ENERPLUS Corp (Form: 6-K, Received: 05/10/2019 06:24:57)

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 May, 2019

COMMISSION FILE NUMBER 1‑15150

The Dome Tower

Suite 3000, 333 – 7 th Avenue S.W.

Calgary, Alberta

Canada T2P 2Z1

(403) 298‑2200

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20‑F or Form 40‑F.

Form 20‑F ☐ Form 40‑F ☒

Indicate by check mark if the registrant is submitting the Form 6‑K in paper as permitted by Regulation S‑T Rule 101(b)(1)

Yes ☐ No ☒

Indicate by check mark if the registrant is submitting the Form 6‑K in paper as permitted by Regulation S‑T Rule 101(b)(7)

Yes ☐ No ☒

EXHIBIT INDEX

EXHIBIT 99.1 — Management’s Discussion and Analysis for the First Quarter ended March 31, 2019

EXHIBIT 99.2 — Unaudited Consolidated Financial Statements for the First Quarter ended March 31, 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: May 10, 2019

MD&A

Exhibit 99.1

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

The following discussion and analysis of financial results is dated May 9, 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 months ended March 31, 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 first quarter averaged 88,583 BOE/day, a 9% decrease compared to the fourth quarter of 2018. Production decreased in North Dakota as expected, due to modest capital spending in the fourth quarter of 2018, along with the planned timing of wells coming on-stream towards the end of the quarter. Despite the lower production in the first quarter, we expect strong well performance for the remainder of the year and we are increasing our average annual production guidance to 97,000 – 101,000 BOE/day from 94,000 – 100,000 BOE/day and revising our average annual crude oil and natural gas liquids guidance to 53,500 – 56,000 bbls/day from 52,500 – 56,000 bbls/day. In addition, we expect second quarter average production of 97,500 – 100,000 BOE/day, with crude oil and natural gas liquids production of 51,500 – 53,000 bbls/day.

Capital expenditures of $160.8 million were in line with our expectations, with approximately 70% of our capital spending directed to our North Dakota crude oil properties. We are narrowing our 2019 annual capital spending guidance range to $590 – $630 million from $565 – $635 million, following the continued optimization of our operational plans in North Dakota.

Operating costs for the quarter increased to $69.8 million or $8.75/BOE from $62.9 million or $6.99/BOE in the fourth quarter of 2018 mainly due to higher well service activity in both Canada and the U.S. and lower production in the first quarter of 2019. We are maintaining our annual operating cost guidance of $8.00/BOE for 2019.

ENERPLUS 2019 Q1 REPORT 1

Cash G&A expenses for the quarter were $12.3 million or $1.55/BOE, compared to $12.6 million or $1.40/BOE in the fourth quarter of 2018. Cash G&A expenses remained consistent with the fourth quarter but increased on a per BOE basis, primarily due to lower production volumes during the period. We are maintaining our annual guidance of $1.50/BOE for cash G&A expenses for the year.

During the first quarter of 2019, our Bakken crude oil price differential improved to US$3.25/bbl below WTI, compared to US$5.60/bbl below WTI in the fourth quarter of 2018, as a result of stronger demand from midwest U.S. refineries and severe winter weather in North Dakota reducing Bakken supply in the field. Our Marcellus natural gas differential improved to US$0.13/Mcf above NYMEX in the first quarter, compared to US$0.34/Mcf below NYMEX in the fourth quarter of 2018, due to strong weather-related demand resulting in lower than expected storage inventory in the U.S., and the benefit of a portion of our fixed physical gas sales contracts which are tied to regional New York markets.

As of May 8, 2019, we had approximately 65% 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 have also hedged approximately 45% of our forecasted natural gas production, net of royalties, for the period April 1 to October 31, 2019.

We reported net income of $19.2 million in the first quarter of 2019 compared to $249.3 million in the fourth quarter of 2018. The decrease is primarily the result of a $95.4 million unrealized loss on commodity derivative instruments, compared to a $256.5 million unrealized gain in the fourth quarter of 2018 due to the improvement in crude oil and natural gas prices in the first quarter.

In the first quarter of 2019, cash flow from operations decreased to $109.0 million, compared to $221.6 million in the fourth quarter of 2018 due to lower crude oil production and changes to working capital. Adjusted funds flow in the quarter decreased to $168.8 million from $214.3 million in the fourth quarter of 2018, as a result of lower crude oil production and a reduced Alternative Minimum Tax (“AMT”) refund of $5.5 million in the first quarter of 2019, compared to $27.2 million in the prior period.

During the quarter, we repurchased and cancelled 1,732,038 common shares under our Normal Course Issuer Bid (“NCIB”) for total consideration of $19.8 million.

At March 31, 2019, our total debt net of cash was $363.8 million and our net debt to adjusted funds flow ratio was 0.5x.

RESULTS OF OPERATIONS

Production

Average daily production for the first quarter totaled 88,583 BOE/day, compared to production of 97,860 BOE/day in the fourth quarter of 2018. Crude oil and liquids production decreased by 8,963 bbls/day, primarily due to lower North Dakota volumes as a result of lower capital spending in the fourth quarter of 2018, along with the expected timing of wells coming on-stream in March 2019. Our natural gas production remained flat, compared to the fourth quarter of 2018.

Production in the first quarter increased by 3,503 BOE/day or 4%, when compared to production of 85,080 BOE/day for the same period of the prior year. A larger capital program in North Dakota resulted in an increase of approximately 4,500 BOE/day of liquids production. This increase was partially offset by the divestment of non-core Canadian properties in the first quarter of 2018.

Our crude oil and natural gas liquids weighting increased to 51% in the first quarter of 2019, from 49% for the same period of 2018, due to increased capital spending on our U.S. crude oil assets.

Average daily production volumes for the three months ended March 31, 2019 and 2018 are outlined below:


	Three months ended March 31,
Average Daily Production Volumes	2019	2018	% Change
Crude oil (bbls/day)	41,105	37,443	10%
Natural gas liquids (bbls/day)	4,383	4,085	7%
Natural gas (Mcf/day)	258,568	261,310	(1%)
Total daily sales (BOE/day)	88,583	85,080	4%

We are increasing our average annual production guidance to 97,000 – 101,000 BOE/day from 94,000 – 100,000 BOE/day and revising our average annual crude oil and natural gas liquids guidance to 53,500 – 56,000 bbls/day from 52,500 – 56,000 bbls/day. In addition, we expect second quarter average production of 97,500 – 100,000 BOE/day, with crude oil and natural gas liquids average production of 51,500 – 53,000 bbls/day.

