		Three months ended June 30,						Six months ended June 30,
($ millions)		2019			2018			2019			2018
Realized:
Foreign exchange (gain)/loss on settlements		$	0.1		$	0.2		$	—		$	0.3
Translation of U.S. dollar cash held in Canada (gain)/loss			4.1			(3.7)			9.3			(11.0)
Unrealized (gain)/loss			(16.5)			12.4			(33.6)			30.0
Total foreign exchange (gain)/loss		$	(12.3)		$	8.9		$	(24.3)		$	19.3
USD/CDN average exchange rate			1.34			1.29			1.33			1.28
USD/CDN period end exchange rate			1.31			1.31			1.31			1.31

 

For the three and six months ended June 30, 2019, we recorded foreign exchange gains of $12.3 million and $24.3 million, respectively, compared to losses of $8.9 million and $19.3 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 our U.S. dollar denominated cash held in Canada, while unrealized gains and losses are recorded on the translation of our U.S. dollar denominated debt and working capital at each period end. Comparing the period end exchange rate at June 30, 2019 to December 31, 2018, the Canadian dollar strengthened relative to the U.S. dollar, resulting in an unrealized gain of $33.6 million. See Note 13 to the Interim Financial Statements for further details.

Capital Investment

 

		Three months ended June 30,						Six months ended June 30,
($ millions)		2019			2018			2019			2018
Capital spending(1)		$	207.2		$	177.1		$	368.0		$	328.6
Office capital(1)			2.1			2.3			3.3			3.7
Line fill			—			—			5.1			—
Sub-total			209.3			179.4			376.4			332.3
Property and land acquisitions		$	1.9		$	2.4		$	4.9		$	14.7
Property divestments			(9.6)			0.2			(10.1)			(6.8)
Sub-total			(7.7)			2.6			(5.2)			7.9
Total		$	201.6		$	182.0		$	371.2		$	340.2

(1)

Excludes changes in non-cash investing working capital. See Note 18(b) to the Interim Financial Statements for further details.

 

Capital spending for the three and six months ended June 30, 2019 totaled $207.2 million and $368.0 million, respectively, compared to the spending of $177.1 million and $328.6 million for the same periods in 2018. The increase in spending is in line with our strategy to deliver production and liquids growth through 2019. During the second quarter, we spent $186.6 million on our U.S. crude oil properties, $13.7 million on our Marcellus natural gas assets and $6.1 million on our Canadian waterflood properties. During the six months ended June 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.

 

ENERPLUS 2019 Q2 REPORT               9

        

In the second quarter of 2019, we completed $1.9 million in property and land acquisitions, which included minor interests in leases and undeveloped land, compared to $2.4 million for the same period in 2018. Property divestments for the three months ended June 30, 2019 were $9.6 million, which primarily related to the divestment of properties in Southeastern Saskatchewan with associated production of approximately 350 bbls/day.  

 

We are narrowing our 2019 annual capital spending guidance range to $610 million – $630 million from $590 million – $630 million.

 

Depletion, Depreciation and Accretion (“DD&A”)

 

		Three months ended June 30,						Six months ended June 30,
($ millions, except per BOE amounts)		2019			2018			2019			2018
DD&A expense		$	88.3		$	73.2		$	164.2		$	137.2
Per BOE		$	9.64		$	8.66		$	9.58		$	8.52

 

DD&A of property, plant and equipment (“PP&E”) is recognized using the unit-of-production method based on proved reserves. For the three and six months ended June 30, 2019, DD&A increased to $88.3 million and $164.2 million, respectively, compared to $73.2 million and $137.2 million for the same periods in 2018, as a result of additional U.S. production with higher depletion rates and a weaker Canadian dollar. 

 

Asset Retirement Obligation

 

In connection with our operations, we incur abandonment, reclamation and remediation costs related to assets such as surface leases, wells, facilities and pipelines. Total asset retirement obligations included on our balance sheet are based on management’s estimate of our net ownership interest, costs to abandon, reclaim and remediate and the timing of the costs to be incurred in future periods. We have estimated the net present value of our asset retirement obligation, using a weighted average credit-adjusted risk-free rate of 5.55%, to be $127.1 million at June 30, 2019, compared to 5.59% and $126.1 million at December 31, 2018. For the three and six months ended June 30, 2019, asset retirement obligation settlements were $0.5 million and $5.9 million, respectively, compared to $2.1 million and $5.4 million during the same periods in 2018. See Note 9 to the Interim Financial Statements for further details. 

 

Leases

 

On January 1, 2019, we adopted ASU 842 – Leases, which requires the recognition of ROU assets and lease liabilities on the Condensed Consolidated Balance Sheet for qualifying leases with a term greater than 12 months. We incur lease payments related to office space, drilling rig commitments, vehicles and other equipment. Total lease liabilities included on our balance sheet are based on the present value of lease payments over the lease term. Total ROU assets included on our balance sheet represent our right to use an underlying asset for the lease term. At June 30, 2019, our total lease liability was $61.1 million. In addition, ROU assets of $60.7 million were recorded, which equates to our lease liabilities less non-cash lease incentives. See Note 3(a) and Note 10 to the Interim Financial Statements for further details.

Income Taxes

 

		Three months ended June 30,						Six months ended June 30,
($ millions)		2019			2018			2019			2018
Current tax expense/(recovery)		$	(13.9)		$	0.1		$	(19.5)		$	0.1
Deferred tax expenses/(recovery)			48.8			3.2			30.9			15.7
Total tax expense/(recovery)		$	34.9		$	3.3		$	11.4		$	15.8

 

For the three and six months ended June 30, 2019, we recorded a current tax recovery of $13.9 and $19.5 million, respectively, compared to an expense of $0.1 million for each of the same periods in 2018. The recoveries primarily relate to the favorable settlement of a tax dispute in Canada in the second quarter of 2019 and the reversal of the reserve recorded at December 31, 2018 for the sequestered portion of our U.S. AMT refund in the first quarter of 2019.

 

For the three and six months ended June 30, 2019, we recorded deferred tax expense of $48.8 million and $30.9 million, respectively, compared to an expense of $3.2 million and $15.7 million, for the same periods in 2018.  The increase in the deferred tax expense during the second quarter was primarily due to a  $26.3 million expense recorded for the remeasurement of our Canadian net deferred income tax asset for the change in the Alberta corporate income tax rate from 12% to 8% by 2022.  See Note 14 to the Interim Financial Statements for further details.

10               ENERPLUS 2019 Q2 REPORT

        

LIQUIDITY AND CAPITAL RESOURCES

 

There are numerous factors that influence how we assess our liquidity and leverage, including commodity price cycles, capital spending levels, acquisition and divestment plans, hedging, share repurchases and dividend levels. We also assess our leverage relative to our most restrictive debt covenant under our bank credit facility and senior notes, which is a maximum senior debt to earnings before interest, taxes, depreciation, amortization, impairment and other non-cash charges (“adjusted EBITDA”) ratio of 3.5x for a period of up to six months, after which it drops to 3.0x. At June 30, 2019, our senior debt to adjusted EBITDA ratio was 0.8x and our net debt to adjusted funds flow ratio was 0.5x. Although it is not included in our debt covenants, the net debt to adjusted funds flow ratio is often used by investors and analysts to evaluate our liquidity.

 

Total debt net of cash at June 30, 2019 was $359.0 million, an increase of 8% compared to $333.5 million at December 31, 2018. Total debt was comprised of $611.5 million of senior notes less $252.5 million in cash. During the second quarter, we repaid a portion of our 2009 and 2012 senior notes, resulting in a  $59.4 million decrease to our outstanding debt. 

 

Our adjusted payout ratio, which is calculated as cash dividends plus capital, office expenditures and line fill divided by adjusted funds flow, was 116%  and 110%  for the three and six months ended June 30, 2019, respectively, compared to 107% and 106% for the same periods in 2018.

 

For the three months ended June 30, 2019, the Company repurchased and cancelled approximately 6.6 million shares under our NCIB for a total cost of $70.6 million. In total in 2019, the Company has allocated $90.4 million in capital to the repurchase and cancellation of approximately 8.4 million shares under our current and previous NCIB.

 

Our working capital deficiency, excluding cash and current derivative financial assets and liabilities, increased to $269.3 million at June 30, 2019 from $143.1 million at December 31, 2018. This increase is primarily due to the reclassification of a portion of our 2009 and 2012 senior notes from long-term debt to current liabilities and an increase in accounts payable due to higher capital spending in the second quarter of 2019 when compared to the fourth quarter of 2018.  We expect to finance our working capital deficit and our ongoing working capital requirements through cash, cash flow from operations and our $800 million bank credit facility. We have sufficient liquidity to meet our financial commitments, as disclosed under “Commitments” in the Annual MD&A.

 

At June 30, 2019, we were in compliance with all covenants under our bank credit facility and outstanding senior notes. Our bank credit facility and senior note purchase agreements have been filed under our SEDAR profile at www.sedar.com.    

 

Our net debt to adjusted funds flow remains at 0.5x and the following table lists our financial covenants as at June 30, 2019: 

 

Covenant Description				June 30, 2019
Bank Credit Facility:		Maximum Ratio
Senior debt to adjusted EBITDA (1)		3.5x		0.8x
Total debt to adjusted EBITDA (1)		4.0x		0.8x
Total debt to capitalization		50%		17%
Senior Notes:		Maximum Ratio
Senior debt to adjusted EBITDA (1)(2)		3.0x - 3.5x		0.8x
Senior debt to consolidated present value of total proved reserves(3)		60%		18%
		Minimum Ratio
Adjusted EBITDA to interest (1)		4.0x		21.6x

 

Definitions

“Senior debt” is calculated as the sum of drawn amounts on our bank credit facility, outstanding letters of credit and the principal amount of senior notes.

“Adjusted EBITDA” is calculated as net income less interest, taxes, depletion, depreciation, amortization, impairment and other non-cash gains and losses. Adjusted EBITDA is calculated on a trailing twelve-month basis and is adjusted for material acquisitions and divestments. Adjusted EBITDA for the three months and the trailing twelve months ended June  30, 2019 was $176.6 million and $767.5 million, respectively.

