Enerplus (ERF) 40-F 2018 FY Annual report (Canada)

Contents
1	Financial Summary
3	Highlights
4	Management’s Discussion and Analysis
37	Financial Statements
63	Five Year Detailed Statistical Review
65	Supplemental Information
66	Abbreviations and Definitions
69	Board of Directors
70	Officers
71	Corporate Information

 2018 FINANCIAL SUMMARY

	Three months ended					Twelve months ended
SELECTED FINANCIAL RESULTS	December 31,					December 31,
		2018		2017			2018		2017
Financial (000’s)
Net Income		$	249,315	$	15,272		$	378,279	$	236,998
Cash Flow from Operating Activities			221,619		135,332			738,784		476,125
Adjusted Funds Flow(4)			214,285		199,559			753,506		524,064
Dividends to Shareholders - Declared			7,234		7,264			29,256		29,033
Total Debt Net of Cash(4)			333,523		325,831			333,523		325,831
Capital Spending			72,058		116,827			593,876		458,015
Property and Land Acquisitions			9,474		3,805			25,840		13,276
Property Divestments			886		(1,385)			6,912		56,196
Net Debt to Adjusted Funds Flow Ratio(4)			0.4x		0.6x			0.4x		0.6x
Financial per Weighted Average Shares Outstanding
Net Income - Basic		$	1.03	$	0.06		$	1.55	$	0.98
Net Income - Diluted			1.02		0.06			1.53		0.96
Weighted Average Number of Shares Outstanding (000’s) - Basic			242,344		242,129			244,076		241,929
Weighted Average Number of Shares Outstanding (000’s) - Diluted			245,242		248,122			247,261		247,874
Selected Financial Results per BOE(1)(2)
Oil & Natural Gas Sales(3)		$	45.43	$	41.72		$	47.35	$	36.93
Royalties and Production Taxes			(11.58)		(10.65)			(11.92)		(8.91)
Commodity Derivative Instruments			(0.31)		(0.39)			(1.05)		0.28
Cash Operating Expenses			(6.99)		(6.42)			(7.00)		(6.39)
Transportation Costs			(3.71)		(3.20)			(3.63)		(3.60)
General and Administrative Expenses			(1.40)		(1.55)			(1.47)		(1.63)
Cash Share-Based Compensation			0.23		(0.01)			(0.01)		(0.03)
Interest, Foreign Exchange and Other Expenses			(0.90)		(1.17)			(0.92)		(1.24)
Current Income Tax Recovery			3.03		6.15			0.80		1.55
Adjusted Funds Flow(4)		$	23.80	$	24.48		$	22.15	$	16.96

	Three months ended					Twelve months ended
SELECTED OPERATING RESULTS	December 31,					December 31,
		2018		2017			2018		2017
Average Daily Production(2)
Crude Oil (bbls/day)			49,968		42,374			45,424		36,935
Natural Gas Liquids (bbls/day)			4,483		4,448			4,486		3,858
Natural Gas (Mcf/day)			260,453		250,607			259,837		263,506
Total (BOE/day)			97,860		88,590			93,216		84,711
% Crude Oil and Natural Gas Liquids			56%		53%			54%		48%
Average Selling Price(2)(3)
Crude Oil (per bbl)		$	64.18	$	65.91		$	74.59	$	58.69
Natural Gas Liquids (per bbl)			26.72		32.26			28.31		30.01
Natural Gas (per Mcf)			4.28		3.03			3.42		3.21
Net Wells Drilled			12		7			61		46

(1) Non‑cash amounts have been excluded.

(2) Based on Company interest production volumes. See “Basis of Presentation” section in the following MD&A.

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

(4) These non‑GAAP measures may not be directly comparable to similar measures presented by other entities. See “Non‑GAAP Measures” section in the following MD&A.

ENERPLUS 2018 FINANCIAL SUMMARY             1

	Three months ended					Twelve months ended
	December 31,					December 31,
Average Benchmark Pricing		2018		2017			2018		2017
WTI crude oil (US$/bbl)		$	58.81	$	55.40		$	64.77	$	50.95
Brent (ICE) crude oil (US$/bbl)			68.08		61.54			71.53		54.83
NYMEX natural gas – last day (US$/Mcf)			3.64		2.93			3.09		3.11
AECO natural gas – monthly index (CDN$/Mcf)			1.90		1.96			1.53		2.43
US/CDN average exchange rate			1.32		1.27			1.30		1.30

Share Trading Summary	CDN(1) – ERF		U.S.(2) – ERF
For the twelve months ended December 31, 2018	(CDN$)		(US$)
High	$	18.04	$	13.87
Low	$	9.65	$	6.84
Close	$	10.62	$	7.76

(1) TSX and other Canadian trading data combined.

(2) NYSE and other U.S. trading data combined.

2018 Dividends per Share		CDN$		US$(1)
First Quarter Total	$	0.03	$	0.02
Second Quarter Total	$	0.03	$	0.02
Third Quarter Total	$	0.03	$	0.02
Fourth Quarter Total	$	0.03	$	0.02
Total Year to Date	$	0.12	$	0.08

(1) CDN$ dividends converted at the relevant foreign exchange rate on the payment date.

2ENERPLUS 2018 FINANCIAL SUMMARY

 2018 HIGHLIGHTS

Financial and Operational Highlights

· Fourth quarter 2018 production was at the high-end of the Company’s guidance range and modestly higher than the prior quarter. Total fourth quarter production averaged 97,860 BOE per day, including oil and natural gas liquids production of 54,451 barrels per day (92% oil).

· Full year 2018 production was also at the high-end of the Company’s guidance range, averaging 93,216 BOE per day, including 49,910 barrels per day of crude oil and natural gas liquids (91% oil). Year-over-year, the Company’s 2018 production increased by 10%, with liquids production increasing by 22%. This growth was largely driven by North Dakota production which increased by 42%.