2 ENERPLUS 2019 Q1 REPORT

Pricing

The prices received for our crude oil and natural gas production directly impact our earnings, adjusted funds flow and financial condition. The following table compares quarterly average prices for the three months ended March 31, 2019 and 2018 and other periods indicated:


Pricing (average for the period)	Q1 2019		Q4 2018			Q3 2018		Q2 2018		Q1 2018
Benchmarks
WTI crude oil (US$/bbl)	$	54.90	$	58.81	$	69.50	$	67.88	$	62.87
Brent (ICE) crude oil (US$/bbl)		63.90		68.08		75.97		74.90		67.18
NYMEX natural gas – last day (US$/Mcf)		3.10		3.64		2.90		2.80		3.00
USD/CDN average exchange rate		1.33		1.32		1.31		1.29		1.26
USD/CDN period end exchange rate		1.33		1.36		1.29		1.31		1.29

Enerplus selling price (1)
Crude oil ($/bbl)	$	66.56	$	64.18	$	83.98	$	79.98	$	69.67
Natural gas liquids ($/bbl)		19.15		26.72		25.95		32.23		28.13
Natural gas ($/Mcf)		4.38		4.28		3.22		2.68		3.50

Average differentials
Brent (ICE) – WTI (US$/bbl)	$	9.00	$	9.27	$	6.47	$	7.02	$	4.31
MSW Edmonton – WTI (US$/bbl)		(4.85)		(26.30)		(6.83)		(5.45)		(5.89)
WCS Hardisty – WTI (US$/bbl)		(12.29)		(39.43)		(22.25)		(19.27)		(24.28)
Transco Leidy monthly – NYMEX (US$/Mcf)		(0.22)		(0.39)		(0.61)		(0.91)		(0.67)
TGP Z4 300L monthly – NYMEX (US$/Mcf)		(0.27)		(0.49)		(0.68)		(0.99)		(0.76)

Enerplus realized differentials (1)(2)
Bakken crude oil – WTI (US$/bbl)	$	(3.25)	$	(5.60)	$	(2.54)	$	(3.42)	$	(3.27)
Marcellus natural gas – NYMEX (US$/Mcf)		0.13		(0.34)		(0.48)		(0.69)		(0.21)
Canada crude oil – WTI (US$/bbl)		(10.42)		(33.27)		(16.61)		(16.31)		(20.82)

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

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

CRUDE OIL AND NATURAL GAS LIQUIDS

Our average realized crude oil price for the first quarter of 2019 averaged $66.56/bbl, an increase of 4% compared to the previous quarter, despite a 7% decrease in WTI Benchmark pricing. This increase was due to the strengthening of crude oil differentials in the first quarter of 2019 as U.S. refinery demand returned after record levels of maintenance in the fourth quarter of 2018 combined with mandatory Alberta oil curtailments. As a result, our realized Bakken price differential improved by 42% during the quarter to average US$3.25/bbl below WTI. Our sales price continued to benefit from a portion of our physical sales that were sold on a fixed differential basis below WTI. For the remainder of 2019, we have physical sales contracts in place for an average of 19,000 bbls/day of Bakken crude oil production with fixed differentials averaging approximately US$1.90/bbl below WTI, a portion of which is sold directly into the U.S. Gulf Coast that utilizes our firm capacity on the Dakota Access Pipeline. We are maintaining our full year Bakken differential guidance of US$4.00/bbl below WTI.

Our realized price differential for our Canadian crude oil production improved by US$22.85/bbl compared to the previous quarter. Canadian crude oil prices weakened significantly during the fourth quarter as seasonal U.S. refinery maintenance and growing Canadian crude oil production placed constraints on Canadian pipeline capacity. This pressure has since been relieved mainly due to Alberta Government mandated production curtailments. We have fixed differential hedges in place for 1,500 bbl/day of our Canadian heavy crude oil production at an average differential of US$14.83/bbl below WTI for the remainder of 2019.

Our realized price for natural gas liquids averaged $19.15/bbl during the period, which represents a 28% decrease compared to the previous quarter. The reduction is mainly due to price weakness in U.S. benchmark pricing, applicable to both propane and butane production from our U.S. Bakken assets.

ENERPLUS 2019 Q1 REPORT 3

NATURAL GAS

Our average realized natural gas price during the first quarter of 2019 increased by 2% compared to the fourth quarter of 2018, to average $4.38/Mcf, while NYMEX benchmark pricing decreased by 15%. The increase was mainly due to continued improvement in Marcellus pricing, where our realized differentials averaged US$0.13/Mcf above NYMEX for the period, compared to US$0.34/Mcf below NYMEX in the fourth quarter. Strong weather-related demand resulted in lower than expected storage inventory in the U.S., especially in the Northeastern region, which resulted in improved differentials. Our realized Marcellus gas price was supported by fixed physical basis sales during the quarter at markedly higher levels than the settled benchmarks. Further, basis differentials in the Marcellus continued to be supported by pipeline additions that were recently brought into service. We expect our realized Marcellus differentials for the remainder of the year to moderate from the first quarter due to the seasonality of pricing and demand in Northeastern U.S. markets and we are maintaining our full year differential guidance for the Marcellus of US$0.30/Mcf below NYMEX.

FOREIGN EXCHANGE

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

The Canadian dollar was weaker during the first three months in 2019 with an average exchange rate of 1.33 US/CDN compared to 1.26 US/CDN for the same period in 2018. However, when comparing the exchange rate in the first quarter of 2019 to the fourth quarter of 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 expenditures.

As of May 8, 2019, we have hedged approximately 24,170 bbls/day of crude oil, which represents approximately 65% 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% based off our 2019 forecasted crude oil production, after royalties. Our crude oil hedges are all three-way collars, which consist of a sold put, a purchased put and a sold call. When WTI prices settle below the sold put strike price, the three-way collars provide a limited amount of protection above the WTI settled price equal to the difference between the strike price of the purchased and sold puts. Overall, we expect our crude oil related hedging contracts to protect a significant portion of our cash flow from operating activities and adjusted funds flow.

As of May 8, 2019, we have hedged approximately 90,000 Mcf/day of our forecasted natural gas production for the period April 1 to October 31, 2019. This represents approximately 45% of our forecasted natural gas production, after royalties, for that period.

The following is a summary of our financial contracts in place at May 8, 2019, expressed as a percentage of our anticipated net production volumes:


	WTI Crude Oil (US$/bbl) (1)(2)
	Apr 1, 2019 –	Jul 1, 2019 –	Oct 1, 2019 –	Jan 1, 2020 –
	Jun 30, 2019	Sep 30, 2019	Dec 31, 2019	Dec 31, 2020
Three Way Collars (2)
Sold Puts	$ 44.50	$ 44.64	$ 44.64	$ 46.88
%	63%	66%	66%	43%
Purchased Puts	$ 54.59	$ 54.81	$ 54.81	$ 57.50
%	63%	66%	66%	43%
Sold Calls	$ 65.52	$ 65.95	$ 65.99	$ 72.50
%	63%	66%	66%	43%

(1)

Based on weighted average price (before premiums) assuming average annual production of 99,000 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 spent on our three-way collars is US$1.59/bbl from April 1, 2019 to December 31, 2020.


		NYMEX Natural Gas (US$/Mcf) (1)
		Apr 1, 2019 –
		Oct 31, 2019
Swaps
Sold Swaps		$ 2.85
%		45%

(1)

Based on weighted average price (before premiums) assuming average annual production of 99,000 BOE/day, which is the mid-point of our annual 2019 guidance, less royalties and production taxes of 25%.

4 ENERPLUS 2019 Q1 REPORT

ACCOUNTING FOR PRICE RISK MANAGEMENT


Commodity Risk Management Gains/(Losses)	Three months ended March 31,
($ millions)	2019		2018
Cash gains/(losses):
Crude oil	$	(2.0)	$	(6.4)
Natural gas		12.5		16.5
Total cash gains/(losses)	$	10.5	$	10.1

Non-cash gains/(losses):
Crude oil	$	(86.9)	$	(29.9)
Natural gas		(8.5)		(0.7)
Total non-cash gains/(losses)	$	(95.4)	$	(30.6)
Total gains/(losses)	$	(84.9)	$	(20.5)


	Three months ended March 31,
(Per BOE)	2019		2018
Total cash gains/(losses)	$	1.32	$	1.33
Total non-cash gains/(losses)		(11.97)		(3.99)
Total gains/(losses)	$	(10.65)	$	(2.66)

During the first quarter of 2019, we realized cash losses of $2.0 million on our crude oil contracts and cash gains of $12.5 million on our natural gas contracts. In comparison, during the first quarter of 2018, we realized cash losses of $6.4 million on our crude oil contracts and cash gains of $16.5 million on our natural gas contracts. Cash losses on our crude oil contracts were primarily due to crude oil prices rising above the swap level. Cash gains on our natural gas contracts were primarily due to natural gas prices falling below the swap level and the put strike price on our collars.