“Total debt” is calculated as the sum of senior debt plus subordinated debt. Enerplus currently does not have any subordinated debt.

“Capitalization” is calculated as the sum of total debt and shareholder’s equity plus a $1.1 billion adjustment related to our adoption of U.S. GAAP.

 

Footnotes

(1)See “Non-GAAP Measures” in this MD&A for a reconciliation of adjusted EBITDA to net income.

(2)Senior debt to adjusted EBITDA for the senior notes may increase to 3.5x for a period of 6 months, after which the ratio decreases to 3.0x.

(3)Senior debt to consolidated present value of total proved reserves is calculated annually on December 31 based on before tax reserves at forecast prices discounted at 10%.

 

ENERPLUS 2019 Q2 REPORT               11

        

Dividends

 

		Three months ended June 30,						Six months ended June 30,
($ millions, except per share amounts)		2019			2018			2019			2018
Dividends to shareholders(1)		$	7.0		$	7.3		$	14.2		$	14.7
Per weighted average share (Basic)		$	0.03		$	0.03		$	0.06		$	0.06

(1)

Excludes changes in non-cash financing working capital. See Note 18(b) to the Interim Financial Statements for further details.

 

During the three and six months ended June 30, 2019, we reported total dividends of $7.0 million or $0.03 per share and $14.2 million or $0.06 per share, respectively, compared to $7.3 million or $0.03 per share and $14.7 million or $0.06 per share for the same periods in 2018.

 

The dividend is part of our strategy to return capital to our shareholders. We continue to monitor commodity prices and economic conditions and are prepared to make adjustments as necessary.

 

Shareholders’ Capital

 

		Six months ended June 30,
		2019			2018
Share capital ($ millions)		$	3,225.6		$	3,415.0
Common shares outstanding (thousands)			231,616			244,984
Weighted average shares outstanding – basic (thousands)			237,197			244,369
Weighted average shares outstanding – diluted (thousands)			239,947			249,367

 

For the six months ended June 30, 2019, a total of 1,007,234 units vested pursuant to our treasury settled LTI plans (2018 – 2,539,498). In total, 564,000 shares were issued from treasury and $4.4 million was transferred from paid-in capital to share capital (2018 – 2,539,498; $23.4 million). We elected to cash settle the remaining units related to the required tax withholdings (2019 – $5.0 million, 2018 – nil).

 

For the six months ended June 30, 2019, no shares were issued pursuant to our stock option plan, resulting in no additional share capital (2018 – 315,843; $4.3 million).

 

On March 21, 2019, Enerplus announced the renewal of its NCIB to purchase up to 16,673,015 common shares, representing 7% of the "public float" of Enerplus (within the meaning under the rules of the Toronto Stock Exchange (the "TSX")) through the facilities of the TSX, the New York Stock Exchange and/or alternative Canadian trading systems during the 12-month period ending March 25, 2020.

 

During the six months ended June 30, 2019, the Company repurchased 8,358,821 common shares under the previous and current NCIB at an average price of $10.80 per share, for total consideration of $90.4 million. Of the amount paid, $116.4 million was charged to share capital and $26.0 million was credited to accumulated deficit. Subsequent to the quarter and up to August 7, 2019, the Company repurchased 981,266 common shares under the NCIB at an average price of $8.97 per share, for total consideration of $8.8 million.

 

On May 23, 2019, we filed a short form base shelf prospectus (the “Shelf Prospectus”) with securities regulatory authorities in each of the provinces of Canada and a Registration Statement with the U.S. Securities Exchange Commission. The Shelf Prospectus allows us to offer and issue up to an aggregate amount of $2.0 billion of common shares, preferred shares, warrants, subscription receipts and units by way of one or more prospectus supplements during the 25-month period that the Shelf Prospectus remains in place.

 

At August 7, 2019, we had 230,635,015 common shares outstanding. In addition, an aggregate of 7,958,372 common shares may be issued to settle outstanding grants under the Performance Share Unit (“PSU”), Restricted Share Unit, and stock option plans, assuming the maximum payout multiplier of 2.0 times for the PSUs.

 

For further details, see Note 15 to the Interim Financial Statements.

 

12               ENERPLUS 2019 Q2 REPORT

        

SELECTED CANADIAN AND U.S. FINANCIAL RESULTS

 

		Three months ended June 30, 2019									Three months ended June 30, 2018
($ millions, except per unit amounts)		Canada			U.S.			Total			Canada			U.S.			Total
Average Daily Production Volumes(1)
Crude oil (bbls/day)			8,749			39,392			48,141			9,212			36,030			45,242
Natural gas liquids (bbls/day)			931			3,789			4,720			1,055			3,753			4,808
Natural gas (Mcf/day)			23,120			263,880			287,000			29,151			227,844			256,995
Total average daily production (BOE/day)			13,533			87,161			100,694			15,126			77,757			92,883
Pricing(2)
Crude oil (per bbl)		$	67.12		$	76.04		$	74.42		$	66.58		$	83.41		$	79.98
Natural gas liquids (per bbl)			25.31			16.16			17.96			50.20			27.18			32.23
Natural gas (per Mcf)			1.82			2.71			2.63			2.07			2.76			2.68
Capital Expenditures
Capital spending		$	7.0		$	200.2		$	207.2		$	11.4		$	165.7		$	177.1
Acquisitions			1.1			0.8			1.9			1.0			1.4			2.4
Divestments			(9.4)			(0.2)			(9.6)			0.2			—			0.2
Netback(3) Before Hedging
Oil and natural gas sales		$	60.1		$	343.1		$	403.2		$	66.9		$	339.9		$	406.8
Royalties			(12.7)			(69.0)			(81.7)			(10.7)			(68.7)			(79.4)
Production taxes			(0.2)			(21.2)			(21.4)			(0.7)			(21.9)			(22.6)
Cash operating expenses			(17.5)			(54.3)			(71.8)			(17.7)			(43.3)			(61.0)
Transportation costs			(2.6)			(34.2)			(36.8)			(2.8)			(27.3)			(30.1)
Netback before hedging		$	27.1		$	164.4		$	191.5		$	35.0		$	178.7		$	213.7
Other Expenses
Commodity derivative instruments loss/(gain)		$	(27.4)		$	—		$	(27.4)		$	91.0		$	—		$	91.0
Total G&A(4)			(1.9)			17.6			15.7			6.3			10.9			17.2
Current income tax expense/(recovery)			(13.9)			—			(13.9)			—			0.1			0.1

 

		Six months ended June 30, 2019									Six months ended June 30, 2018
($ millions, except per unit amounts)		Canada			U.S.			Total			Canada			U.S.			Total
Average Daily Production Volumes(1)
Crude oil (bbls/day)			8,873			35,769			44,642			9,362			32,002			41,364
Natural gas liquids (bbls/day)			957			3,595			4,552			1,151			3,298			4,449
Natural gas (Mcf/day)			23,730			249,133			272,863			31,131			228,010			259,141
Total average daily production (BOE/day)			13,785			80,886			94,671			15,701			73,302			89,003
Pricing(2)
Crude oil (per bbl)		$	63.06		$	72.75		$	70.82		$	59.63		$	79.94		$	75.34
Natural gas liquids (per bbl)			30.71			15.29			18.53			47.46			24.39			30.36
Natural gas (per Mcf)			3.26			3.48			3.46			2.63			3.16			3.09
Capital Expenditures
Capital spending		$	24.5		$	343.5		$	368.0		$	24.6		$	304.0		$	328.6
Acquisitions			2.1			2.8			4.9			2.1			12.6			14.7
Divestments			(9.5)			(0.6)			(10.1)			(0.7)			(6.1)			(6.8)
Netback(3) Before Hedging
Oil and natural gas sales		$	121.9		$	637.7		$	759.6		$	127.6		$	607.7		$	735.3
Royalties			(21.7)			(129.0)			(150.7)			(20.7)			(122.2)			(142.9)
Production taxes			(0.9)			(35.2)			(36.1)			(1.5)			(37.3)			(38.8)
Cash operating expenses			(38.4)			(103.2)			(141.6)			(38.2)			(76.5)			(114.7)
Transportation costs			(5.3)			(62.8)			(68.1)			(5.8)			(51.2)			(57.0)
Netback before hedging		$	55.6		$	307.5		$	363.1		$	61.4		$	320.5		$	381.9
Other Expenses
Commodity derivative instruments loss/(gain)		$	57.4		$	—		$	57.4		$	111.4		$	—		$	111.4
Total G&A(4)			11.3			26.1			37.4			21.7			18.7			40.4
Current income tax expense/(recovery)			(14.0)			(5.5)			(19.5)			—			0.1			0.1

(1)Company interest volumes.

(2)Before transportation costs, royalties and the effects of commodity derivative instruments.

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

(4)Includes share-based compensation expense. 

 

ENERPLUS 2019 Q2 REPORT               13

        

QUARTERLY FINANCIAL INFORMATION

 

		Oil and Natural Gas						Net Income/(Loss) Per Share
($ millions, except per share amounts)		Sales, Net of Royalties			Net Income/(Loss)			Basic			Diluted
2019
Second Quarter		$	321.4		$	85.1		$	0.36		$	0.36
First Quarter			287.5			19.2			0.08			0.08
Total 2019		$	608.9		$	104.3		$	0.44		$	0.43
2018
Fourth Quarter		$	326.7		$	249.4		$	1.03		$	1.02
Third Quarter			373.6			86.9			0.35			0.35
Second Quarter			327.4			12.4			0.05			0.05
First Quarter			265.0			29.6			0.12			0.12
Total 2018		$	1,292.7		$	378.3		$	1.55		$	1.53
2017
Fourth Quarter		$	271.1		$	15.3		$	0.06		$	0.06
Third Quarter			196.1			16.1			0.07			0.07
Second Quarter			225.7			129.3			0.53			0.52
First Quarter			227.8			76.3			0.32			0.31
Total 2017		$	920.7		$	237.0		$	0.98		$	0.96

 

Oil and natural gas sales, net of royalties, increased by $34.0 million in the second quarter of 2019 compared to the first quarter of 2019, due to increased production volumes. Net income increased in the second quarter of 2019 due to increased sales and a gain of $27.4 million on commodity derivative instruments, compared to a loss of $84.9 million during the first quarter of 2019.