· Higher realized commodity prices and increased production volumes resulted in significant increases to cash flow from operating activities and adjusted funds flow for 2018 compared to 2017. 

o Fourth quarter cash flow from operating activities increased to $221.6 million from $216.1 million in the third quarter. Full year 2018 cash flow from operating activities was $738.8 million, 55% higher than 2017.

o Fourth quarter adjusted funds flow increased to $214.3 million from $210.4 million in the third quarter. Fourth quarter adjusted funds flow benefited from a $27.2 million Alternative Minimum Tax (“AMT”) refund expected to be realized in 2019. Enerplus expects to realize the remaining $27.2 million in AMT refund in 2020 and 2021. Full year 2018 adjusted funds flow was $753.5 million, 44% higher than 2017.

· Fourth quarter net income was $249.3 million ($1.03 per share) compared to $86.9 million ($0.35 per share) in the prior quarter. Full year 2018 net income was $378.3 million ($1.55 per share) compared to $237.0 million ($0.98 per share) in 2017.

· Fourth quarter adjusted net income was $102.2 million ($0.42 per share) compared to $97.3 million ($0.40 per share) in the prior quarter. Full year 2018 adjusted net income was $344.8 million ($1.41 per share) compared to $132.2 million ($0.55 per share) in 2017.

· Capital spending was $72.1 million in the fourth quarter of 2018, bringing full year 2018 capital spending to $593.9 million, in-line with the Company’s $585 million 2018 budget.

· Enerplus remains in a strong financial position. The Company’s net debt at December 31, 2018 was $333.5 million, comprised of $696.8 million of senior notes less $363.3 million in cash. At December 31, 2018, Enerplus was undrawn on its $800 million bank credit facility and had a net debt to adjusted funds flow ratio of 0.4 times.

· During 2018 Enerplus repurchased 5,925,084 common shares at an average share price of $13.33 and a cost of $79.0 million.

Reserves Highlights

· Replaced 194% of 2018 production, adding 65.7 MMBOE (51% oil) of 2P reserves from development activities (including revisions and economic factors).

· Material reserves growth was realized in North Dakota and the Marcellus. The Company replaced 244% of 2018 North Dakota production, adding 35.1 MMBOE of 2P reserves and 247% of 2018 Marcellus production, adding 187.4 Bcf of 2P reserves (including revisions and economic factors).

· Finding and development (“F&D”) costs were $13.08 per BOE for proved developed producing (“PDP”) reserves, $16.69 per BOE for proved reserves, and $13.74 per BOE for 2P reserves, including future development costs (“FDC”).

· Three-year average F&D costs were $10.17 per BOE for PDP reserves, $10.27 per BOE for proved reserves, and $10.04 per BOE for 2P reserves, including FDC.

· Finding, development and acquisition (“FD&A”) costs were $17.42 per BOE for proved reserves and $14.37 per BOE for 2P reserves, including FDC.

· Three-year average FD&A costs were $7.55 per BOE for proved reserves and $8.26 per BOE for 2P reserves, including FDC.

· Total 2P reserves were 427.7 MMBOE at year-end 2018, representing an 8% increase from year-end 2017.

· 2P reserves were comprised of 49% crude oil, 5% natural gas liquids, and 46% natural gas at year-end 2018.

· Proved developed producing reserves and total proved reserves represent 46% and 70% of 2P reserves, respectively.

ENERPLUS 2018 FINANCIAL SUMMARY             3

 MD&A

Exhibit 99.3

Management’s Discussion and Analysis (“MD&A”)

The following discussion and analysis of financial results is dated February 21, 2019 and is to be read in conjunction with the audited Consolidated Financial Statements (the “Financial Statements”) of Enerplus Corporation (“Enerplus” or the “Company”), as at December 31, 2018 and 2017 and for the years ended December 31, 2018, 2017 and 2016.

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 this MD&A for further information.

BASIS OF PRESENTATION

The Financial Statements and notes have been prepared in accordance with U.S. GAAP. All amounts are stated in Canadian dollars unless otherwise specified and all note references relate to the notes included with the 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 BOE and oil and natural gas liquids (“NGL”) have been converted to thousand cubic feet of gas equivalent (“Mcfe”) based on 0.167 bbl:1 Mcfe. The BOE and Mcfe rates are based on an energy equivalent conversion method primarily applicable at the burner tip and do not represent a value equivalent at the wellhead. Given that the value ratio based on the current price of natural gas as compared to crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. Use of BOE and Mcfe in isolation may be misleading. All production volumes are presented on a Company interest basis, being the Company’s working interest share before deduction of any royalties paid to others, plus the Company’s royalty interests, unless otherwise stated. Company interest is not a term defined in Canadian National Instrument 51‑101– Standards of Disclosure for Oil and Gas Activities (“NI 51‑101”) and may not be comparable to information produced by other entities. All reserves information presented herein has been prepared in accordance with NI 51-101 and is presented at December 31, 2018 unless otherwise stated.

In accordance with U.S. GAAP, oil and natural gas sales are presented net of royalties in the Financial Statements. Under International Financial Reporting Standards, industry standard is to present oil and natural gas sales before deduction of royalties and as such this MD&A presents production, oil and natural gas sales, and BOE measures before deduction of royalties to remain comparable with our Canadian peers.

The following table provides a reconciliation of our production volumes:

		Year ended December 31,
Average Daily Production Volumes	2018		2017		2016
Company interest production volumes
Crude oil (bbls/day)		45,424		36,935		38,353
Natural gas liquids (bbls/day)		4,486		3,858		4,903
Natural gas (Mcf/day)		259,837		263,506		299,214
Company interest production volumes (BOE/day)		93,216		84,711		93,125
Royalty volumes
Crude oil (bbls/day)		9,054		7,531		7,198
Natural gas liquids (bbls/day)		951		777		932
Natural gas (Mcf/day)		48,923		47,722		50,270
Royalty volumes (BOE/day)		18,159		16,262		16,508
Net production volumes
Crude oil (bbls/day)		36,370		29,404		31,155
Natural gas liquids (bbls/day)		3,535		3,081		3,971
Natural gas (Mcf/day)		210,914		215,784		248,944
Net production volumes (BOE/day)		75,057		68,449		76,617

4ENERPLUS 2018 FINANCIAL SUMMARY

2018 FOURTH QUARTER OVERVIEW

Fourth quarter production averaged 97,860 BOE/day, which was higher than our third quarter production of 96,861 BOE/day. Crude oil and natural gas liquids production increased by 2% to 54,451 bbls/day compared to the third quarter and was at the high end of our fourth quarter liquids production guidance range of 53,500 – 54,500 bbls/day. Our fourth quarter capital spending of $72.1 million was largely focused on drilling in North Dakota in preparation for the 2019 capital program.