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 first quarter of 2019, the fair value of our crude oil contracts was in a net liability position of $6.4 million and the fair value of our natural gas contracts was in a net asset position of $2.4 million. For the three months ended March 31, 2019, the change in the fair value of our crude oil contracts and natural gas contracts represented losses of $86.9 million and $8.5 million, respectively.

Revenues


	Three months ended March 31,
($ millions)	2019		2018
Oil and natural gas sales	$	356.4	$	328.5
Royalties		(68.9)		(63.5)
Oil and natural gas sales, net of royalties	$	287.5	$	265.0

Oil and natural gas sales, net of royalties, for the three months ended March 31, 2019 were $287.5 million, an increase of 8% from the same period in 2018. The increase in revenue was a result of higher liquids production and higher natural gas realized prices.

Royalties and Production Taxes


	Three months ended March 31,
($ millions, except per BOE amounts)	2019		2018
Royalties	$	68.9	$	63.5
Per BOE	$	8.65	$	8.30

Production taxes	$	14.6	$	16.1
Per BOE	$	1.83	$	2.11
Royalties and production taxes	$	83.5	$	79.6
Per BOE	$	10.48	$	10.41

Royalties and production taxes (% of oil and natural gas sales)		23%		24%

ENERPLUS 2019 Q1 REPORT 5

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 months ended March 31, 2019, royalties and production taxes increased to $83.5 million from $79.6 million for the same period in 2018, primarily due to higher U.S. crude oil and natural gas sales.

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

Operating Expenses


	Three months ended March 31,
($ millions, except per BOE amounts)	2019		2018
Cash operating expenses	$	69.8	$	53.8
Per BOE	$	8.75	$	7.02

For the three months ended March 31, 2019, operating expenses were $69.8 million or $8.75/BOE, compared to our annual guidance of $8.00/BOE, representing an increase of $16.0 million from the same period in 2018. The increase is mainly attributable to our higher crude oil production as our liquids weighting increased to 51% from 49% in the prior year, higher well service activity on our crude oil properties and the effects of a weaker Canadian dollar in 2019.

With production growing for the remainder of the year, we are maintaining our annual operating cost guidance of $8.00/BOE.

Transportation Costs


	Three months ended March 31,
($ millions, except per BOE amounts)	2019		2018
Transportation costs	$	31.3	$	26.9
Per BOE	$	3.92	$	3.52

For the three months ended March 31, 2019, transportation costs were $31.3 million or $3.92/BOE, compared to our annual guidance of $4.00/BOE. During the same period in 2018, transportation costs were $26.9 million or $3.52/BOE. The increase is due to the increase in our U.S. crude oil production and a weaker Canadian dollar when compared to the prior period.

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

Netbacks

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


	Three months ended March 31, 2019
Netbacks by Property Type	Crude Oil		Natural Gas		Total
Average Daily Production	48,909 BOE/day		238,044 Mcfe/day		88,583 BOE/day
Netback (1) $ per BOE or Mcfe	(per BOE)		(per Mcfe)		(per BOE)
Oil and natural gas sales	$	59.51	$	4.41	$	44.70
Royalties and production taxes		(14.92)		(0.83)		(10.48)
Cash operating expenses		(13.96)		(0.39)		(8.75)
Transportation costs		(2.75)		(0.90)		(3.92)
Netback before hedging	$	27.88	$	2.29	$	21.55
Cash hedging gains/(losses)		(0.45)		0.59		1.32
Netback after hedging	$	27.43	$	2.88	$	22.87
Netback before hedging ($ millions)	$	122.7	$	49.1	$	171.8
Netback after hedging ($ millions)	$	120.8	$	61.5	$	182.3

6 ENERPLUS 2019 Q1 REPORT


	Three months ended March 31, 2018
Netbacks by Property Type	Crude Oil		Natural Gas		Total
Average Daily Production	44,050 BOE/day		246,180 Mcfe/day		85,080 BOE/day
Netback (1) $ per BOE or Mcfe	(per BOE)		(per Mcfe)		(per BOE)
Oil and natural gas sales	$	62.99	$	3.56	$	42.91
Royalties and production taxes		(16.47)		(0.65)		(10.41)
Cash operating expenses		(10.79)		(0.50)		(7.02)
Transportation costs		(2.07)		(0.84)		(3.52)
Netback before hedging	$	33.66	$	1.57	$	21.96
Cash hedging gains/(losses)		(1.61)		0.75		1.33
Netback after hedging	$	32.05	$	2.32	$	23.29
Netback before hedging ($ millions)	$	133.4	$	34.8	$	168.2
Netback after hedging ($ millions)	$	127.0	$	51.3	$	178.3

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

Crude oil netbacks before hedging for the three months ended March 31, 2019 were lower compared to the same period in 2018 primarily due to weaker realized prices and higher operating and transportation expenses. Natural gas netbacks before hedging were higher for the first quarter of 2019 compared to the same period in 2018 mainly due to higher realized prices. For the three months ended March 31, 2019, our crude oil properties accounted for 71% of our total netback before hedging, compared to 79% during the same period 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 March 31,
($ millions)	2019		2018
Cash:
G&A expense	$	12.3	$	13.2
Share-based compensation expense		1.3		1.9

Non-Cash:
Share-based compensation expense		8.1		9.1
Equity swap loss/(gain)		(0.1)		(1.0)
G&A expense		0.1		—
Total G&A expenses	$	21.7	$	23.2


	Three months ended March 31,
(Per BOE)	2019		2018
Cash:
G&A expense	$	1.55	$	1.72
Share-based compensation expense		0.17		0.25

Non-Cash:
Share-based compensation expense		1.01		1.19
Equity swap loss/(gain)		(0.01)		(0.13)
G&A expense		0.01		—
Total G&A expenses	$	2.73	$	3.03

For the three months ended March 31, 2019, cash G&A expenses were $12.3 million or $1.55/BOE compared to $13.2 million or $1.72/BOE for the same period in 2018. Cash G&A expenses were essentially flat but decreased on a per BOE basis compared to the same period in 2018 due to higher production.

During the first quarter of 2019, we reported cash SBC expense of $1.3 million due to the grant of additional deferred share units and the increase in our share price on outstanding deferred share units. In comparison, during the same period of 2018, we recorded cash SBC expense of $1.9 million. We recorded non-cash SBC expense of $8.1 million or $1.01/BOE in the first quarter of 2019, a decrease from an expense of $9.1 million or $1.19/BOE during the same period in 2018.

ENERPLUS 2019 Q1 REPORT 7

We have hedges in place on a portion of the outstanding cash-settled grants under our LTI plans. In the first quarter we recorded a non-cash mark-to-market gain of $0.1 million on these hedges due to the increase in our share price. We had 195,000 units outstanding, hedged at a weighted average price of $20.60 per share at March 31, 2019.