 

Oil and natural gas sales, net of royalties, improved in 2018 compared to 2017 due to an increase in realized commodity prices and a higher weighting of crude oil and natural gas liquids as a proportion of total production. As a result, net income also improved in 2018, excluding the effects of a gain which was recorded on asset divestments in the second quarter of 2017.

 

U.S. Filing Status

 

Pursuant to U.S. securities regulations, we are required to reassess our U.S. securities filing status annually at June 30. As at June 30, 2019, we continued to qualify as a foreign private issuer for the purposes of U.S. reporting requirements.

 

2019 UPDATED GUIDANCE

 

We are increasing our average annual production guidance to 99,000 – 102,000 BOE/day and revising our average annual crude oil and natural gas liquids guidance to 54,000 – 55,500 bbls/day. 

 

We are narrowing our 2019 capital spending guidance to $610 – $630 million from our previous range of $590 – $630 million. With higher average annual production, we are reducing our annual operating expense guidance to $7.90/BOE from $8.00/BOE and reducing our annual cash G&A guidance to $1.45/BOE from $1.50/BOE.

 

We are decreasing our full year Bakken differential guidance to US$3.25/bbl below WTI from US$4.00/bbl. We are also increasing our full year Marcellus differential guidance to US$0.35/Mcf below NYMEX from $0.30/Mcf.

 

All other guidance targets remain unchanged. This guidance does not include any additional acquisitions or divestments.

 

Summary of 2019 Expectations		Target
Capital spending		$610 - $630 million (from $590 - $630 million)
Average annual production		99,000 - 102,000 BOE/day (from 97,000 - 101,000 BOE/day)
Average annual crude oil and natural gas liquids production		54,000 - 55,500 bbls/day (from 53,500 - 56,000 bbls/day)
Average royalty and production tax rate (% of gross sales, before transportation)		25%
Operating expenses		$7.90/BOE (from $8.00/BOE)
Transportation costs		$4.00/BOE
Cash G&A expenses		$1.45/BOE (from $1.50/BOE)

 

2019 Differential/Basis Outlook(1)		Target
Average U.S. Bakken crude oil differential (compared to WTI crude oil)		US$(3.25)/bbl (from US$(4.00)/bbl)
Average Marcellus natural gas sales price differential (compared to NYMEX natural gas)		US$(0.35)/Mcf (from US$(0.30)/Mcf)

(1)

Excludes transportation costs.

 

14               ENERPLUS 2019 Q2 REPORT

        

NON-GAAP MEASURES

 

The Company utilizes the following terms for measurement within the MD&A that do not have a standardized meaning or definition as prescribed by U.S. GAAP and, therefore, may not be comparable with the calculation of similar measures by other entities:

 

“Netback” is used by Enerplus and is useful to investors and securities analysts in evaluating operating performance of our crude oil and natural gas assets. Netback is calculated as oil and natural gas sales less royalties, production taxes, cash operating expenses and transportation costs.

 

Calculation of Netback		Three months ended June 30,						Six months ended June 30,
($ millions)		2019			2018			2019			2018
Oil and natural gas sales		$	403.2		$	406.8		$	759.6		$	735.3
Less:
Royalties			(81.7)			(79.4)			(150.7)			(142.9)
Production taxes			(21.4)			(22.6)			(36.1)			(38.8)
Cash operating expenses			(71.8)			(61.0)			(141.6)			(114.7)
Transportation costs			(36.8)			(30.1)			(68.1)			(57.0)
Netback before hedging		$	191.5		$	213.7		$	363.1		$	381.9
Cash gains/(losses) on derivative instruments			(1.2)			(19.3)			9.4			(9.1)
Netback after hedging		$	190.3		$	194.4		$	372.5		$	372.8

 

“Adjusted funds flow” is used by Enerplus and is useful to investors and securities analysts in analyzing operating and financial performance, leverage and liquidity. Adjusted funds flow is calculated as cash flow from operating activities before asset retirement obligation expenditures and changes in non-cash operating working capital.

 

Reconciliation of Cash Flow from Operating Activities to Adjusted Funds Flow		Three months ended June 30,						Six months ended June 30,
($ millions)		2019			2018			2019			2018
Cash flow from operating activities		$	237.0		$	141.8		$	345.9		$	301.1
Asset retirement obligation expenditures			0.5			2.0			5.9			5.4
Changes in non-cash operating working capital			(51.5)			29.9			3.0			22.4
Adjusted funds flow		$	186.0		$	173.7		$	354.8		$	328.9

 

“Free cash flow” is used by Enerplus and is useful to investors and securities analysts in analyzing operating and financial performance, leverage and liquidity. Free cash flow is calculated as adjusted funds flow minus capital spending.

 

Calculation of Free Cash Flow	Three months ended June 30,						Six months ended June 30,
($ millions)	2019			2018			2019			2018
Adjusted funds flow	$	186.0		$	173.7		$	354.8		$	328.9
Capital spending		(207.2)			(177.1)			(368.0)			(328.6)
Free cash flow	$	(21.2)		$	(3.4)		$	(13.2)		$	0.3

 

“Adjusted net income” is used by Enerplus and is useful to investors and securities analysts in evaluating the financial performance of the Company by understanding the impact of certain non-cash items and other items that the Company considers appropriate to adjust given the irregular nature and relevance to comparable companies. Adjusted net income is calculated as net income adjusted for unrealized derivative instrument gain/loss, unrealized foreign exchange gain/loss, the tax effect of these items and the impact of statutory changes to the Company’s corporate tax rate.

 

Calculation of Adjusted Net Income		Three months ended June 30,						Six months ended June 30,
($ millions)		2019			2018			2019			2018
Net income/(loss)		$	85.1		$	12.4		$	104.3		$	42.0
Unrealized derivative instrument (gain)/loss			(28.4)			71.2			67.0			100.8
Unrealized foreign exchange (gain)/loss			(16.5)			12.4			(33.6)			30.0
Tax effect on above items			7.8			(19.1)			(17.1)			(27.5)
Income tax rate adjustment on deferred taxes			26.3			—			26.3			—
Adjusted net income		$	74.3		$	76.9		$	146.9		$	145.3

 

“Total debt net of cash” is used by Enerplus and is useful to investors and securities analysts in analyzing leverage and liquidity. Total debt net of cash is calculated as senior notes plus any outstanding bank credit facility balance, minus cash and cash equivalents.

ENERPLUS 2019 Q2 REPORT               15

        

“Net debt to adjusted funds flow ratio” is used by Enerplus and is useful to investors and securities analysts in analyzing leverage and liquidity. The net debt to adjusted funds flow ratio is calculated as total debt net of cash divided by a trailing twelve months of adjusted funds flow. This measure is not equivalent to debt to earnings before interest, taxes, depreciation, amortization, impairment and other non-cash charges (“adjusted EBITDA”) and is not a debt covenant.

 

“Adjusted payout ratio” is used by Enerplus and is useful to investors and securities analysts in analyzing operating performance, leverage and liquidity. We calculate our adjusted payout ratio as cash dividends plus capital, office expenditures and line fill divided by adjusted funds flow.

 

Calculation of Adjusted Payout Ratio		Three months ended June 30,						Six months ended June 30,
($ millions)		2019			2018			2019			2018
Dividends		$	7.0		$	7.3		$	14.2		$	14.7
Capital, office expenditures and line fill			209.3			179.4			376.4			332.3
Sub-total		$	216.3		$	186.7		$	390.6		$	347.0
Adjusted funds flow		$	186.0		$	173.7		$	354.8		$	328.9
Adjusted payout ratio (%)			116%			107%			110%			106%

 

“Adjusted EBITDA” is used by Enerplus and its lenders to determine compliance with financial covenants under its bank credit facility and outstanding senior notes.

 

Reconciliation of Net Income to Adjusted EBITDA(1)
($ millions)		June 30, 2019
Net income/(loss)		$	440.5
Add:
Interest			35.5
Current and deferred tax expense/(recovery)			98.8
DD&A and asset impairment			331.3
Other non-cash charges(2)			(138.6)
Adjusted EBITDA		$	767.5

(1)

Adjusted EBITDA is calculated based on the trailing four quarters. Balances above at June 30, 2019 include the six months ended June  30, 2019 and the third and fourth quarter of 2018.

(2)

Includes the change in fair value of commodity derivatives and equity swaps, non-cash SBC expense, non-cash G&A expense and unrealized foreign exchange gains/losses.

 

In addition, the Company uses certain financial measures within the “Liquidity and Capital Resources” section of this MD&A that do not have a standardized meaning or definition as prescribed by U.S. GAAP and, therefore, may not be comparable with the calculation of similar measures by other entities. Such measures include “senior debt to adjusted EBITDA”, “total debt to adjusted EBITDA”, “total debt to capitalization”, “senior debt to consolidated present value of total proved reserves” and “adjusted EBITDA to interest” and are used to determine the Company’s compliance with financial covenants under its bank credit facility and outstanding senior notes. Calculation of such terms is described under the “Liquidity and Capital Resources” section of this MD&A.

INTERNAL CONTROLS AND PROCEDURES

 

Our Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of our disclosure controls and procedures and internal control over financial reporting as defined in Rule 13a - 15 under the U.S. Securities Exchange Act of 1934 and as defined in Canada under National Instrument 52-109 - Certification of Disclosure in Issuer’s Annual and Interim Filings. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of Enerplus Corporation have concluded that, as at June 30, 2019, our disclosure controls and procedures and internal control over financial reporting were effective. There were no changes in our internal control over financial reporting during the period beginning on April 1, 2019 and ended June 30, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ADDITIONAL INFORMATION

 

Additional information relating to Enerplus, including our current Annual Information Form (“AIF”), is available under our profile on the SEDAR website at www.sedar.com, on the EDGAR website at www.sec.gov and at www.enerplus.com.