We reported net income of $249.3 million in the fourth quarter compared to net income of $86.9 million in the third quarter. The increase is primarily the result of a $253.7 million gain on commodity derivative instruments compared to a $54.1 million loss in the third quarter of 2018 due to crude oil prices falling below the swap and purchased put levels on our three-way collars. 

Fourth quarter cash flow from operating activities and adjusted funds flow increased to $221.6 million and $214.3 million, respectively, from $216.1 million and $210.4 million, respectively, in the third quarter. The increases were due to higher realized natural gas prices in the Marcellus, offset by a decrease in crude oil revenue.  Adjusted funds flow in the fourth quarter benefited from a $27.2 million Alternative Minimum Tax (“AMT”) refund, expected to be realized in 2019.

During the fourth quarter, we had $142.2 million in free cash flow, enabling our repurchase of 5.4 million common shares for $70.6 million, bringing total repurchases in 2018 to $79.0 million (5.9 million shares), and further enhancing our per share growth and the return of capital to shareholders.

Selected Fourth Quarter Canadian and U.S. Financial Results

	Three months ended						Three months ended
	December 31, 2018						December 31, 2017
(millions, except per unit amounts)	Canada		U.S.		Total		Canada		U.S.		Total
Average Daily Production Volumes(1)
Crude oil (bbls/day)		9,237		40,731		49,968		9,478		32,896		42,374
Natural gas liquids (bbls/day)		956		3,527		4,483		1,198		3,250		4,448
Natural gas (Mcf/day)		23,357		237,096		260,453		37,265		213,342		250,607
Total average daily production (BOE/day)		14,086		83,774		97,860		16,887		71,703		88,590
Pricing(2)
Crude oil (per bbl)	$	33.76	$	71.07	$	64.18	$	57.05	$	68.46	$	65.91
Natural gas liquids (per bbl)		39.69		23.20		26.72		44.07		27.91		32.26
Natural gas (per Mcf)		3.74		4.33		4.28		3.01		3.04		3.03
Capital Expenditures
Capital spending	$	13.5	$	58.6	$	72.1	$	10.9	$	105.9	$	116.8
Acquisitions		1.2		8.3		9.5		1.1		2.7		3.8
Divestments		0.9		(1.8)		(0.9)		0.9		0.5		1.4
Netback(3) Before Hedging
Oil and natural gas sales	$	40.9	$	368.3	$	409.2	$	64.9	$	275.2	$	340.1
Royalties		(5.4)		(77.0)		(82.4)		(13.9)		(55.1)		(69.0)
Production taxes		(0.4)		(21.5)		(21.9)		(0.7)		(17.1)		(17.8)
Cash operating expenses		(17.8)		(45.1)		(62.9)		(18.2)		(34.1)		(52.3)
Transportation costs		(2.6)		(30.8)		(33.4)		(2.9)		(23.3)		(26.2)
Netback before hedging	$	14.7	$	193.9	$	208.6	$	29.2	$	145.6	$	174.8
Other Expenses
Commodity derivative instruments loss/(gain)	$	(253.7)	$	—	$	(253.7)	$	41.0	$	—	$	41.0
General and administrative expense(4)		11.6		7.5		19.1		13.9		5.8		19.7
Current income tax recovery		—		(27.4)		(27.4)		—		(50.2)		(50.2)

(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.

ENERPLUS 2018 FINANCIAL SUMMARY             5

Comparing the fourth quarter of 2018 with the same period in 2017:

· Average daily production was 97,860 BOE/day, an increase of 10% from 88,590 BOE/day, primarily due to a 24% increase in U.S. crude oil production as a result of strong well performance and a larger capital spending program in North Dakota in 2018.

· Our crude oil and natural gas liquids production accounted for 56% of our total production mix in the fourth quarter of 2018, an increase from 53% in 2017.

· Capital spending decreased to $72.1 million compared to $116.8 million in the fourth quarter of 2017 due to the timing of our 2018 capital program and limited completions activity in the fourth quarter. The majority of our capital investment in the fourth quarter was focused on drilling our U.S. crude oil properties, with spending of $51.7 million.

· Operating expenses increased to $62.9 million ($6.99/BOE) compared to $52.1 million ($6.39/BOE) in the fourth quarter of 2017 as a result of an increased weighting of crude oil and liquids production with higher associated operating cost metrics.

· Cash general and administrative (“G&A”) expenses were unchanged but improved on a per BOE basis from $12.6 million ($1.40/BOE) compared to $12.6 million ($1.55/BOE) in 2017 with increased production volumes.

· During the fourth quarter of 2018, our Bakken crude oil price differential widened to US$5.60/bbl below WTI compared to US$1.61/bbl below WTI for the same period in 2017, as a result of significant refinery maintenance reducing demand in the region. Our Marcellus natural gas differential narrowed in the fourth quarter to US$0.34/Mcf below NYMEX compared to US$0.81/Mcf below NYMEX in 2017, due to additional pipeline capacity that came online during the year.

· We reported net income of $249.3 million in the fourth quarter of 2018 compared to net income of $15.3 million in the fourth quarter of 2017. Net income increased by $234.0 million primarily due to a $253.7 million gain on commodity derivative instruments in 2018 compared to a $41.0 million loss recorded in 2017.

· Cash flow from operating activities and adjusted funds flow increased to $221.6 million and $214.3 million, respectively, compared to $135.3 million and $199.6 million, respectively, in the fourth quarter of 2017. The increases were the result of higher production and stronger natural gas prices in the Marcellus offset by wider Bakken crude oil differentials in the fourth quarter of 2018.

· During the fourth quarter of 2018, we repurchased 5.4 million common shares under our Normal Course Issuer Bid (“NCIB”) for total consideration of $70.6 million, bringing our total repurchases to 5.9 million shares for total consideration of $79.0 million in 2018.