We are maintaining our annual cash G&A guidance of $1.50/BOE.

Interest Expense

For the three months ended March 31, 2019, we recorded total interest expense of $8.4 million, compared to $9.1 million for the same period in 2018. The decrease in interest expense for the three month period ended March 31, 2019 was primarily due to the repayment of a portion of our 2009 senior notes which carry a higher coupon rate, offset by the impact of a weaker Canadian dollar on our U.S. dollar denominated interest expense.

At March 31, 2019, we were undrawn on our $800 million bank credit facility and our debt balance consisted of fixed interest rates, with a weighted average interest rate of 4.7%. See Note 8 to the Interim Financial Statements for further details.

Foreign Exchange


	Three months ended March 31,
($ millions)	2019		2018
Realized:
Foreign exchange (gain)/loss on settlements	$	(0.1)	$	0.1
Translation of U.S. dollar cash held in Canada (gain)/loss		5.2		(7.3)
Unrealized (gain)/loss		(17.1)		17.6
Total foreign exchange (gain)/loss	$	(12.0)	$	10.4
USD/CDN average exchange rate		1.33		1.26
USD/CDN period end exchange rate		1.33		1.29

For the three months ended March 31, 2019, we recorded a foreign exchange gain of $12.0 million compared to losses of $10.4 million for the same period 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 March 31, 2019 to December 31, 2018, the Canadian dollar strengthened relative to the U.S. dollar, resulting in an unrealized gain of $17.1 million. See Note 13 to the Interim Financial Statements for further details.

Capital Investment


	Three months ended March 31,
($ millions)	2019		2018
Capital spending (1)	$	160.8	$	151.5
Office capital (1)		1.1		1.4
Line fill		5.1		—
Sub-total		167.0		152.9
Property and land acquisitions	$	3.0	$	12.3
Property divestments		(0.5)		(7.0)
Sub-total		2.5		5.3
Total	$	169.5	$	158.2

(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 months ended March 31, 2019 totaled $160.8 million compared to $151.5 million for the same period in 2018. The increase in spending is in line with our strategy to deliver production and liquids growth through 2019. During the first quarter of 2019, we spent $128.1 million on our U.S. crude oil properties, $15.2 million on our Marcellus natural gas assets and $14.7 million on our Canadian waterflood properties. For the three months ended March 31, 2019, we spent $5.1 million on line fill to meet the requirements of a multi-year transportation contract, which began in March 2019.

In the first quarter, we completed $3.0 million in property and land acquisitions compared to $12.3 million for the same period in 2018 which included minor acquisitions of leases and undeveloped land. Property divestments for the three months ended March 31, 2019 were $0.5 million compared to $7.0 million for the same period in 2018 which primarily related to an acreage swap in North Dakota and the divestment of non-core properties in Northwestern Alberta.

We are narrowing our 2019 annual capital spending guidance range to $590 million – $630 million, following the continued optimization of our operational plans in North Dakota.

8 ENERPLUS 2019 Q1 REPORT

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


	Three months ended March 31,
($ millions, except per BOE amounts)	2019		2018
DD&A expense	$	75.9	$	64.0
Per BOE	$	9.52	$	8.36

DD&A of property, plant and equipment (“PP&E”) is recognized using the unit-of-production method based on proved reserves. For the three months ended March 31, 2019, DD&A increased compared to the same period 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 5.56%, to be $127.9 million at March 31, 2019, compared to 5.59% and $126.1 million at December 31, 2018. For the three months ended March 31, 2019, asset retirement obligation settlements were $5.4 million compared to $3.3 million during the same period 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 March 31, 2019, our total lease liability was $65.0 million. In addition, ROU assets of $64.9 million were recorded, which equals 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 March 31,
($ millions)	2019		2018
Current tax expense/(recovery)	$	(5.5)	$	0.1
Deferred tax expenses/(recovery)		(17.9)		12.4
Total tax expense/(recovery)	$	(23.4)	$	12.5

We recorded a total tax recovery of $23.4 million during the first quarter of 2019, compared to a $12.5 million expense for the same period in 2018. The recovery in 2019 primarily relates to lower net income, as a result of higher unrealized commodity derivative losses, compared to the same period in 2018. The current tax recovery of $5.5 million in 2019 primarily relates to the reversal of the reserve recorded at December 31, 2017 for the sequestered portion of our U.S. AMT refund as the U.S. federal government announced in the first quarter of 2019 that they do not intend to sequester any portion of the AMT refund. See Note 14 to the Interim Financial Statements for further details.

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 March 31, 2019, our senior debt to adjusted EBITDA ratio was 0.9x 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 March 31, 2019 was $363.8 million, an increase of 9% compared to $333.5 million at December 31, 2018. Total debt was comprised of $682.8 million of senior notes less $319.0 million in cash. At March 31, 2019, we were undrawn on our $800 million bank credit facility.

Our adjusted payout ratio, which is calculated as cash dividends plus capital, office expenditures and line fill divided by adjusted funds flow, was 103% for the three months ended March 31, 2019, consistent with the same period in 2018.

ENERPLUS 2019 Q1 REPORT 9

For the three months ended March 31, 2019, the Company repurchased and cancelled approximately 1.7 million shares under our previous and current NCIB for a total cost of $19.8 million.

Our working capital deficiency, excluding cash and current derivative financial assets and liabilities, increased to $161.6 million at March 31, 2019 from $143.1 million at December 31, 2018. We expect to finance our working capital deficit and our ongoing working capital requirements through cash, adjusted funds flow and our bank credit facility. We have sufficient liquidity to meet our financial commitments, as disclosed under “Commitments” in the Annual MD&A.

At March 31, 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.

The following table lists our financial covenants as at March 31, 2019:


Covenant Description		March 31, 2019
Bank Credit Facility:	Maximum Ratio
Senior debt to adjusted EBITDA (1)	3.5x	0.9x
Total debt to adjusted EBITDA (1)	4.0x	0.9x
Total debt to capitalization	50%	19%

Senior Notes:	Maximum Ratio
Senior debt to adjusted EBITDA (1)(2)	3.0x - 3.5x	0.9x
Senior debt to consolidated present value of total proved reserves (3)	60%	20%
	Minimum Ratio
Adjusted EBITDA to interest (1)	4.0x	21.5x

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 March 31, 2019 was $166.4 million and $777.6 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%.

Dividends


	Three months ended March 31,
($ millions, except per share amounts)	2019		2018
Dividends to shareholders (1)	$	7.2	$	7.3
Per weighted average share (Basic)	$	0.03	$	0.03

(1)

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

During the three months ended March 31, 2019, we reported total dividends of $7.2 million or $0.03 per share compared to $7.3 million or $0.03 per share for the same period 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


	Three months ended March 31,
	2019		2018
Share capital ($ millions)	$	3,317.9	$	3,411.9

Common shares outstanding (thousands)		238,243		244,773
Weighted average shares outstanding – basic (thousands)		238,922		243,874
Weighted average shares outstanding – diluted (thousands)		241,298		249,191

For the three months ended March 31, 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).