 

16               ENERPLUS 2019 Q2 REPORT

        

FORWARD-LOOKING INFORMATION AND STATEMENTS

 

This MD&A contains certain forward-looking information and statements ("forward-looking information") within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", “guidance”, "ongoing", "may", "will", "project", "plans", “budget”, "strategy" and similar expressions are intended to identify forward-looking information. In particular, but without limiting the foregoing, this MD&A contains forward-looking information pertaining to the following: expected 2019 average production volumes, timing thereof and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting our adjusted funds flow; the results from our drilling program and the timing of related production; oil and natural gas prices and differentials and our commodity risk management program in 2019 and in the future; expectations regarding our realized oil and natural gas prices; future royalty rates on our production and future production taxes; anticipated cash G&A, share-based compensation and financing expenses; expected operating and transportation costs; our anticipated shares repurchases under current and future normal course issuer bids; capital spending levels in 2019 and impact thereof on our production levels and land holdings; potential future asset and goodwill impairments, as well as relevant factors that may affect such impairments; the amount of our future abandonment and reclamation costs and asset retirement obligations; future environmental expenses; our future royalty and production and U.S. cash taxes; deferred income taxes, our tax pools and the time at which we may pay Canadian cash taxes; future debt and working capital levels and net debt to adjusted funds flow ratio and adjusted payout ratio, financial capacity, liquidity and capital resources to fund capital spending and working capital requirements; expectations regarding our ability to comply with debt covenants under our bank credit facility and outstanding senior notes; our future acquisitions and dispositions, expecting timing thereof and use of proceeds therefrom; and the amount of future cash dividends that we may pay to our shareholders.

 

The forward-looking information contained in this MD&A reflects several material factors and expectations and assumptions of Enerplus including, without limitation: that we will conduct our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; that lack of adequate infrastructure will not result in curtailment of production and/or reduced realized prices beyond our current expectations; current commodity price, differentials and cost assumptions; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve and contingent resource volumes; the continued availability of adequate debt and/or equity financing and adjusted funds flow to fund our capital, operating and working capital requirements, and dividend payments as needed; the continued availability and sufficiency of our adjusted funds flow and availability under our bank credit facility to fund our working capital deficiency; the availability of third party services; and the extent of our liabilities. In addition, our updated 2019 guidance contained in this MD&A is based on the rest of the year prices of: a WTI price of US$56.00/bbl, a NYMEX price of US$2.30/Mcf, and a USD/CDN exchange rate of 1.31. Enerplus believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

 

The forward-looking information included in this MD&A is not a guarantee of future performance and should not be unduly relied upon. Such information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information including, without limitation: continued low commodity prices environment or further volatility in commodity prices; changes in realized prices of Enerplus’ products; changes in the demand for or supply of our products; unanticipated operating results, results from our capital spending activities or production declines; curtailment of our production due to low realized prices or lack of adequate infrastructure; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in our capital plans or by third party operators of our properties; increased debt levels or debt service requirements; inability to comply with debt covenants under our bank credit facility and outstanding senior notes; inaccurate estimation of our oil and gas reserve and contingent resource volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; reliance on industry partners and third party service providers; and certain other risks detailed from time to time in our public disclosure documents (including, without limitation, those risks identified in our AIF, our Annual MD&A and Form 40-F as at December 31, 2018). 

 

The forward-looking information contained in this MD&A speak only as of the date of this MD&A. Enerplus does not undertake any obligation to publicly update or revise any forward-looking information contained herein, except as required by applicable laws.

 

 

 

ENERPLUS 2019 Q2 REPORT               17

        STATEMENTS

Exhibit 99.2

Condensed Consolidated Balance Sheets

 

(CDN$ thousands) unaudited		Note		June 30, 2019			December 31, 2018
Assets
Current Assets
Cash and cash equivalents				$	252,531		$	363,327
Accounts receivable		4			158,290			145,206
Income tax receivable		14			43,542			55,172
Derivative financial assets		16			21,347			59,258
Other current assets					1,931			8,928
					477,641			631,891
Property, plant and equipment:
Oil and natural gas properties (full cost method)		5			1,456,502			1,293,941
Other capital assets, net		5			19,569			13,130
Property, plant and equipment					1,476,071			1,307,071
Right-of-use assets		3,10			60,717			—
Goodwill					646,704			654,799
Derivative financial assets		16			3,408			32,220
Deferred income tax asset		14			423,997			465,124
Income tax receivable		14			—			27,195
Total Assets				$	3,088,538		$	3,118,300
Liabilities
Current liabilities
Accounts payable		7		$	346,911		$	290,045
Dividends payable					2,318			2,395
Current portion of long-term debt		8			106,855			60,001
Derivative financial liabilities		16			2,161			1,909
Current portion of lease liabilities		3,10			16,974			—
					475,219			354,350
Long-term debt		8			504,682			636,849
Asset retirement obligation		9			127,098			126,112
Lease liabilities		3,10			44,098			—
					675,878			762,961
Total Liabilities					1,151,097			1,117,311
Shareholders’ Equity
Share capital – authorized unlimited common shares, no par value Issued and outstanding: June 30, 2019 – 232 million shares                                       December 31, 2018 – 239 million shares		15			3,225,591			3,337,608
Paid-in capital					49,472			46,524
Accumulated deficit					(1,655,999)			(1,772,084)
Accumulated other comprehensive income/(loss)					318,377			388,941
					1,937,441			2,000,989
Total Liabilities & Shareholders' Equity				$	3,088,538		$	3,118,300
Commitments and Contingencies		17
Subsequent events		15
The accompanying notes to the Condensed Consolidated Financial Statements are an integral part of these statements.

 

 

ENERPLUS 2019 Q2 REPORT               1

        

Condensed Consolidated Statements of Income/(Loss) and Comprehensive Income/(Loss)

 

				Three months ended						Six months ended
				June 30,						June 30,
(CDN$ thousands, except per share amounts) unaudited		Note		2019			2018			2019			2018
Revenues
Oil and natural gas sales, net of royalties		11		$	321,463		$	327,384		$	608,915		$	592,404
Commodity derivative instruments gain/(loss)		16			27,422			(90,951)			(57,445)			(111,415)
					348,885			236,433			551,470			480,989
Expenses
Operating					71,818			60,879			141,611			114,640
Transportation					36,803			30,123			68,094			57,044
Production taxes					21,442			22,649			36,057			38,784
General and administrative		12			15,680			17,189			37,390			40,413
Depletion, depreciation and accretion					88,315			73,165			164,226			137,211
Interest					8,693			9,249			17,086			18,352
Foreign exchange (gain)/loss		13			(12,251)			8,911			(24,277)			19,282
Other expense/(income)					(1,568)			(1,447)			(4,430)			(2,630)
					228,932			220,718			435,757			423,096
Income/(Loss) before taxes					119,953			15,715			115,713			57,893
Current income tax expense/(recovery)		14			(13,928)			72			(19,458)			138
Deferred income tax expense/(recovery)		14			48,797			3,239			30,929			15,714
Net Income/(Loss)				$	85,084		$	12,404		$	104,242		$	42,041
Other Comprehensive Income/(Loss)
Change in cumulative translation adjustment					(34,208)			27,990			(70,564)			62,358
Total Comprehensive Income/(Loss)				$	50,876		$	40,394		$	33,678		$	104,399
Net income/(Loss) per share
Basic		15		$	0.36		$	0.05		$	0.44		$	0.17
Diluted		15		$	0.36		$	0.05		$	0.43		$	0.17

 

The accompanying notes to the Condensed Consolidated Financial Statements are an integral part of these statements.

2               ENERPLUS 2019 Q2 REPORT

        

Condensed Consolidated Statements of Changes in Shareholders’ Equity

 

			Three months ended						Six months ended
			June 30,						June 30,
(CDN$ thousands) unaudited		2019			2018			2019			2018
Share Capital
Balance, beginning of period		$	3,317,855		$	3,411,878		$	3,337,608		$	3,386,946
Purchase of common shares under Normal Course Issuer Bid			(92,264)			—			(116,423)			—
Share-based compensation – treasury settled			—			—			4,406			23,389
Stock Option Plan – cash			—			2,915			—			4,344
Stock Option Plan – exercised			—			251			—			365
Balance, end of period		$	3,225,591		$	3,415,044		$	3,225,591		$	3,415,044
Paid-in Capital
Balance, beginning of period		$	45,209		$	60,951		$	46,524		$	75,375
Share-based compensation – cash settled (tax withholding)			—			—			(4,952)			—
Share-based compensation – treasury settled			—			—			(4,406)			(23,389)
Share-based compensation – non-cash			4,263			4,997			12,306			14,076
Stock Option Plan – exercised			—			(251)			—			(365)
Balance, end of period		$	49,472		$	65,697		$	49,472		$	65,697
Accumulated Deficit
Balance, beginning of period		$	(1,755,757)		$	(2,102,359)		$	(1,772,084)		$	(2,124,676)
Purchase of common shares under Normal Course Issuer Bid			21,708			—			26,039			—
Net income/(loss)			85,084			12,404			104,242			42,041
Dividends declared ($0.01 per share)			(7,034)			(7,347)			(14,196)			(14,667)
Balance, end of period		$	(1,655,999)		$	(2,097,302)		$	(1,655,999)		$	(2,097,302)
Accumulated Other Comprehensive Income/(Loss)
Balance, beginning of period		$	352,585		$	297,492		$	388,941		$	263,124
Change in cumulative translation adjustment			(34,208)			27,990			(70,564)			62,358
Balance, end of period		$	318,377		$	325,482		$	318,377		$	325,482
Total Shareholders’ Equity		$	1,937,441		$	1,708,921		$	1,937,441		$	1,708,921

 

The accompanying notes to the Condensed Consolidated Financial Statements are an integral part of these statements.