· Net debt to adjusted funds flow improved to 0.4x compared to 0.6x in the fourth quarter of 2017.

2018 OVERVIEW AND 2019 OUTLOOK

Summary of Guidance and Results	Revised 2018 Guidance	2018 Results	2019 Guidance
Capital spending ($ millions)	$ 585	$ 594	$565 - $635
Average annual production (BOE/day)	92,500 - 93,000	93,216	94,000 – 100,000
Average annual crude oil and natural gas liquids production (bbls/day)	49,500 - 50,000	49,910	52,500 – 56,000
Fourth quarter average crude oil and natural gas liquids production (bbls/day)	53,500 - 54,500	54,451
Average royalty and production tax rate (% of gross sales, before transportation)	25%	25%	25%
Operating expenses (per BOE)	$ 7.00	$ 7.00	$ 8.00
Transportation costs (per BOE)	$ 3.60	$ 3.63	$ 4.00
Cash G&A expenses (per BOE)	$ 1.50	$ 1.47	$ 1.50
2019 Differential/Basis Outlook and Results(1)
Average U.S. Bakken crude oil differential (compared to WTI crude oil)	US$(3.80)/bbl	US$(3.78)/bbl	US$(4.00)/bbl
Average Marcellus natural gas differential (compared to NYMEX natural gas)	US$(0.40)/Mcf	US$(0.43)/Mcf	US$(0.30)/Mcf

(1) Excludes transportation costs

6ENERPLUS 2018 FINANCIAL SUMMARY

2018 Overview

In 2018, we continued to focus on maximizing returns, sustainable growth, as well as returning capital to our shareholders. We delivered total production growth of 10% and liquids growth of 22% compared to 2017 and returned $108.3 million of capital to our shareholders through share repurchases and dividends, while maintaining our balance sheet strength.

In 2018, our annual average production was 93,216 BOE/day with crude oil and liquids volumes of 49,910 bbls/day, at the high end of our revised production guidance targets of 92,500 – 93,000 BOE/day and 49,500 – 50,000 bbls/day, respectively. Our capital spending for the year totaled $593.9 million, in line with our guidance of $585 million. The majority of our spending (88%) was focused on our liquids properties, primarily in North Dakota. 

Our Bakken sales price differentials remained consistent with the prior year averaging US$3.78/bbl below WTI, which was in line with our revised guidance of US$3.80/bbl below WTI. Our Marcellus differential narrowed to US$0.43/Mcf below NYMEX, a 43% improvement compared to 2017,  due to additional pipeline capacity coming into service. Canadian crude oil and natural gas differentials weakened  significantly in 2018, averaging US$21.83/bbl below WTI and US$0.81/Mcf below NYMEX, respectively, mainly due to limited pipeline takeaway capacity and  storage concerns. 

Operating expenses and cash G&A expenses were $7.00/BOE and $1.47/BOE, respectively, consistent with our guidance of $7.00/BOE and $1.50/BOE, respectively.

Net income for 2018 was $378.3 million, an increase from $237.0 million in 2017 primarily due to higher revenue as a result of an increase in production,  realized pricing and gains on commodity derivative instruments. The higher production also increased operating, royalty and depletion expenses, which partially offset the higher revenue in 2018 when compared to 2017.  

Cash flow from operations and adjusted funds flow increased significantly to $738.8 million and $753.5 million, respectively, from $476.1 million and $524.1 million, respectively, in 2017. Oil and natural gas sales increased by $469.1 million, compared to 2017, largely due to higher realized commodity prices, narrower sales price differentials in the Marcellus and higher production volumes. This increase was partially offset by higher operating and royalty expenses in 2018.

Total debt net of cash at December 31, 2018 was $333.5 million, comprised of $696.8 million of senior notes less $363.3 million in cash. At December 31, 2018, we were undrawn on our $800 million senior unsecured bank credit facility and had a net debt to adjusted funds flow ratio of 0.4x.   

2019 Outlook

Our focus in 2019 is to continue to maximize returns, while delivering sustainable liquids production growth, returning capital to shareholders and preserving our balance sheet strength. Our capital budget range for 2019 is between $565 million and $635 million, with the majority of capital being allocated to our North Dakota crude oil properties. As a result, we expect annual liquids production growth of approximately 9% at the mid-point of production guidance in 2019.

Annual 2019 production is expected to average between 94,000 – 100,000 BOE/day, with crude oil and natural gas liquids production expected to average between 52,500 – 56,000 bbls/day. As a result of lower capital spending in the fourth quarter of 2018, we expect the majority of our production growth to occur during the second half of 2019.

We expect our Bakken sales price differential to widen slightly in 2019 to be approximately US$4.00/bbl below WTI, which includes 16,000 bbls/day of fixed price differential sales at approximately US$3.00/bbl below WTI. In the Marcellus, we expect our sales price differential to improve to approximately US$0.30/Mcf below NYMEX as a result of excess pipeline egress out of the region. 

To support our 2019 capital program, we have hedged 63% of our 2019 forecasted crude oil production, after royalties, primarily through the use of three-way collar structures. We also have additional natural gas hedges in 2019 for approximately 34% of our forecasted 2019 natural gas production, after royalties.

Operating expenses are expected to average approximately $8.00/BOE in 2019, an increase from 2018, as a result of the increase to our crude oil and liquids weighting throughout 2019, as well as an increase in gas processing costs and the use of electrical submersible pumps in North Dakota. We continue to focus our capital program on crude oil production growth, which has higher operating cost metrics. 

We expect cash G&A expenses and transportation costs for 2019 to average approximately $1.50/BOE and $4.00/BOE, respectively. The increase in transportation costs reflects additional transportation commitments that provide access to sell a portion of our production at U.S. gulf coast or Brent pricing.