10 ENERPLUS 2019 Q1 REPORT

For the three months ended March 31, 2019, no shares were issued pursuant to our stock option plan, resulting in no additional share capital (2018 – 104,622; $0.1 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. Subject to exceptions for block purchases, the Company will limit daily purchases of common shares on the TSX in connection with the NCIB to no more than 25% (270,933 common shares) of the average daily trading volume of the common shares on the TSX (1,083,735 common shares) during any trading day. Purchases under the NCIB will be made through open market purchases at market price, as well as by other means as may be permitted by applicable securities regulatory authorities, including private agreements. Common shares purchased under the NCIB will be cancelled. Shareholders may obtain a copy of the Company's notice to the TSX to renew its NCIB, without charge, by contacting the Corporate Secretary of the Company at Suite 3000, 333 - 7th Avenue S.W., Calgary, Alberta, T2P 2Z1, telephone (403) 298-2200.

During the three months ended March 31, 2019, the Company repurchased 1,732,038 common shares under the previous and current NCIB at an average price of $11.43 per share, for total consideration of $19.8 million. Of the amount paid, $24.1 million was charged to share capital and $4.3 million was credited to accumulated deficit. Subsequent to the quarter and up to May 8, 2019, the Company repurchased 1,259,832 common shares under the NCIB at an average price of $11.86 per share, for total consideration of $15.0 million.

At May 8, 2019, we had 236,983,232 common shares outstanding. In addition, an aggregate of 8,572,694 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.

SELECTED CANADIAN AND U.S. FINANCIAL RESULTS


	Three months ended March 31, 2019						Three months ended March 31, 2018
($ millions, except per unit amounts)	Canada		U.S.		Total		Canada		U.S.		Total
Average Daily Production Volumes (1)
Crude oil (bbls/day)		8,998		32,107		41,105		9,513		27,930		37,443
Natural gas liquids (bbls/day)		984		3,399		4,383		1,247		2,838		4,085
Natural gas (Mcf/day)		24,348		234,220		258,568		33,132		228,178		261,310
Total average daily production (BOE/day)		14,040		74,543		88,583		16,282		68,798		85,080

Pricing (2)
Crude oil (per bbl)	$	59.07	$	68.66	$	66.56	$	52.82	$	75.41	$	69.67
Natural gas liquids (per bbl)		35.89		14.30		19.15		45.11		20.66		28.13
Natural gas (per Mcf)		4.64		4.35		4.38		3.12		3.56		3.50

Capital Expenditures
Capital spending	$	17.5	$	143.3	$	160.8	$	13.2	$	138.3	$	151.5
Acquisitions		1.0		2.0		3.0		1.1		11.2		12.3
Divestments		(0.1)		(0.4)		(0.5)		(0.9)		(6.1)		(7.0)

Netback (3) Before Hedging
Oil and natural gas sales	$	61.8	$	294.6	$	356.4	$	60.7	$	267.8	$	328.5
Royalties		(8.9)		(60.0)		(68.9)		(9.9)		(53.6)		(63.5)
Production taxes		(0.6)		(14.0)		(14.6)		(0.8)		(15.3)		(16.1)
Cash operating expenses		(21.0)		(48.8)		(69.8)		(20.6)		(33.2)		(53.8)
Transportation costs		(2.7)		(28.6)		(31.3)		(3.0)		(23.9)		(26.9)
Netback before hedging	$	28.6	$	143.2	$	171.8	$	26.4	$	141.8	$	168.2

Other Expenses
Commodity derivative instruments loss/(gain)	$	84.9	$	—	$	84.9	$	20.5	$	—	$	20.5
General and administrative expense (4)		13.2		8.5		21.7		15.4		7.8		23.2
Current income tax expense/(recovery)		—		(5.5)		(5.5)		—		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 Q1 REPORT 11

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
First Quarter	$	287.5	$	19.2	$	0.08	$	0.08
Total 2019	$	287.5	$	19.2	$	0.08	$	0.08
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, decreased in the first quarter of 2019 compared to the fourth quarter of 2018 due to lower production volumes. Net income decreased in the first quarter of 2019 due to unrealized losses on commodity derivative instruments, compared to a significant unrealized gain during the fourth quarter of 2018.

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.

2019 UPDATED GUIDANCE

We are increasing our annual average production guidance to 97,000 – 101,000 BOE/day and revising our average annual crude oil and natural gas liquids guidance to 53,500 – 56,000 bbls/day. In addition, we expect second quarter average production of 97,500 – 100,000 BOE/day, with average crude oil and natural gas liquids production of 51,500 – 53,000 bbls/day.

We are narrowing our 2019 capital spending guidance to $590 – $630 million from our previous range of $565 – $635 million.

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


Summary of 2019 Expectations		Target
Capital spending		$590 - $630 million (from $565 - $635 million)
Average annual production		97,000 - 101,000 BOE/day (from 94,000 - 100,000 BOE/day)
Average annual crude oil and natural gas liquids production		53,500 - 56,000 bbls/day (from 52,500 - 56,000 bbls/day)
Second quarter average production		97,500 - 100,000 BOE/day
Second quarter average crude oil and natural gas liquids production		51,500 - 53,000 bbls/day
Average royalty and production tax rate (% of gross sales, before transportation)		25%
Operating expenses		$8.00/BOE
Transportation costs		$4.00/BOE
Cash G&A expenses		$1.50/BOE


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

(1)

Excludes transportation costs.

12 ENERPLUS 2019 Q1 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 March 31,
($ millions)	2019		2018
Oil and natural gas sales	$	356.4	$	328.5
Less:
Royalties		(68.9)		(63.5)
Production taxes		(14.6)		(16.1)
Cash operating expenses		(69.8)		(53.8)
Transportation costs		(31.3)		(26.9)
Netback before hedging	$	171.8	$	168.2
Cash gains/(losses) on derivative instruments		10.5		10.1
Netback after hedging	$	182.3	$	178.3

“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 net cash 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 March 31,
($ millions)	2019		2018
Cash flow from operating activities	$	109.0	$	159.3
Asset retirement obligation expenditures		5.4		3.3
Changes in non-cash operating working capital		54.4		(7.4)
Adjusted funds flow	$	168.8	$	155.2

“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 March 31,
($ millions)	2019		2018
Adjusted funds flow	$	168.8	$	155.2
Capital spending		(160.8)		(151.5)
Free cash flow	$	8.0	$	3.7

“Adjusted net income” is used by Enerplus and is useful to investors and securities analyst 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 and the tax effect of these items.


Calculation of Adjusted Net Income	Three months ended March 31,
($ millions)	2019		2018
Net income/(loss)	$	19.2	$	29.6
Unrealized derivative instrument (gain)/loss		95.3		29.6
Unrealized foreign exchange (gain)/loss		(17.1)		17.6
Tax effect on above items		(24.9)		(8.4)
Adjusted net income	$	72.5	$	68.4

“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 Q1 REPORT 13

“ 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 March 31,
($ millions)	2019		2018
Dividends	$	7.2	$	7.3
Capital, office expenditures and line fill		167.0		152.9
Sub-total	$	174.2	$	160.2
Adjusted funds flow	$	168.8	$	155.2
Adjusted payout ratio (%)		103%		103%

“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)	March 31, 2019
Net income/(loss)	$	367.8
Add:
Interest		36.1
Current and deferred tax expense/(recovery)		67.3
DD&A and asset impairment		316.1
Other non-cash charges (2)		(9.7)
Adjusted EBITDA	$	777.6

(1)

Adjusted EBITDA is calculated based on the trailing four quarters. Balances above at March 31, 2019 include the three months ended March 31, 2019 and the second, 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 March 31, 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 January 1, 2019 and ended March 31, 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 .