 

ENERPLUS 2019 Q2 REPORT               3

        

Condensed Consolidated Statements of Cash Flows

 

		Three months ended						Six months ended
		June 30,						June 30,
(CDN$ thousands) unaudited	Note	2019			2018			2019			2018
Operating Activities
Net income/(loss)		$	85,084		$	12,404		$	104,242		$	42,041
Non-cash items add/(deduct):
Depletion, depreciation and accretion			88,315			73,165			164,226			137,211
Changes in fair value of derivative instruments	16		(28,353)			71,213			66,975			100,835
Deferred income tax expense/(recovery)	14		48,797			3,239			30,929			15,714
Foreign exchange (gain)/loss on debt and working capital	13		(16,498)			12,386			(33,602)			30,035
Share-based compensation and general and administrative	12,15		4,535			4,997			12,669			14,076
Translation of U.S. dollar cash held in Canada	13		4,158			(3,696)			9,354			(11,042)
Asset retirement obligation expenditures	9		(503)			(2,053)			(5,893)			(5,384)
Changes in non-cash operating working capital	18		51,456			(29,888)			(2,958)			(22,419)
Cash flow from/(used in) operating activities			236,991			141,767			345,942			301,067
Financing Activities
Senior notes	8		(59,429)			(29,044)			(59,429)			(29,044)
Proceeds from the issuance of shares	15		—			2,915			—			4,344
Purchase of common shares under Normal Course Issuer Bid	15		(70,556)			—			(90,384)			—
Share-based compensation – cash settled (tax withholding)	15		—			—			(4,952)			—
Dividends	15,18		(7,099)			(7,344)			(14,273)			(14,638)
Cash flow from/(used in) financing activities			(137,084)			(33,473)			(169,038)			(39,338)
Investing Activities
Capital and office expenditures	18		(168,282)			(147,898)			(280,077)			(256,110)
Property and land acquisitions			(1,911)			(2,392)			(4,892)			(8,582)
Property divestments			9,601			(182)			10,023			706
Cash flow from/(used in) investing activities			(160,592)			(150,472)			(274,946)			(263,986)
Effect of exchange rate changes on cash and cash equivalents			(5,780)			6,205			(12,754)			16,131
Change in cash and cash equivalents			(66,465)			(35,973)			(110,796)			13,874
Cash and cash equivalents, beginning of period			318,996			396,395			363,327			346,548
Cash and cash equivalents, end of period		$	252,531		$	360,422		$	252,531		$	360,422

 

The accompanying notes to the Condensed Consolidated Financial Statements are an integral part of these statements.

 

 

4               ENERPLUS 2019 Q2 REPORT

        NOTES

Notes to Condensed Consolidated Financial Statements

(unaudited)

 

1)   REPORTING ENTITY

 

These interim Condensed Consolidated Financial Statements (“interim Consolidated Financial Statements”) and notes present the financial position and results of Enerplus Corporation (“the Company” or “Enerplus”) including its Canadian and U.S. subsidiaries. Enerplus is a North American crude oil and natural gas exploration and development company. Enerplus is publicly traded on the Toronto and New York stock exchanges under the ticker symbol ERF. Enerplus’ head office is located in Calgary, Alberta, Canada.

 

2)   BASIS OF PREPARATION

 

Enerplus’ interim Consolidated Financial Statements present its results of operations and financial position under accounting principles generally accepted in the United States of America (“U.S. GAAP”) for the three and six months ended June 30, 2019 and the 2018 comparative periods. Certain information and notes normally included with the annual audited Consolidated Financial Statements have been condensed or have been disclosed on an annual basis only. Accordingly, these interim Consolidated Financial Statements should be read in conjunction with Enerplus’  annual audited Consolidated Financial Statements as of December 31, 2018. There are no differences in the use of estimates or judgments between these interim Consolidated Financial Statements and the annual audited Consolidated Financial Statements and notes thereto for the year ended December 31, 2018.

 

These unaudited interim Consolidated Financial Statements reflect, in the opinion of Management, all normal and recurring adjustments necessary to present fairly the financial position and results of the Company as at and for the periods presented.

 

3)   ACCOUNTING POLICY CHANGES

 

a)    Recently adopted accounting standards

 

Enerplus adopted ASC 842 Leases effective January 1, 2019 as detailed below. Enerplus used the modified retrospective method to adopt the new standard, with ASC 842 applied to all contracts not yet completed as of the date of adoption with the cumulative effect on comparative periods reflected as an adjustment to retained earnings, if applicable. The most significant impact was the recognition of right-of-use (“ROU”) assets and lease liabilities for operating leases, while accounting for finance leases and lessor accounting remained unchanged.

 

Enerplus elected the practical expedient related to land easements, allowing it to carry forward its accounting treatment for land easements on existing agreements.

 

The impacts of the adoption of ASC 842 as at January 1, 2019 are as follows:

 

			As reported as at						Balance as at
($ thousands)			December 31, 2018			Adjustments			January 1, 2019
Right-of-use assets		$	—		$	50,193		$	50,193
Current portion of lease liabilities			—			(10,648)			(10,648)
Lease liabilities			—			(39,545)			(39,545)
Total		$	—		$	—		$	—

 

The standard did not materially impact the Company’s Consolidated Statement of Income/(Loss) or cash flows.

 

As a result of this adoption, Enerplus has revised its accounting policy for leases as follows:

 

Leases

 

Enerplus determines if an arrangement is a lease at inception. A contract is, or contains a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Operating and finance leases are included in right-of-use assets, current lease liabilities, and long-term lease liabilities in the Consolidated Balance Sheets.

ENERPLUS 2019 Q2 REPORT               5

        

ROU assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the obligation to make lease payments arising from the lease. Lease liabilities are recognized at lease commencement date based on the present value of remaining lease payments over the lease term. A corresponding ROU asset is recognized at the amount of the lease liability, adjusted for lease incentives received. Enerplus uses the implicit rate when readily available, or uses its incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments. Enerplus’ lease terms may have options to extend or terminate the lease which are included in the calculation of lease liabilities when it is reasonably certain that it will exercise those options. Lease expense for operating leases is recognized on a straight-line basis over the lease term.

 

Lease agreements contain both lease and non-lease components which are accounted for separately. For certain equipment leases, a portfolio approach is applied to effectively account for the ROU assets and liabilities. Prior to January 1, 2019, the Company applied lease accounting in accordance with ASC 840.

 

b)    Future accounting changes

 

In future accounting periods, the Company will adopt the following Accounting Standards Updates (“ASU”) issued by the Financial Accounting Standards Board (“FASB”):

 

In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326). The ASU significantly changes how entities measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than a direct write down of the amortized cost basis. The new guidance is effective January 1, 2020, and will be applied using a modified retrospective approach. Enerplus does not expect to early adopt the standard and continues to assess the impact it will have on the Consolidated Financial Statements.

 

In January 2017, the FASB issued ASU 2017-04, Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment (Topic 350). This standard eliminates Step 2 of the goodwill impairment test and requires a goodwill impairment charge for the amount that the carrying amount of the reporting unit exceeds the reporting unit’s fair value. The updated guidance is effective January 1, 2020. Early adoption is permitted. The amended standard may affect goodwill impairment tests past the adoption date, the impact of which is not known.

 

4)   ACCOUNTS RECEIVABLE

 

($ thousands)		June 30, 2019			December 31, 2018
Accrued revenue		$	119,477		$	118,821
Accounts receivable – trade			42,629			30,252
Allowance for doubtful accounts			(3,816)			(3,867)
Total accounts receivable, net of allowance for doubtful accounts		$	158,290		$	145,206

 

 

 

5)   PROPERTY, PLANT AND EQUIPMENT (“PP&E”)

 

					Accumulated Depletion,
As of June 30, 2019					Depreciation, and
($ thousands)			Cost		Impairment				Net Book Value
Oil and natural gas properties(1)		$	14,859,006		$	(13,402,504)		$	1,456,502
Other capital assets			122,994			(103,425)			19,569
Total PP&E		$	14,982,000		$	(13,505,929)		$	1,476,071

 

 

					Accumulated Depletion,
As of December 31, 2018					Depreciation, and
($ thousands)			Cost		Impairment				Net Book Value
Oil and natural gas properties(1)		$	14,773,082		$	(13,479,141)		$	1,293,941
Other capital assets			115,510			(102,380)			13,130
Total PP&E		$	14,888,592		$	(13,581,521)		$	1,307,071

(1)

All of the Company’s unproved properties are included in the full cost pool.

6               ENERPLUS 2019 Q2 REPORT

        

6)   ASSET IMPAIRMENT

 

There was no impairment recorded for the six months ended June 30, 2019 and 2018.  