ENERPLUS 2018 FINANCIAL SUMMARY             7

RESULTS OF OPERATIONS

Production

Average Daily Production Volumes	2018	2017	2016
Crude oil (bbls/day)	45,424	36,935	38,353
Natural gas liquids (bbls/day)	4,486	3,858	4,903
Natural gas (Mcf/day)	259,837	263,506	299,214
Total daily sales (BOE/day)	93,216	84,711	93,125

Production in 2018 averaged 93,216 BOE/day, in line with our revised guidance range of 92,500 – 93,000 BOE/day and a 10% increase when compared to 2017. Crude oil and liquids production averaged 49,910 BOE/day, meeting our revised guidance of 49,500 – 50,000 bbls/day, as a result of a successful capital program focused on our U.S. crude oil properties.

Our U.S. production volumes increased by 20% to 78,287 BOE/day compared to 2017, mainly due to a 10,743 bbl/day increase in crude oil and natural gas liquids production as a result of strong well performance in North Dakota and an increase to our 2018 capital spending program. Our U.S. natural gas production increased by 7% with no price related curtailments in the Marcellus during the year.

Canadian production volumes decreased by 4,748 BOE/day or 24% compared to the prior year, largely due to the full year impact of non-core asset divestments that occurred throughout 2017.

Our crude oil and natural gas liquids production accounted for 54% of our total average daily production in 2018, a significant increase when compared to 48% in 2017 and 46% in 2016.

Production for 2017 compared to 2016 decreased 9% or 8,414 bbls/day. The decrease was primarily a result of non-core Canadian divestments throughout 2017 and the sale of our U.S. non-operated North Dakota properties, which closed on December 30, 2016. The impact of divestments was somewhat offset by growth in our operated U.S. crude oil production with the additional capital spending on our North Dakota assets. 

2019 Guidance

We expect annualaverage production for 2019 of 94,000 – 100,000 BOE/day, including 52,500 – 56,000 bbls/day of crude oil and natural gas liquids, resulting in year over year production growth of 4% and liquids production growth of 9% based on  a WTI price of US$50/bbl – US$55/bbl.

Pricing

The prices received for our crude oil and natural gas production directly impact our earnings, cash flow from operating activities, adjusted funds flow and financial condition. The following table summarizes our average selling prices, benchmark prices and differentials:

Pricing (average for the period)	2018		2017		2016
Benchmarks
WTI crude oil (US$/bbl)	$	64.77	$	50.95	$	43.32
Brent (ICE) crude oil (US$/bbl)		71.53		54.83		45.04
NYMEX natural gas – last day (US$/Mcf)		3.09		3.11		2.46
AECO natural gas – monthly index ($/Mcf)		1.53		2.43		2.09
US/CDN average exchange rate		1.30		1.30		1.32
US/CDN period end exchange rate		1.36		1.26		1.34
Enerplus selling price(1)
Crude oil ($/bbl)	$	74.59	$	58.69	$	44.84
Natural gas liquids ($/bbl)		28.31		30.01		15.29
Natural gas ($/Mcf)		3.42		3.21		2.06
Average benchmark differentials
Brent (ICE) - WTI (US$/bbl)	$	6.77	$	3.88	$	1.72
MSW Edmonton – WTI (US$/bbl)		(11.12)		(2.46)		(3.21)
WCS Hardisty – WTI (US$/bbl)		(26.31)		(11.98)		(13.84)
Transco Leidy monthly – NYMEX (US$/Mcf)		(0.64)		(0.96)		(1.15)
TGP Z4 300L monthly – NYMEX (US$/Mcf)		(0.73)		(1.03)		(1.21)
AECO monthly – NYMEX (US$/Mcf)		(1.90)		(1.26)		(0.89)

8ENERPLUS 2018 FINANCIAL SUMMARY

Enerplus realized differentials(1)(2)
Bakken crude oil – WTI (US$/bbl)	$	(3.78)	$	(3.72)	$	(7.46)
Marcellus natural gas – NYMEX (US$/Mcf)		(0.43)		(0.76)		(0.93)
Canada crude oil – WTI (US$/bbl)		(21.83)		(10.94)		(13.21)
Canada natural gas – NYMEX (US$/Mcf)		(0.81)		(0.62)		(0.80)

(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

Benchmark WTI prices increased by 27% to US$64.77/bbl in 2018 compared to 2017, largely due to lower global inventories as a result of the supply reductions made by the Organization of Petroleum Exporting Countries (“OPEC”). In addition, supply concerns, particularly in Venezuela, and the reimposition of U.S. sanctions on Iran supported global crude oil prices for the majority of the year. However, WTI prices declined significantly during the fourth quarter of 2018,  closing at US$45.41/bbl. The decline in oil prices was due to concerns over global trade and ongoing geopolitical issues, which may reduce global demand.  Our 2018 realized crude oil price averaged $74.59/bbl, a 27% increase compared to 2017, in line with changes in the underlying benchmark price.

Our Bakken sales price differentials weakened slightly in 2018 compared to the prior year, averaging US$3.78/bbl below WTI, which was in line with our revised guidance of US$3.80/bbl below WTI. Bakken prices were strong during the second and third quarter of 2018 but weakened significantly during the fourth quarter. This was due to a large amount of demand lost during seasonal refinery maintenance and higher than anticipated production increases that put pressure on regional pipeline capacity. Our realized Bakken differentials were somewhat insulated from the weakness in the fourth quarter of 2018 due to a portion of our physical sales being based on term negotiated fixed differentials to WTI. We expect Bakken differentials to widen slightly in 2019 and are guiding to US$4.00/bbl below WTI,  which includes 16,000 bbls/day of fixed price differential sales at approximately US$3.00/bbl below WTI.  

Canadian crude oil differentials weakened substantially in 2018, with both heavy and light differentials trading at much wider levels compared to the prior year. This was especially evident during the fourth quarter of 2018, as pipeline capacity leaving the region was fully utilized, resulting in a large increase in Canadian crude oil held in storage and a significant volume of production using rail to clear the region. However, differentials have recently strengthened due to Alberta government mandated production curtailments, which were announced in December 2018. Inadequate pipeline takeaway continues to be a major concern throughout the Canadian oil and gas industry. 

We realized an average price of $28.31/bbl on our natural gas liquids production in 2018, which represents a 6% decrease in prices when compared to 2017. This decrease was mainly due to lower condensate prices in both Canada and the U.S.