14 ENERPLUS 2019 Q1 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, including second quarter, 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 current NCIB and share repurchases thereunder; 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$60.00/bbl, a NYMEX price of US$2.75/Mcf, and a USD/CDN exchange rate of 1.33. 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 Q1 REPORT 15

STATEMENTS

Exhibit 99.2

Condensed Consolidated Balance Sheets


(CDN$ thousands) unaudited	Note	March 31, 2019		December 31, 2018
Assets
Current Assets
Cash and cash equivalents		$	318,996	$	363,327
Accounts receivable	4		153,805		145,206
Income tax receivable	14		57,746		55,172
Derivative financial assets	16		5,541		59,258
Other current assets			6,822		8,928
			542,910		631,891
Property, plant and equipment:
Oil and natural gas properties (full cost method)	5		1,368,294		1,293,941
Other capital assets, net	5		18,468		13,130
Property, plant and equipment			1,386,762		1,307,071
Right-of-use assets	3,10		64,934		—
Goodwill			650,498		654,799
Derivative financial assets	16		4,252		32,220
Deferred income tax asset	14		477,274		465,124
Income tax receivable	14		28,470		27,195
Total Assets		$	3,155,100	$	3,118,300

Liabilities
Current liabilities
Accounts payable	7	$	301,545	$	290,045
Dividends payable			2,383		2,395
Current portion of long-term debt	8		59,368		60,001
Derivative financial liabilities	16		15,552		1,909
Current portion of lease liabilities	3,10		16,647		—
			395,495		354,350
Long-term debt	8		623,399		636,849
Asset retirement obligation	9		127,937		126,112
Lease liabilities	3,10		48,377		—
			799,713		762,961
Total Liabilities			1,195,208		1,117,311

Shareholders’ Equity
Share capital – authorized unlimited common shares, no par value Issued and outstanding: March 31, 2019 – 238 million shares December 31, 2018 – 239 million shares	15		3,317,855		3,337,608
Paid-in capital			45,209		46,524
Accumulated deficit			(1,755,757)		(1,772,084)
Accumulated other comprehensive income/(loss)			352,585		388,941
			1,959,892		2,000,989
Total Liabilities & Shareholders' Equity		$	3,155,100	$	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 Q1 REPORT 1

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


		Three months ended
		March 31,
(CDN$ thousands, except per share amounts) unaudited	Note	2019		2018
Revenues
Oil and natural gas sales, net of royalties	11	$	287,452	$	265,020
Commodity derivative instruments gain/(loss)	16		(84,867)		(20,464)
			202,585		244,556
Expenses
Operating			69,793		53,761
Transportation			31,291		26,921
Production taxes			14,615		16,135
General and administrative	12		21,710		23,224
Depletion, depreciation and accretion			75,911		64,046
Interest			8,393		9,103
Foreign exchange (gain)/loss	13		(12,026)		10,371
Other expense/(income)			(2,862)		(1,183)
			206,825		202,378
Income/(Loss) before taxes			(4,240)		42,178
Current income tax expense/(recovery)	14		(5,530)		66
Deferred income tax expense/(recovery)	14		(17,868)		12,475
Net Income/(Loss)		$	19,158	$	29,637

Other Comprehensive Income/(Loss)
Change in cumulative translation adjustment			(36,356)		34,368
Total Comprehensive Income/(Loss)		$	(17,198)	$	64,005

Net income/(Loss) per share
Basic	15	$	0.08	$	0.12
Diluted	15	$	0.08	$	0.12

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

2 ENERPLUS 2019 Q1 REPORT

Condensed Consolidated Statements of Changes in Shareholders’ Equity


		Three months ended
		March 31,
(CDN$ thousands) unaudited	2019		2018
Share Capital
Balance, beginning of period	$	3,337,608	$	3,386,946
Purchase of common shares under Normal Course Issuer Bid		(24,159)		—
Share-based compensation – treasury settled		4,406		23,389
Stock Option Plan – cash		—		1,429
Stock Option Plan – exercised		—		114
Balance, end of period	$	3,317,855	$	3,411,878

Paid-in Capital
Balance, beginning of period	$	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		8,043		9,079
Stock Option Plan – exercised		—		(114)
Balance, end of period	$	45,209	$	60,951

Accumulated Deficit
Balance, beginning of period	$	(1,772,084)	$	(2,124,676)
Purchase of common shares under Normal Course Issuer Bid		4,331		—
Net income/(loss)		19,158		29,637
Dividends declared ($0.01 per share)		(7,162)		(7,320)
Balance, end of period	$	(1,755,757)	$	(2,102,359)

Accumulated Other Comprehensive Income/(Loss)
Balance, beginning of period	$	388,941	$	263,124
Change in cumulative translation adjustment		(36,356)		34,368
Balance, end of period	$	352,585	$	297,492
Total Shareholders’ Equity	$	1,959,892	$	1,667,962

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

ENERPLUS 2019 Q1 REPORT 3

Condensed Consolidated Statements of Cash Flows


		Three months ended
		March 31,
(CDN$ thousands) unaudited	Note	2019		2018
Operating Activities
Net income/(loss)		$	19,158	$	29,637
Non-cash items add/(deduct):
Depletion, depreciation and accretion			75,911		64,046
Changes in fair value of derivative instruments	16		95,328		29,622
Deferred income tax expense/(recovery)	14		(17,868)		12,475
Foreign exchange (gain)/loss on debt and working capital	13		(17,104)		17,649
Share-based compensation and general and administrative	12,15		8,134		9,079
Translation of U.S. dollar cash held in Canada	13		5,196		(7,346)
Asset retirement obligation expenditures	9		(5,390)		(3,331)
Changes in non-cash operating working capital	18		(54,414)		7,469
Cash flow from/(used in) operating activities			108,951		159,300

Financing Activities
Proceeds from the issuance of shares	15		—		1,429
Purchase of common shares under Normal Course Issuer Bid	15		(19,828)		—
Share-based compensation – cash settled (tax withholding)	15		(4,952)		—
Dividends	15,18		(7,174)		(7,294)
Cash flow from/(used in) financing activities			(31,954)		(5,865)

Investing Activities
Capital and office expenditures	18		(111,795)		(108,212)
Property and land acquisitions			(2,981)		(6,190)
Property divestments			422		888
Cash flow from/(used in) investing activities			(114,354)		(113,514)
Effect of exchange rate changes on cash and cash equivalents			(6,974)		9,926
Change in cash and cash equivalents			(44,331)		49,847
Cash and cash equivalents, beginning of period			363,327		346,548
Cash and cash equivalents, end of period		$	318,996	$	396,395

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

4 ENERPLUS 2019 Q1 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 months ended March 31, 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 Condensed Consolidated Financial Statements should be read in conjunction with Enerplus’ audited Consolidated Financial Statements as of December 31, 2018. There are no differences in the use of estimates or judgments between these interim Condensed Consolidated Financial Statements and the 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 (“ROU”) assets, current lease liabilities, and long-term lease liabilities in the Consolidated Balance Sheets.

ENERPLUS 2019 Q1 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 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 lease payments 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, and will be applied prospectively. Enerplus does not expect to early adopt the standard. The amended standard may affect goodwill impairment tests past the adoption date, the impact of which is not known.