 

The following table outlines the 12-month average trailing benchmark prices and exchange rates used in Enerplus’ ceiling tests from June 30, 2018 through June 30, 2019:

 

		WTI Crude Oil			Edm Light Crude			U.S. Henry Hub		Exchange Rate
Period		US$/bbl			CDN$/bbl			Gas US$/Mcf		US$/CDN$
Q2 2019	$	61.38		$	66.07		$	3.02		1.32
Q1 2019		63.00			67.30			3.07		1.32
Q4 2018		65.56			69.58			3.10		1.28
Q3 2018		63.43			74.38			2.92		1.28
Q2 2018		57.67			67.77			2.92		1.27

 

 

 

7)   ACCOUNTS PAYABLE

 

($ thousands)		June 30, 2019						December 31, 2018
Accrued payables		$		151,764				$		115,388
Accounts payable – trade				195,147						174,657
Total accounts payable		$		346,911				$		290,045

 

 

 

8)   DEBT

 

($ thousands)		June 30, 2019				December 31, 2018
Current:
Senior notes		$	106,855			$		60,001
Long-term:
Bank credit facility			—					—
Senior notes			504,682					636,849
Total debt		$	611,537			$		696,850

 

The terms and rates of the Company’s outstanding senior notes are provided below:

 

Original

Remaining

CDN$ Carrying

Interest

Coupon

Principal

Principal

Value

Issue Date

Payment Dates

Principal Repayment

Rate

($ thousands)

($ thousands)

($ thousands)

September 3, 2014

March 3 and Sept 3

5 equal annual installments beginning September 3, 2022

3.79%

US$200,000

US$105,000

$

137,498

May 15, 2012

May 15 and Nov 15

Bullet payment on May 15, 2022

4.40%

US$20,000

US$20,000

26,190

May 15, 2012

May 15 and Nov 15

5 equal annual installments beginning May 15, 2020

4.40%

US$355,000

US$298,000

390,231

June 18, 2009

June 18 and Dec 18

2 equal annual installments June 18, 2020 - 2021

7.97%

US$225,000

US$44,000

57,618

Total carrying value

$

611,537

 

 

During the three months ended June 30, 2019, Enerplus made its third US$22  million principal repayment on its 2009 senior notes and a  $30 million bullet repayment on its 2012 senior notes. During the three months ended June 30, 2018, Enerplus made its second US$22 million principal repayment on its 2009 senior notes.

 

 

9)   ASSET RETIREMENT OBLIGATION

 

		Six months ended			Year ended
($ thousands)		June 30, 2019			December 31, 2018
Balance, beginning of year		$	126,112		$	117,736
Change in estimates			5,410			16,755
Property acquisitions and development activity			794			1,565
Divestments			(2,242)			(4,585)
Settlements			(5,893)			(11,263)
Accretion expense			2,917			5,904
Balance, end of period		$	127,098		$	126,112

 

 

ENERPLUS 2019 Q2 REPORT               7

        

Enerplus has estimated the present value of its asset retirement obligation to be $127.1 million at June 30, 2019 based on a total undiscounted liability of $342.0 million (December 31, 2018  – $126.1 million and $343.9 million, respectively). The asset retirement obligation was calculated using a weighted average credit-adjusted risk-free rate of 5.55% (December 31, 2018  – 5.59%).

10)   LEASES

 

The Company incurs lease payments related to office space, drilling rig commitments, vehicles and other equipment. Leases are entered into and exited in coordination with specific business requirements which includes the assessment of the appropriate durations for the related leased assets. Short-term leases with a lease term of 12 months or less are not recorded on the Consolidated Balance Sheet. Such items are charged to operating expenses and general and administrative expenses in the Consolidated Statement of Income/(Loss), unless the costs are included in the carrying amount of another asset in accordance with other U.S. GAAP.

 

		At June 30, 2019
Weighted average remaining lease term (years)
Operating leases			4.5
Weighted average discount rate
Operating leases			4.1%

 

The components of lease expense for the three and six months ended June 30, 2019 are as follows:

 

	Three months ended			Six months ended			Financial Statement
($ thousands)	June 30, 2019			June 30, 2019			Presentation
Operating lease expense(1)	$	3,879		$	8,463		PP&E
Operating lease expense(1)		3,588			6,376		Operating expense
Operating lease expense(1)		1,626			3,253		G&A expense
Sublease income		(256)			(500)		G&A expense
Total	$	8,837		$	17,592

(1)

Includes short-term and variable lease costs of $4.0 million and $8.4 million for the three and six months ended June 30, 2019, respectively.

 

Maturities of lease liabilities, all of which are classified as operating leases at June 30, 2019 are as follows:

 

Maturity of Lease Liabilities
($ thousands)		Operating Leases
2019		$	9,423
2020			19,331
2021			13,937
2022			7,551
After 2022			16,935
Total lease payments		$	67,177
Less imputed interest			(6,105)
Total discounted lease payments		$	61,072
Current portion of lease liabilities		$	16,974
Non-current portion of lease liabilities		$	44,098

 

Supplemental information related to leases are as follows:

 

		Three months ended			Six months ended
($ thousands)		June 30, 2019			June 30, 2019
Cash amounts paid to settle lease liabilities:
Operating cash flow used for operating leases		$	4,758		$	9,264
Right-of-use assets obtained in exchange for lease obligations:
Operating leases		$	1,105		$	19,967

 

 

 

8               ENERPLUS 2019 Q2 REPORT

        

11)   OIL AND NATURAL GAS SALES

 

		Three months ended June 30,						Six months ended June 30,
($ thousands)		2019			2018			2019			2018
Oil and natural gas sales		$	403,206		$	406,823		$	759,582		$	735,375
Royalties(1)			(81,743)			(79,439)			(150,667)			(142,971)
Oil and natural gas sales, net of royalties		$	321,463		$	327,384		$	608,915		$	592,404

(1)

Royalties above do not include production taxes which are reported separately on the Condensed Consolidated Statements of Income/(Loss).

 

Oil and natural gas revenue by country and by product for the three and six months ended June 30, 2019 and 2018 are as follows:

 

Three months ended June 30, 2019			Total revenue, net						Natural			Natural gas
($ thousands)			of royalties(1)			Crude oil(2)			gas(2)			liquids(2)			Other(3)
Canada		$	47,378		$	41,386		$	3,703		$	1,582		$	707
United States			274,085			217,830			51,766			4,489			—
Total		$	321,463		$	259,216		$	55,469		$	6,071		$	707

 

Three months ended June 30, 2018			Total revenue, net						Natural			Natural gas
($ thousands)			of royalties(1)			Crude oil(2)			gas(2)			liquids(2)			Other(3)
Canada		$	56,128		$	45,023		$	6,581		$	3,774		$	750
United States			271,256			218,039			45,692			7,525			—
Total		$	327,384		$	263,062		$	52,273		$	11,299		$	750

 

Six months ended June 30, 2019			Total revenue, net						Natural			Natural gas
($ thousands)			of royalties(1)			Crude oil(2)			gas(2)			liquids(2)			Other(3)
Canada		$	100,276		$	80,805		$	14,071		$	4,068		$	1,332
United States			508,639			375,669			124,922			8,048			—
Total		$	608,915		$	456,474		$	138,993		$	12,116		$	1,332

 

Six months ended June 30, 2018			Total revenue, net						Natural			Natural gas
($ thousands)			of royalties(1)			Crude oil(2)			gas(2)			liquids(2)			Other(3)
Canada		$	106,903		$	81,009		$	16,221		$	7,833		$	1,840
United States			485,501			369,262			104,287			11,952			—
Total		$	592,404		$	450,271		$	120,508		$	19,785		$	1,840

(1)

Royalties above do not include production taxes which are reported separately on the Condensed Consolidated Statements of Income/(Loss).

(2)

U.S. sales of crude oil and natural gas relate primarily to the Company’s North Dakota and Marcellus properties, respectively. Canadian crude oil sales relate primarily to the Company’s waterflood properties.

(3)

Includes third party processing income.

 

12)   GENERAL AND ADMINISTRATIVE EXPENSE

 

		Three months ended June 30,						Six months ended June 30,
($ thousands)		2019			2018			2019			2018
General and administrative expense		$	11,796		$	12,131		$	24,227		$	25,336
Share-based compensation expense			3,884			5,058			13,163			15,077
General and administrative expense(1)		$	15,680		$	17,189		$	37,390		$	40,413

(1)

Includes cash and non-cash amounts.

 

13)   FOREIGN EXCHANGE

 

	Three months ended June 30,						Six months ended June 30,
($ thousands)	2019			2018			2019			2018
Realized:
Foreign exchange (gain)/loss	$	89		$	221		$	(29)		$	289
Translation of U.S. dollar cash held in Canada (gain)/loss		4,158			(3,696)			9,354			(11,042)
Unrealized:
Translation of U.S. dollar debt and working capital (gain)/loss		(16,498)			12,386			(33,602)			30,035
Foreign exchange (gain)/loss	$	(12,251)		$	8,911		$	(24,277)		$	19,282

 

 

 

ENERPLUS 2019 Q2 REPORT               9

        

14)   INCOME TAXES

 

		Three months ended June 30,						Six months ended June 30,
($ thousands)		2019			2018			2019			2018
Current tax expense/(recovery)
Canada		$	(13,941)		$	—		$	(13,941)		$	—
United States			13			72			(5,517)			138
Current tax expense/(recovery)			(13,928)			72			(19,458)			138
Deferred tax expense/(recovery)
Canada		$	34,808		$	(20,460)		$	5,249		$	(25,970)
United States			13,989			23,699			25,680			41,684
Deferred tax expense/(recovery)			48,797			3,239			30,929			15,714
Income tax expense/(recovery)		$	34,869		$	3,311		$	11,471		$	15,852

 

The difference between the expected income taxes based on the statutory income tax rate and the effective income taxes for the current and prior period is impacted by the following: expected annual earnings, recognition or reversal of valuation allowance, foreign rate differentials for foreign operations, statutory and other rate differentials, non-taxable portions of capital gains and losses, and share-based compensation. Our overall net deferred income tax asset was $424.0 million at June 30, 2019 (December 31, 2018 – $465.1 million).

 

During the three months ended June 30, 2019, Enerplus recorded a deferred tax expense of $26.3 million for the remeasurement of its Canadian net deferred income tax asset for the change in the Alberta corporate tax rate.

 

During the three months ended June 30, 2019, Enerplus settled an outstanding dispute with the Canadian tax authorities in the Company’s favor reducing the balance of its December 31, 2018 unrecognized tax benefit to nil and recorded a current tax recovery of $13.9 million, including tax and interest. During the six months ended June 30, 2019, the current tax recovery included $5.5 million related to the reversal of the reserve recorded at December 31, 2017 for the sequestered portion of the U.S. Alternative Minimum Tax (“AMT”) refund.

 

At June 30, 2019, the current income tax receivable included $27.9 million related to a portion of the U.S. AMT refund (December 31, 2018 – $54.4 million) and $13.9 million related to the settlement of the Company’s unrecognized tax benefit. 