NATURAL GAS

Our realized natural gas price averaged $3.42/Mcf in 2018, a 7% increase from 2017 realized prices, despite NYMEX and AECO prices both declining on a year-over-year basis. Our realized natural gas price outperformed the benchmarks due to stronger Marcellus basis differentials in 2018 and the positive impact of our multi-year term AECO physical sales which had average fixed basis differentials of US$0.64/Mcf below NYMEX.

In the Marcellus, the Tennessee Gas Pipeline Zone 4 - 300 Leg and Transco Leidy monthly benchmark differentials averaged US$0.73/Mcf and US$0.64/Mcf below NYMEX, respectively, compared to US$1.03/Mcf and US$0.96/Mcf, respectively, below NYMEX in 2017. The strengthening in local Marcellus prices was due to additional pipeline capacity coming into service, as well as stronger weather-related demand in the region. As a result, our realized portfolio sales price differential, before transportation costs, averaged US$0.43/Mcf below NYMEX for the year, which was in line with our guidance of US$0.40/Mcf below NYMEX. We expect our Marcellus differential to average US$0.30/Mcf below NYMEX in 2019 as regional prices continue to benefit from excess pipeline takeaway capacity.

In Alberta, congestion on regional and export pipelines and continued production growth resulted in benchmark AECO monthly prices averaging US$1.90/Mcf below NYMEX in 2018 compared to US$1.26/Mcf below NYMEX in 2017. We continue to benefit from our term AECO physical sales. 

ENERPLUS 2018 FINANCIAL SUMMARY             9

Monthly Crude Oil Prices 

Monthly Natural Gas Prices 

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 weakened throughout 2018, closing the year at 1.36 US/CDN compared to 1.26 US/CDN at December 31, 2017 and averaging 1.30 US/CDN throughout the year. The weakness in the Canadian dollar was driven by decelerating domestic economic growth, changing U.S. and Canada trade policies including the renegotiation of the North American Free Trade Agreement, as well as interest rates in the U.S. and Canada.

10ENERPLUS 2018 FINANCIAL SUMMARY

Monthly USD/CDN Exchange Rate 

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 February 20, 2019,  we have hedged approximately 23,100 bbls/day of our expected crude oil production for 2019, which represents approximately 63% of our 2019 forecasted crude oil production, after royalties. For 2020, we have hedged 16,000 bbls/day, which represents approximately 43%  of our 2019 forecasted crude oil production, after royalties. Our crude oil hedges are predominantly three-way collars, which consist of a sold put, a purchased put and a sold call. When WTI prices settle below the sold put strike price, the three-way collars provide a limited amount of protection above the WTI settled price equal to the difference between the strike price of the purchased and sold puts. Overall, we expect our crude oil related hedging contracts to protect a significant portion of our cash flow from operating activities and adjusted funds flow.

As of February 20, 2019,  we have hedged approximately 65,700 Mcf/day of our forecasted natural gas production for 2019. This represents approximately 34% of our forecasted natural gas production, after royalties.    

The following is a summary of our financial contracts in place at February 20, 2019, expressed as a percentage of our forecasted 2019 net production volumes:

	WTI Crude Oil (US$/bbl)(1)(2)
	Jan 1, 2019 –	Apr 1, 2019 –	July 1, 2019 –	Oct 1, 2019 –	Jan 1, 2020 –
	Mar 31, 2019	Jun 30, 2019	Sep 30, 2019	Dec 31, 2019	Dec 31, 2020
Swaps
Sold Swaps	$ 53.73	-	-	-	-
%	8%	-	-	-	-
Three Way Collars
Sold Puts	$ 44.28	$ 44.50	$ 44.64	$ 44.64	$ 46.88
%	46%	63%	66%	66%	43%
Purchased Puts	$ 54.12	$ 54.59	$ 54.81	$ 54.81	$ 57.50
%	46%	63%	66%	66%	43%
Sold Calls	$ 64.12	$ 65.52	$ 65.95	$ 65.99	$ 72.50
%	46%	63%	66%	66%	43%

(1) Based on weighted average price (before premiums) assuming average annual production of 97,000 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$1.61/bbl from January 1, 2019 to December 31, 2020.

ENERPLUS 2018 FINANCIAL SUMMARY             11

	NYMEX Natural Gas (US$/Mcf)(1)
	Jan 1, 2019 –	Apr 1, 2019 –
	Mar 31, 2019	Oct 31, 2019
Swaps
Sold Swaps	$ 4.23	$ 2.85
%	26%	36%
Collars
Purchased Puts	$ 3.80	-
%	26%	-
Sold Calls	$ 6.01	-
%	26%	-

(1) Based on weighted average price (before premiums) assuming average annual production of 97,000 BOE/day, which is the mid-point of our annual 2019 guidance, less royalties and production taxes of 25%.

ACCOUNTING FOR PRICE RISK MANAGEMENT

Commodity Risk Management Gains/(Losses)
($ millions)	2018		2017		2016
Cash gains/(losses):
Crude oil	$	(52.0)	$	0.9	$	75.0
Natural gas		16.2		7.7		5.3
Total cash gains/(losses)	$	(35.8)	$	8.6	$	80.3
Non-cash gains/(losses):
Crude oil	$	114.8	$	(5.4)	$	(96.2)
Natural gas		9.2		11.1		(13.5)
Total non-cash gains/(losses)	$	124.0	$	5.7	$	(109.7)
Total gains/(losses)	$	88.2	$	14.3	$	(29.4)

(Per BOE)	2018		2017		2016
Total cash gains/(losses)	$	(1.05)	$	0.28	$	2.36
Total non-cash gains/(losses)		3.64		0.18		(3.22)
Total gains/(losses)	$	2.59	$	0.46	$	(0.86)

During 2018, we realized cash losses of $52.0 million on our crude oil contracts and gains of $16.2 million on our natural gas contracts. The realized cash losses were the result of crude oil prices rising above the swap level and the sold call strike price on our three-way collars. Cash gains on our natural gas contracts included a gain of $15.1 million on the unwind of a portion of our AECO-NYMEX basis physical contracts. In 2017, we realized cash gains of $0.9 million on our crude oil contracts and $7.7 million on our natural gas contracts, which included a gain of $8.5 million on the unwind of a portion of our AECO-NYMEX basis physical contracts. During 2016, we realized cash gains of $75.0 million on our crude oil contracts and $5.3 million on our natural gas contracts. The cash gains in 2017 and 2016 were due to contracts which provided floor protection above market prices.