4) ACCOUNTS RECEIVABLE


($ thousands)	March 31, 2019		December 31, 2018
Accrued revenue	$	125,969	$	118,821
Accounts receivable – trade		31,675		30,252
Allowance for doubtful accounts		(3,839)		(3,867)
Total accounts receivable, net of allowance for doubtful accounts	$	153,805	$	145,206

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


			Accumulated Depletion,
As of March 31, 2019			Depreciation, and
($ thousands)		Cost	Impairment			Net Book Value
Oil and natural gas properties (1)	$	14,797,051	$	(13,428,757)	$	1,368,294
Other capital assets		121,349		(102,881)		18,468
Total PP&E	$	14,918,400	$	(13,531,638)	$	1,386,762


			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 Q1 REPORT

6) ASSET IMPAIRMENT

There was no impairment recorded for the three months ended March 31, 2019 and 2018.

The following table outlines the 12-month average trailing benchmark prices and exchange rates used in Enerplus’ ceiling tests from March 31, 2018 through March 31, 2019:



	WTI Crude Oil		Edm Light Crude		U.S. Henry Hub		Exchange Rate
Period	US$/bbl		CDN$/bbl		Gas US$/Mcf		US$/CDN$
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
Q1 2018		53.49		64.57		3.00	1.28

7) ACCOUNTS PAYABLE


($ thousands)	March 31, 2019		December 31, 2018
Accrued payables	$	131,070	$	115,388
Accounts payable – trade		170,475		174,657
Total accounts payable	$	301,545	$	290,045

8) DEBT


($ thousands)	March 31, 2019		December 31, 2018
Current:
Senior notes	$	59,368	$	60,001
Long-term:
Bank credit facility		—		—
Senior notes		623,399		636,849
Total debt	$	682,767	$	696,850

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

Original

Remaining

CDN$ Carrying

Interest

Coupon

Principal

Value

Issue Date

Payment Dates

Principal Repayment

Rate

( $ 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

140,166

May 15, 2012

May 15 and Nov 15

Bullet payment on May 15, 2019

4.34%

CDN$30,000

30,000

May 15, 2012

May 15 and Nov 15

Bullet payment on May 15, 2022

4.40%

US$20,000

26,698

May 15, 2012

May 15 and Nov 15

5 equal annual installments beginning May 15, 2020

4.40%

US$355,000

US$298,000

397,800

June 18, 2009

June 18 and Dec 18

3 equal annual installments June 18, 2019 - 2021

7.97%

US$225,000

US$66,000

88,103

Total carrying value

682,767

9) ASSET RETIREMENT OBLIGATION


	Three months ended		Year ended
($ thousands)	March 31, 2019		December 31, 2018
Balance, beginning of year	$	126,112	$	117,736
Change in estimates		5,279		16,755
Property acquisitions and development activity		483		1,565
Divestments		(8)		(4,585)
Settlements		(5,390)		(11,263)
Accretion expense		1,461		5,904
Balance, end of period	$	127,937	$	126,112

Enerplus has estimated the present value of its asset retirement obligation to be $127.9 million at March 31, 2019 based on a total undiscounted liability of $345.2 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 5.56% (December 31, 2018 – 5.59%).

ENERPLUS 2019 Q1 REPORT 7

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 March 31, 2019
Weighted average remaining lease term (years)
Operating leases		4.6

Weighted average discount rate
Operating leases		4.1%

The components of lease expense for the three months ended March 31, 2019 are as follows:


			Financial Statement
($ thousands)	Lease Expense		Presentation
Operating lease expense (1)	$	4,584	PP&E
Operating lease expense (1)		2,788	Operating expense
Operating lease expense (1)		1,627	G&A expense
Sublease income		(244)	G&A expense
Total	$	8,755

Includes short-term and variable lease costs of $4.4 million.

Maturities of lease liabilities, all of which are classified as operating leases at March 31, 2019, are as follows:


Maturity of Lease Liabilities
($ thousands)	Operating Leases
2019	$	14,292
2020		19,328
2021		13,758
2022		7,390
After 2022		16,990
Total lease payments	$	71,758
Less imputed interest		(6,734)
Total discounted lease payments	$	65,024
Current portion of lease liabilities	$	16,647
Non-current portion of lease liabilities	$	48,377

Supplemental cash flow information related to leases are as follows:


	Three months ended
($ thousands)	March 31, 2019
Cash amounts paid to settle lease liabilities:
Operating cash flow from operating leases	$	4,506
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	18,863

11) OIL AND NATURAL GAS SALES


	Three months ended March 31,
($ thousands)	2019		2018
Oil and natural gas sales	$	356,376	$	328,552
Royalties (1)		(68,924)		(63,532)
Oil and natural gas sales, net of royalties	$	287,452	$	265,020

(1)

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

8 ENERPLUS 2019 Q1 REPORT

Oil and natural gas revenue by country and by product for the three months ended March 31, 2019 and 2018 are as follows:


Three months ended March 31, 2019		Total revenue, net				Natural		Natural gas
($ thousands)		of royalties (1)		Crude oil (2)		gas (2)		liquids (2)		Other (3)
Canada	$	52,895	$	39,417	$	10,367	$	2,486	$	625
United States		234,557		157,841		73,157		3,559		—
Total	$	287,452	$	197,258	$	83,524	$	6,045	$	625


Three months ended March 31, 2018		Total revenue, net				Natural		Natural gas
($ thousands)		of royalties (1)		Crude oil (2)		gas (2)		liquids (2)		Other (3)
Canada	$	50,774	$	35,985	$	9,640	$	4,059	$	1,090
United States		214,246		151,224		58,595		4,427		—
Total	$	265,020	$	187,209	$	68,235	$	8,486	$	1,090

(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 March 31,
($ thousands)	2019		2018
General and administrative expense	$	12,431	$	13,205
Share-based compensation expense		9,279		10,019
General and administrative expense (1)	$	21,710	$	23,224

(1)

Includes cash and non-cash amounts.

13) FOREIGN EXCHANGE


	Three months ended March 31,
($ thousands)	2019		2018
Realized:
Foreign exchange (gain)/loss	$	(118)	$	68
Translation of U.S. dollar cash held in Canada (gain)/loss		5,196		(7,346)
Unrealized:
Translation of U.S. dollar debt and working capital (gain)/loss		(17,104)		17,649
Foreign exchange (gain)/loss	$	(12,026)	$	10,371

14) INCOME TAXES


	Three months ended March 31,
($ thousands)	2019		2018
Current tax expense/(recovery)
United States	$	(5,530)	$	66
Current tax expense/(recovery)		(5,530)		66
Deferred tax expense/(recovery)
Canada	$	(29,559)	$	(5,510)
United States		11,691		17,985
Deferred tax expense/(recovery)		(17,868)		12,475
Income tax expense/(recovery)	$	(23,398)	$	12,541

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 $477.3 million at March 31, 2019 (December 31, 2018 – $465.1 million).

At March 31, 2019, the current and non-current income tax receivable included $56.9 million and $28.5 million, respectively, relating to a portion of the U.S. Alternative Minimum Tax ("AMT") refund (December 31, 2018 – $54.4 million and $27.2 million, respectively).

ENERPLUS 2019 Q1 REPORT 9

15) SHAREHOLDERS’ EQUITY

a) Share Capital


	Three months ended			Year ended
	March 31, 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	(1,732)		(24,159)	(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	238,243	$	3,317,855	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 months ended March 31, 2019 was $7.2 million (2018 – $7.3 million).

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. During the three months ended March 31, 2019, the Company repurchased 1,732,038 common shares under the previous and current NCIB at an average price of $11.43 per share, for total consideration of $19.8 million. Of the amount paid, $24.1 million was charged to share capital and $4.3 million was credited to accumulated deficit.