 

15)   SHAREHOLDERS’ EQUITY

 

a)   Share Capital

 

		Six months ended					Year ended
		June 30, 2019					December 31, 2018
Authorized unlimited number of common shares issued: (thousands)		Shares			Amount		Shares			Amount
Balance, beginning of year		239,411		$	3,337,608		242,129		$	3,386,946
Issued/(Purchased) for cash:
Purchase of common shares under Normal Course Issuer Bid		(8,359)			(116,423)		(5,925)			(82,596)
Stock Option Plan		—			—		668			9,138
Non-cash:
Share-based compensation – settled(1)		564			4,406		2,539			23,389
Stock Option Plan – exercised		—			—		—			731
Balance, end of period		231,616		$	3,225,591		239,411		$	3,337,608

(1)

The amount of shares issued on LTI settlement is net of employee withholding taxes in 2019.

 

Dividends declared to shareholders for the three and six months ended June 30, 2019 were $7.0 million and $14.2 million, respectively (2018  – $7.3 million and $14.7 million, respectively).

 

On March 21, 2019, Enerplus renewed its Normal Course Issuer Bid (“NCIB”) to continue to repurchase shares through the facilities of the Toronto Stock Exchange, New York Stock Exchange and/or alternative Canadian trading systems. Pursuant to the NCIB renewal, the Company was permitted to repurchase for cancellation up to 16,673,015 common shares over a period of twelve months commencing on March 26, 2019. All repurchases are made in accordance with the NCIB at prevailing market prices plus brokerage fees, with consideration allocated to share capital up to the average carrying amount of the shares, and any excess is allocated to accumulated deficit.

 

 

10               ENERPLUS 2019 Q2 REPORT

        

During the three months ended June 30, 2019, the Company repurchased 6,626,783 common shares under the current NCIB at an average price of $10.64 per share, for total consideration of $70.6 million. Of the amount paid, $92.3 million was charged to share capital and $21.7 million was credited to accumulated deficit. During the six months ended June 30, 2019, the Company repurchased 8,358,821 common shares under the previous and current NCIB at an average price of $10.80 per share, for total consideration of $90.4 million. Of the amount paid, $116.4 million was charged to share capital and $26.0 million was credited to accumulated deficit.

 

Subsequent to the quarter, and up to August 7, 2019, the Company repurchased an additional 981,266 common shares under the NCIB at an average price of $8.97 per share, for total consideration of $8.8 million.

 

b)   Share-based Compensation

 

The following table summarizes Enerplus’ share-based compensation expense, which is included in General and Administrative expense on the Condensed Consolidated Statements of Income/(Loss):

 

		Three months ended June 30,						Six months ended June 30,
($ thousands)		2019			2018			2019			2018
Cash:
Long-term incentive plans (recovery)/expense		$	(626)		$	435		$	711		$	2,381
Non-cash:
Long-term incentive plans			4,263			4,997			12,306			14,076
Equity swap (gain)/loss			247			(374)			146			(1,380)
Share-based compensation expense		$	3,884		$	5,058		$	13,163		$	15,077

 

i)   Long-term Incentive (“LTI”) Plans

 

The following table summarizes the Performance Share Unit (“PSU”), Restricted Share Unit (“RSU”) and Deferred Share Unit (“DSU”) plan activity for the six months ended June 30, 2019:

 

For the six months ended June 30, 2019		Cash-settled LTI plans		Equity-settled LTI plans				Total
(thousands of units)		DSU(1)		PSU(2)		RSU
Balance, beginning of year		391		1,371		1,753		3,515
Granted		97		803		845		1,745
Vested		(68)		—		(1,007)		(1,075)
Forfeited		—		(49)		(38)		(87)
Balance, end of period		420		2,125		1,553		4,098

(1)

Settlement of units vested has been deferred.

(2)

Based on underlying awards before any effect of the performance multiplier.

 

Cash-settled LTI Plans

 

For the three and six months ended June 30, 2019, the Company recorded a  cash share-based compensation recovery of $0.6 million and expense of $0.7 million, respectively (June 30, 2018 – expense of $0.4 million and $2.4 million, respectively). For the three and six months ended June 30, 2019, the Company made cash payments of $0.1 million related to its cash-settled plans (June 30, 2018  – $0.4 million).

 

As of June 30, 2019, a liability of $4.8 million (December 31, 2018  – $4.1 million) with respect to the DSU plan has been recorded to Accounts Payable on the Condensed Consolidated Balance Sheets.

 

Equity-settled LTI Plans

 

The following table summarizes the cumulative share-based compensation expense recognized to-date which is recorded to Paid-in Capital on the Condensed Consolidated Balance Sheets. Unrecognized amounts will be recorded to non-cash share-based compensation expense over the remaining vesting terms.

 

At June 30, 2019 ($ thousands, except for years)		PSU(1)			RSU			Total
Cumulative recognized share-based compensation expense		$	24,664		$	9,581		$	34,245
Unrecognized share-based compensation expense			15,601			9,895			25,496
Fair value		$	40,265		$	19,476		$	59,741
Weighted-average remaining contractual term (years)			1.9			1.6

(1)

Includes estimated performance multipliers.

 

ENERPLUS 2019 Q2 REPORT               11

        

The 2016 PSU’s which vested and were recognized in December 2018 were cash settled in January 2019.

 

The Company directly withholds shares on PSU and RSU settlements for tax-withholding purposes. For the six months ended June 30, 2019, $5.0 million (2018 – nil) in cash withholding taxes were paid.

 

ii)   Stock Option Plan

 

At June 30, 2019 all stock options are fully vested and any related non-cash share-based compensation expense has been fully recognized. 

 

The following table summarizes the stock option plan activity for the six months ended June 30, 2019:

 

		Number of Options		Weighted Average
Period ended June 30, 2019		(thousands)		Exercise Price
Options outstanding, beginning of year		4,131		$	17.12
Forfeited		(42)			16.74
Expired		(1,436)			22.79
Options outstanding, end of period		2,653		$	14.05
Options exercisable, end of period		2,653		$	14.05

 

At June 30, 2019,  Enerplus had 2,652,774 options that were exercisable at a weighted average exercise price of $14.05 with a weighted average remaining contractual term of 0.6 years, giving an aggregate intrinsic value of nil  (June 30, 2018  – 1.3 years and $8.0 million). The intrinsic value of options exercised for the three and six months ended June 30, 2019 was nil and nil, respectively (June 30, 2018  – $0.5 million and $0.7 million, respectively).

 

c)   Basic and Diluted Net Income/(Loss) Per Share

 

Net income/(loss) per share has been determined as follows:

 

		Three months ended June 30,						Six months ended June 30,
(thousands, except per share amounts)		2019			2018			2019			2018
Net income/(loss)		$	85,084		$	12,404		$	104,242		$	42,041
Weighted average shares outstanding – Basic			235,490			244,862			237,197			244,369
Dilutive impact of share-based compensation			2,699			5,260			2,750			4,998
Weighted average shares outstanding – Diluted			238,189			250,122			239,947			249,367
Net income/(loss) per share
Basic		$	0.36		$	0.05		$	0.44		$	0.17
Diluted		$	0.36		$	0.05		$	0.43		$	0.17

 

 

16)   FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

 

a)   Fair Value Measurements

 

At June 30, 2019, the carrying value of cash, accounts receivable, accounts payable, and dividends payable approximated their fair value due to the short-term maturity of the instruments.

 

At June 30, 2019, the senior notes had a carrying value of $611.5 million and a fair value of $620.7 million (December 31, 2018  – $696.9 million and $695.4 million, respectively).

 

The fair value of derivative contracts and the senior notes are considered a level 2 fair value measurement. There were no transfers between fair value hierarchy levels during the period.

 

b)   Derivative Financial Instruments

 

The derivative financial assets and liabilities on the Condensed Consolidated Balance Sheets result from recording derivative financial instruments at fair value.

 

12               ENERPLUS 2019 Q2 REPORT

        

The following table summarizes the change in fair value for the three and six months ended June 30, 2019 and 2018:

 

	Three months ended June 30,						Six months ended June 30,						Income Statement
Gain/(Loss) ($ thousands)	2019			2018			2019			2018			Presentation
Electricity Swaps	$	—		$	78		$	—		$	62		Operating expense
Equity Swaps		(247)			374			(146)			1,380		G&A expense
Commodity Derivative Instruments:
Oil		23,617			(70,905)			(63,312)			(100,760)		Commodity derivative
Gas		4,983			(760)			(3,517)			(1,517)		instruments
Total	$	28,353		$	(71,213)		$	(66,975)		$	(100,835)

 

The following table summarizes the income statement effects of Enerplus’ commodity derivative instruments:

 

		Three months ended June 30,						Six months ended June 30,
($ thousands)		2019			2018			2019			2018
Change in fair value gain/(loss)		$	28,600		$	(71,665)		$	(66,829)		$	(102,277)
Net realized cash gain/(loss)			(1,178)			(19,286)			9,384			(9,138)
Commodity derivative instruments gain/(loss)		$	27,422		$	(90,951)		$	(57,445)		$	(111,415)

 

The following table summarizes the fair values at the respective period ends:

 

		June 30, 2019									December 31, 2018
		Assets						Liabilities			Assets							Liabilities
($ thousands)		Current				Long-term		Current			Current			Long Term				Current
Equity Swaps		$	—		$	—		$	2,055		$	—		$	—		$	1,909
Commodity Derivative Instruments:
Oil			13,920			3,408			106			48,314			32,220			—
Gas			7,427			—			—			10,944			—			—
Total		$	21,347		$	3,408		$	2,161		$	59,258		$	32,220		$	1,909

 

c)   Risk Management

 

i)   Market Risk

 

Market risk is comprised of commodity price, foreign exchange, interest rate and equity price risk.

 

Commodity Price Risk:

 

Enerplus manages a portion of commodity price risk through a combination of financial derivative and physical delivery sales contracts. Enerplus’ policy is to enter into commodity contracts subject to a maximum of 80% of forecasted production volumes net of royalties and production taxes.