As the forward markets for crude oil and natural gas fluctuate, as new contracts are executed, and as existing contracts are realized, changes in fair value are reflected as either a non‑cash charge or gain to earnings. The fair value of our crude oil contracts and natural gas contracts at December 31, 2018 were in a net asset position of $80.5 million and $10.9 million, respectively (December 31, 2017 – net liability position of $34.3 million and net asset position of $1.7 million, respectively). The change in fair value of our crude oil and natural gas contracts represented gains of $114.8 million and $9.2 million, respectively, during 2018 and losses of $5.4 million and gains of $11.1 million, respectively, during 2017.

Revenues

($ millions)	2018		2017		2016
Oil and natural gas sales	$	1,610.9	$	1,141.8	$	882.1
Royalties		(318.2)		(221.1)		(159.4)
Oil and natural gas sales, net of royalties	$	1,292.7	$	920.7	$	722.7

Oil and natural gas sales revenue for 2018 totaled $1,610.9 million, an increase of 41% from $1,141.8 million in 2017.  The increase in revenue was a result of higher liquids production and an improvement in crude oil prices.

In 2017, oil and natural gas sales revenue increased 29% to $1,141.8 million from $882.1 million in 2016. The increase in 2017 is a result of the improvement in commodity prices and realized sales price differentials, along with a higher crude oil and natural gas liquids weighting of 48% compared to 46% in 2016.

12ENERPLUS 2018 FINANCIAL SUMMARY

Royalties and Production Taxes

($ millions, except per BOE amounts)	2018		2017		2016
Royalties	$	318.2	$	221.1	$	159.4
Per BOE	$	9.35	$	7.15	$	4.67
Production taxes	$	87.3	$	54.3	$	37.4
Per BOE	$	2.57	$	1.76	$	1.10
Royalties and production taxes	$	405.5	$	275.4	$	196.8
Per BOE	$	11.92	$	8.91	$	5.77
Royalties and production taxes (% of oil and natural gas sales)		25%		24%		22%

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.

Royalties and production taxes were in line with our guidance for 2018, averaging 25% of oil and natural gas sales, before transportation. Royalties and production taxes increased to $405.5 million in 2018 from $275.4 million in 2017 and $196.8 million in 2016, mainly due to a larger portion of production volumes coming from our U.S. properties, as well as higher crude oil and natural gas realized prices.

2019 Guidance

We expect royalty and production taxes in 2019 to average 25% of our oil and gas sales before transportation, which is consistent with 2018 levels.

Operating Expenses

($ millions, except per BOE amounts)	2018		2017		2016
Cash operating expenses	$	238.3	$	197.7	$	249.0
Non-cash (gains)/losses(1)		-		(0.6)		(1.1)
Total operating expenses	$	238.3	$	197.1	$	247.9
Per BOE	$	7.00	$	6.37	$	7.27

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

Operating expenses for 2018 were $238.3 million or $7.00/BOE, consistent with our revised guidance of $7.00/BOE and representing an increase of $41.2 million ($0.63/BOE) from the prior year. The increase is mainly attributable to our higher liquids production as our liquids weighting increased to 54% from 48% in the prior year. Our liquids production has higher associated operating cost metrics, which was partially offset by the divestment of higher operating cost Canadian properties during 2017.  

Operating expenses during 2017 were $197.1 million or $6.37/BOE compared to $247.9 million or $7.27/BOE in 2016. The improvement was mainly the result of cost savings initiatives combined with the divestment of higher operating cost Canadian properties. 

2019 Guidance

We expect operating expenses of $8.00/BOE in 2019. The increase from 2018 is primarily a result of our liquids growth contributing to a higher proportion of our total production, as well as an increase in gas processing costs and use of electrical submersible pumps in North Dakota.

Transportation Costs

($ millions, except per BOE amounts)	2018		2017		2016
Transportation costs	$	123.5	$	111.3	$	107.1
Per BOE	$	3.63	$	3.60	$	3.14

ENERPLUS 2018 FINANCIAL SUMMARY             13

Transportation costs in 2018 were in line with our guidance of $3.60/BOE averaging $3.63/BOE, and similar to $3.60/BOE in 2017. Transportation costs increased to $3.60/BOE in 2017, compared to $3.14/BOE in 2016 due to additional transportation commitments in the Marcellus that commenced in August 2016 and our  growing U.S. production volumes which have higher associated transportation costs. 

2019 Guidance

We expect transportation costs to increase to $4.00/BOE in 2019, due to additional crude oil firm transportation commitments that provide access to sell a portion of our production at U.S. gulf coast or Brent pricing. 

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.

	Year ended December 31, 2018
Netbacks by Property Type		Crude Oil		Natural Gas		Total
Average Daily Production			53,294 BOE/day		239,532 Mcfe/day		93,216 BOE/day
Netback(1) $ per BOE or Mcfe			(per BOE)		(per Mcfe)		(per BOE)
Oil and natural gas sales		$	67.43	$	3.42	$	47.35
Royalties and production taxes			(17.90)		(0.65)		(11.92)
Cash operating expenses			(10.54)		(0.38)		(7.00)
Transportation costs			(2.40)		(0.88)		(3.63)
Netback before hedging		$	36.59	$	1.51	$	24.80
Cash gains/(losses)			(2.67)		0.19		(1.05)
Netback after hedging		$	33.92	$	1.70	$	23.75
Netback before hedging ($ millions)		$	711.7	$	131.9	$	843.6
Netback after hedging ($ millions)		$	659.7	$	148.1	$	807.8