Subsequent to the quarter, and up to May 8, 2019, the Company repurchased an additional 1,259,832 common shares under the NCIB at an average price of $11.86 per share, for total consideration of $15.0 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 March 31,
($ thousands)	2019		2018
Cash:
Long-term incentive plans (recovery)/expense	$	1,337	$	1,946
Non-cash:
Long-term incentive plans		8,043		9,079
Equity swap (gain)/loss		(101)		(1,006)
Share-based compensation expense	$	9,279	$	10,019

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 three months ended March 31, 2019:


For the three months ended March 31, 2019	Cash-settled LTI plans	Equity-settled LTI plans		Total
(thousands of units)	DSU	PSU (1)	RSU
Balance, beginning of year	391	1,371	1,753	3,515
Granted	96	797	835	1,728
Vested	—	—	(1,007)	(1,007)
Forfeited	—	—	(11)	(11)
Balance, end of period	487	2,168	1,570	4,225

(1)

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

10 ENERPLUS 2019 Q1 REPORT

Cash-settled LTI Plans

For the three months ended March 31, 2019, the Company recorded cash share-based compensation expense of $1.3 million (March 31, 2018 – $1.9 million). For the three months ended March 31, 2019, the Company made cash payments of nil related to its cash-settled plans (March 31, 2018 – nil).

As of March 31, 2019, a liability of $5.4 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 March 31, 2019 ($ thousands, except for years)	PSU (1)		RSU		Total
Cumulative recognized share-based compensation expense	$	22,392	$	7,590	$	29,982
Unrecognized share-based compensation expense		18,819		12,129		30,948
Fair value	$	41,211	$	19,719	$	60,930
Weighted-average remaining contractual term (years)		2.1		1.8

(1)

Includes estimated performance multipliers .

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

Cash paid by Enerplus when directly withholding shares for tax-withholding purposes have been classified as a financing activity in the Condensed Consolidated Statements of Cash Flows. As of March 31, 2019, $5.0 million was settled (2018 – nil).

ii) Stock Option Plan

At March 31, 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 three months ended March 31, 2019:


	Number of Options	Weighted Average
Period ended March 31, 2019	(thousands)	Exercise Price
Options outstanding, beginning of year	4,131	$	17.12
Forfeited	(31)		17.74
Expired	(1,436)		22.79
Options outstanding, end of period	2,664	$	14.05
Options exercisable, end of period	2,664	$	14.05

At March 31, 2019, Enerplus had 2,663,579 options that were exercisable at a weighted average exercise price of $14.05 with a weighted average remaining contractual term of 0.8 years, giving an aggregate intrinsic value of nil (March 31, 2018 – 1.5 years and $2.2 million). The intrinsic value of options exercised for the three months ended March 31, 2019 was nil (March 31, 2018 – $0.2 million).

ENERPLUS 2019 Q1 REPORT 11

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

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


	Three months ended March 31,
(thousands, except per share amounts)	2019		2018
Net income/(loss)	$	19,158	$	29,637

Weighted average shares outstanding – Basic		238,922		243,874
Dilutive impact of share-based compensation		2,376		5,317
Weighted average shares outstanding – Diluted		241,298		249,191
Net income/(loss) per share
Basic	$	0.08	$	0.12
Diluted	$	0.08	$	0.12

16) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

a) Fair Value Measurements

At March 31, 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 March 31, 2019, the senior notes had a carrying value of $682.8 million and a fair value of $686.7 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.

The following table summarizes the change in fair value for the three months ended March 31, 2019 and 2018:


	Three months ended March 31,				Income Statement
Gain/(Loss) ($ thousands)	2019		2018		Presentation
Electricity Swaps	$	—	$	(16)	Operating expense
Equity Swaps		101		1,006	G&A expense
Commodity Derivative Instruments:
Oil		(86,929)		(29,855)	Commodity derivative
Gas		(8,500)		(757)	instruments
Total	$	(95,328)	$	(29,622)

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


	Three months ended March 31,
($ thousands)	2019		2018
Change in fair value gain/(loss)	$	(95,429)	$	(30,612)
Net realized cash gain/(loss)		10,562		10,148
Commodity derivative instruments gain/(loss)	$	(84,867)	$	(20,464)

12 ENERPLUS 2019 Q1 REPORT

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


	March 31, 2019						December 31, 2018
	Assets				Liabilities		Assets					Liabilities
($ thousands)	Current			Long-term	Current		Current		Long Term			Current
Equity Swaps	$	—	$	—	$	1,808	$	—	$	—	$	1,909
Commodity Derivative Instruments:
Oil		3,097		4,252		13,744		48,314		32,220		—
Gas		2,444		—		—		10,944		—		—
Total	$	5,541	$	4,252	$	15,552	$	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 May 8, 2019:

Crude Oil Instruments:


Instrument Type (1)(2)	bbls/day	US$/bbl

Apr 1, 2019 – Jun 30, 2019
WTI Purchased Put	23,500	54.59
WTI Sold Call	23,500	65.52
WTI Sold Put	23,500	44.50
WCS Differential Swap	1,500	(14.83)
WTI – Brent Swap	2,700	(8.10)

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)

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)

Jan 1, 2020 – Dec 31, 2020
WTI Purchased Put	16,000	57.50
WTI Sold Call	16,000	72.50
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 three way collars is US$1.59/bbl from April 1, 2019 to December 31, 2020.

For the remainder of 2019, Enerplus has physical sales contracts in place for approximately 19,000 bbls/day of Bakken production with fixed differentials averaging approximately US$1.90/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.

ENERPLUS 2019 Q1 REPORT 13

Natural Gas Instruments:


Instrument Type (1)	MMcf/day	US$/Mcf

Apr 1, 2019 – Oct 31, 2019
NYMEX Swap	90.0	2.85

(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 March 31, 2019, Enerplus did not have any foreign exchange derivatives outstanding.

Interest Rate Risk:

At March 31, 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 in 2019 that effectively fix the future settlement cost on 195,000 shares at a weighted average price of $20.60 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 March 31, 2019, 85% 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 March 31, 2019 was $3.8 million (December 31, 2018 – $3.9 million).

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 shareholders’ 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 March 31, 2019, Enerplus was in full compliance with all covenants under the bank credit facility and outstanding senior notes.

14 ENERPLUS 2019 Q1 REPORT

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 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

Changes in Non-Cash Operating Working Capital


	Three months ended March 31,
($ thousands)	2019		2018
Accounts receivable	$	(14,179)	$	(6,637)
Other assets		(3,027)		1,621
Accounts payable		(37,208)		12,485
	$	(54,414)	$	7,469

Changes in Other Non-Cash Working Capital


	Three months ended March 31,
($ thousands)	2019		2018
Non-cash financing activities (1)	$	(12)	$	26
Non-cash investing activities (2)		50,101		44,660

(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.

Other


	Three months ended March 31,
($ thousands)	2019		2018
Income taxes paid/(received)	$	64	$	(85)
Interest paid		3,259		3,256

ENERPLUS 2019 Q1 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 March 31, 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.

5.1 Control 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.

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

5.3 Limitation 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 January 1, 2019 and ended on March 31, 2019 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: May 10, 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 March 31, 2019.

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

5.1 Control 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.

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

5.3 Limitation on scope of design: N/A

Date: May 10, 2019


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