 

The following tables summarize the Corporation’s price risk management positions at August 7, 2019:

 

Crude Oil Instruments:

 

Instrument Type(1)(2)		bbls/day		US$/bbl
Jul 1, 2019 – Sep 30, 2019
WTI Purchased Put		24,500		54.81
WTI Sold Call		24,500		65.95
WTI Sold Put		24,500		44.64
WCS Differential Swap		1,500		(14.83)
WTI – Brent Swap		2,700		(8.10)
Aug 1, 2019 – Aug 31, 2019
UHC Differential Swap		2,000		(0.10)
Oct 1, 2019 – Dec 31, 2019
WTI Purchased Put		24,500		54.81
WTI Sold Call		24,500		65.99
WTI Sold Put		24,500		44.64
WCS Differential Swap		1,500		(14.83)
WTI – Brent Swap		2,700		(8.10)

ENERPLUS 2019 Q2 REPORT               13

        

Jan 1, 2020 – Dec 31, 2020
WTI Purchased Put		16,000		57.50
WTI Sold Put		16,000		46.88
WTI – Brent Swap		4,400		(8.03)

(1)

Transactions with a common term have been aggregated and presented at a weighted average price/bbl before premiums.

(2)

The total average deferred premium on outstanding hedges is US$2.00/bbl from July 1, 2019 to December 31, 2020.

 

For the remainder of 2019, Enerplus has physical sales contracts in place for approximately 26,300 bbls/day of Bakken production with fixed differentials averaging approximately US$2.66/bbl below WTI, a portion of which is sold directly into the U.S. Gulf Coast that utilizes the Company’s firm capacity on the Dakota Access Pipeline.

 

Natural Gas Instruments:

 

Instrument Type(1)		MMcf/day		US$/Mcf
Jul 1, 2019 – Jul 31, 2019
NYMEX Swap (Sale)		90.0		2.85
NYMEX Swap (Purchase)		60.0		2.34
Aug 1, 2019 – Oct 31, 2019
NYMEX Swap (Sale)		90.0		2.85
NYMEX Swap (Purchase)		90.0		2.34

(1)      Transactions with a common term have been aggregated and presented at a weighted average price/Mcf.

 

Foreign Exchange Risk:

 

Enerplus is exposed to foreign exchange risk in relation to its U.S. operations, U.S. dollar denominated senior notes, cash deposits and working capital. Additionally, Enerplus’ crude oil sales and a portion of its natural gas sales are based on U.S. dollar indices. To mitigate exposure to fluctuations in foreign exchange, Enerplus may enter into foreign exchange derivatives. At June 30, 2019,  Enerplus did not have any foreign exchange derivatives outstanding.

 

Interest Rate Risk:

 

At June 30, 2019, all of Enerplus’ debt was based on fixed interest rates and Enerplus had no interest rate derivatives outstanding.

 

Equity Price Risk:

 

Enerplus is exposed to equity price risk in relation to its long-term incentive plans detailed in Note 15. Enerplus has entered into various equity swaps maturing between 2019 and 2020 that effectively fix the future settlement cost on 264,000 shares at a weighted average price of $17.82 per share.

 

ii)   Credit Risk

 

Credit risk represents the financial loss Enerplus would experience due to the potential non-performance of counterparties to its financial instruments. Enerplus is exposed to credit risk mainly through its joint venture, marketing and financial counterparty receivables.

 

Enerplus mitigates credit risk through credit management techniques including conducting financial assessments to establish and monitor counterparties’ credit worthiness, setting exposure limits, monitoring exposures against these limits and obtaining financial assurances such as letters of credit, parental guarantees or third party credit insurance where warranted. Enerplus monitors and manages its concentration of counterparty credit risk on an ongoing basis.

 

Enerplus’ maximum credit exposure at the balance sheet date consists of the carrying amount of its non-derivative financial assets and the fair value of its derivative financial assets. At June 30, 2019,  86% of Enerplus’ marketing receivables were with companies considered investment grade. 

 

Enerplus actively monitors past due accounts and takes the necessary actions to expedite collection, which can include withholding production, netting amounts of future payments or seeking other remedies including legal action. Should Enerplus determine that the ultimate collection of a receivable is in doubt, it will provide the necessary provision in its allowance for doubtful accounts with a corresponding charge to earnings. If Enerplus subsequently determines an account is uncollectable, the account is written off with a corresponding charge to the allowance account. Enerplus’ allowance for doubtful accounts balance at June 30, 2019 was $3.8 million (December 31, 2018  – $3.9 million).

14               ENERPLUS 2019 Q2 REPORT

        

iii)   Liquidity Risk & Capital Management

 

Liquidity risk represents the risk that Enerplus will be unable to meet its financial obligations as they become due. Enerplus mitigates liquidity risk through actively managing its capital, which it defines as debt, net of cash and cash equivalents and share capital. Enerplus’ objective is to provide adequate short and long term liquidity while maintaining a flexible capital structure to sustain the future development of its business. Enerplus strives to balance the portion of debt and equity in its capital structure given its current oil and natural gas assets and planned investment opportunities.

 

Management monitors a number of key variables with respect to its capital structure, including debt levels, capital spending plans, dividends, share repurchases, access to capital markets, and acquisition and divestment activity.

 

At June 30, 2019, Enerplus was in full compliance with all covenants under the bank credit facility and outstanding senior notes.

 

17)   COMMITMENTS AND CONTINGENCIES

 

As of the date of this report, other than changes related to the adoption of the new lease accounting standard as described in Note 3, there were no material changes to Enerplus’ contractual obligations and commitments outside the ordinary course of business as reported in the Company’s annual audited Consolidated Financial Statements as of December 31, 2018.

 

Enerplus is subject to various legal claims and actions arising in the normal course of business. Although the outcome of such claims and actions cannot be predicted with certainty, the Company does not expect these matters to have a material impact on the Consolidated Financial Statements. In instances where the Company determines that a loss is probable and the amount can be reasonably estimated, an accrual is recorded.

 

18)   SUPPLEMENTAL CASH FLOW INFORMATION

 

a)   Changes in Non-Cash Operating Working Capital

 

		Three months ended June 30,						Six months ended June 30,
($ thousands)		2019			2018			2019			2018
Accounts receivable		$	37,580		$	(44,863)		$	23,401		$	(51,500)
Other assets			4,891			1,539			1,864			3,160
Accounts payable			8,985			13,436			(28,223)			25,921
		$	51,456		$	(29,888)		$	(2,958)		$	(22,419)

 

b)   Changes in Other Non-Cash Working Capital

 

		Three months ended June 30,						Six months ended June 30,
($ thousands)		2019			2018			2019			2018
Non-cash financing activities(1)		$	(65)		$	3		$	(77)		$	29
Non-cash investing activities(2)			41,039			31,463			91,140			76,123

(1)

Relates to changes in dividends payable and included in dividends on the Condensed Consolidated Statements of Cash Flows.

(2)

Relates to changes in accounts payable for capital and office expenditures and included in capital and office expenditures on the Condensed Consolidated Statements of Cash Flows.

 

c)   Other

 

		Three months ended June 30,						Six months ended June 30,
($ thousands)		2019			2018			2019			2018
Income taxes paid/(received)		$	(57,663)		$	2		$	(57,599)		$	(83)
Interest paid			14,390			14,937			17,649			18,193

 

ENERPLUS 2019 Q2 REPORT               15

Exhibit 99.3

 

FORM 52‑109F2

CERTIFICATION OF INTERIM FILINGS

FULL CERTIFICATE

 

I, Ian C. Dundas, President and Chief Executive Officer of Enerplus Corporation, certify the following:

 

1.Review:  I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Enerplus Corporation (the “issuer”) for the interim period ended June  30, 2019.

 

2.No misrepresentations:  Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.

 

3.Fair presentation:  Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.

 

4.Responsibility:  The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52‑109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.

 

5.Design:  Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer and I have, as at the end of the period covered by the interim filings

 

(a)designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

 

(i)material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

 

(ii)information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and

 

(b)designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.

 

5.1Control framework:  The control framework the issuer’s other certifying officer and I used to design the issuer’s ICFR is Internal Control — Integrated Framework (2013 Framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

 

5.2ICFR — material weakness relating to design:  N/A

 

5.3Limitation on scope of design:  N/A

 

6.Reporting changes in ICFR:  The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on April  1, 2019 and ended on June  30, 2019 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

 

Date: August 9, 2019

 

/s/ Ian C. Dundas
Ian C. Dundas President and Chief Executive Officer Enerplus Corporation

 

 

Exhibit 99.4

 

FORM 52‑109F2

CERTIFICATION OF INTERIM FILINGS

FULL CERTIFICATE

 

I, Jodine J. Jenson Labrie, Senior Vice President and Chief Financial Officer of Enerplus Corporation, certify the following:

 

1.Review:  I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Enerplus Corporation (the “issuer”) for the interim period ended June  30, 2019.

 

2.No misrepresentations:  Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.

 

3.Fair presentation:  Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.

 

4.Responsibility:  The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52‑109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.

 

5.Design:  Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer and I have, as at the end of the period covered by the interim filings

 

(a)designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

 

(i)material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

 

(ii)information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and

 

(b)designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.

 

5.1Control framework:  The control framework the issuer’s other certifying officer and I used to design the issuer’s ICFR is Internal Control — Integrated Framework (2013 Framework) issued by The Committee of Sponsoring Organizations of the Treadway Commission.

 

5.2ICFR — material weakness relating to design:  N/A

 

5.3Limitation on scope of design:  N/A

 

6.Reporting changes in ICFR:  The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on April 1, 2019 and ended on June  30, 2019 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

 

Date: August 9, 2019

 

/s/ Jodine J. Jenson Labrie
Jodine J. Jenson Labrie Senior Vice President and Chief Financial Officer Enerplus Corporation

 

This regulatory filing also includes additional resources:

Ex99_1.pdf

Ex99_2.pdf

Ex99_3.pdf

Ex99_4.pdf