	Year ended December 31, 2017
Netbacks by Property Type		Crude Oil		Natural Gas		Total
Average Daily Production			44,496 BOE/day		241,290 Mcfe/day		84,711 BOE/day
Netback(1) $ per BOE or Mcfe			(per BOE)		(per Mcfe)		(per BOE)
Oil and natural gas sales		$	53.38	$	3.12	$	36.93
Royalties and production taxes			(13.89)		(0.57)		(8.91)
Cash operating expenses			(10.20)		(0.36)		(6.39)
Transportation costs			(2.21)		(0.86)		(3.60)
Netback before hedging		$	27.08	$	1.33	$	18.03
Cash gains/(losses)			0.06		0.09		0.28
Netback after hedging		$	27.14	$	1.42	$	18.31
Netback before hedging ($ millions)		$	439.8	$	117.6	$	557.4
Netback after hedging ($ millions)		$	440.7	$	125.2	$	566.0

	Year ended December 31, 2016
Netbacks by Property Type		Crude Oil		Natural Gas		Total
Average Daily Production			47,206 BOE/day		275,538 Mcfe/day		93,125 BOE/day
Netback(1) $ per BOE or Mcfe			(per BOE)		(per Mcfe)		(per BOE)
Oil and natural gas sales		$	37.86	$	2.26	$	25.88
Royalties and production taxes			(9.38)		(0.34)		(5.77)
Cash operating expenses			(10.29)		(0.72)		(7.31)
Transportation costs			(1.97)		(0.72)		(3.14)
Netback before hedging		$	16.22	$	0.48	$	9.66
Cash gains/(losses)			4.34		0.05		2.36
Netback after hedging		$	20.56	$	0.53	$	12.02
Netback before hedging ($ millions)		$	280.4	$	48.8	$	329.2
Netback after hedging ($ millions)		$	355.3	$	54.2	$	409.5

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

14ENERPLUS 2018 FINANCIAL SUMMARY

Crude oil and natural gas netbacks per BOE before hedging were higher during 2018 compared to 2017 and 2016 primarily due to higher realized crude oil prices. During 2018, our crude oil properties accounted for 84% and 82% of our netback before and after hedging, respectively. During 2017, our crude oil properties accounted for 79% and 78% of our netback before and after hedging, respectively.

General and Administrative Expenses

Total G&A expenses include cash G&A expenses and share‑based compensation (“SBC”) charges related to our long‑term incentive plans (“LTI plans”). See Note 10, Note 13 and Note 14 to the Financial Statements for further details.

($ millions)	2018		2017		2016
Cash:
G&A expense	$	50.0	$	50.5	$	59.8
Share-based compensation expense		0.1		1.0		3.1
Non-Cash:
Share-based compensation expense		25.9		22.6		27.0
Equity swap loss/(gain)		(0.2)		0.2		(3.6)
Total G&A expenses	$	75.8	$	74.3	$	86.3

(Per BOE)	2018		2017		2016
Cash:
G&A expense	$	1.47	$	1.63	$	1.75
Share-based compensation expense		0.01		0.03		0.09
Non-Cash:
Share-based compensation expense		0.76		0.73		0.80
Equity swap loss/(gain)		(0.01)		0.01		(0.11)
Total G&A expenses	$	2.23	$	2.40	$	2.53

Cash G&A expenses in 2018 totaled $50.0 million ($1.47/BOE), beating our guidance of $1.50/BOE and consistent with $50.5 million ($1.63/BOE) in 2017. 

During the year, we reported cash SBC on our Deferred Share Unit (“DSU”) plan of $0.1 million, compared to $1.0 million in 2017 due to  a decrease in our share price at December 31, 2018 on outstanding deferred share units. We recorded non‑cash SBC of $25.9 million ($0.76/BOE) in 2018 compared to $22.6 million ($0.73/BOE) in 2017. The increase in non-cash SBC in 2018 was a result of a recovery recorded in 2017 due to the forfeiture of units that were previously expensed.  

Cash G&A expenses in 2017 were $50.5 million ($1.63/BOE), a decrease of 16% from $59.8 million ($1.75/BOE) in 2016. Cash SBC expense was $1.0 million ($0.03/BOE) in 2017 compared to an expense of $3.1 million ($0.09/BOE) in 2016. We recorded non‑cash SBC of $22.6 million ($0.73/BOE) in 2017 compared to $27.0 million ($0.80/BOE) in 2016. The decrease in non-cash SBC was a result of the increased forfeiture of units in 2017.

We have hedged a portion of the outstanding cash‑settled units under our LTI plans. We recorded a non‑cash mark‑to‑market gain of $0.2 million on these hedges in 2018 (2017 – $0.2 million loss; 2016 – $3.6 million gain), which included the settlement of a portion of our equity swaps. As of December 31, 2018, we have 195,000 units hedged at a weighted average price of $20.60 per share.

2019 Guidance

We expectour cash G&A expense to be $1.50/BOE in 2019, which is consistent with 2018. 

Interest Expense

Interest on our senior notes and bank credit facility in 2018 totaled $36.8 million compared to $38.7 million in 2017 and $45.4 million in 2016. Interest expense decreased 5% in 2018 when compared to 2017 primarily due to the repayment of a portion of our 2009 senior notes which carry a higher coupon rate.  

Interest expense decreased 15% in 2017 when compared to 2016 due to our undrawn bank credit facility, the impact of the strengthening Canadian dollar on our U.S. denominated interest payments and the payment of the first of five annual principal instalments on our 2009 senior notes.

ENERPLUS 2018 FINANCIAL SUMMARY             15

At December 31, 2018, we were undrawn on our $800 million bank credit facility and our debt consisted of fixed interest rate senior notes with a weighted average interest rate of 4.8%. See Note 7 to the Financial Statements for further details on our outstanding notes.

Foreign Exchange

($ millions)	2018		2017		2016
Realized:
Foreign exchange loss/(gain) on settlements	$	0.5	$	1.5	$	0.1
Translation of U.S. dollar cash held in Canada loss/(gain)		(19.6)		11.0		—
Unrealized loss/(gain)		58.6		(42.6)		(40.6)
Total foreign exchange loss/(gain)	$	39.5	$	(30.1)	$	(40.5)
US/CDN average exchange rate		1.30		1.30		1.32
US/CDN period end exchange rate		1.36		1.26		1.34

We recorded a net foreign exchange loss of $39.5 million in 2018 compared to gains of $30.1 million and $40.5 million in 2017 and 2016, respectively. 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.

In 2018, we recorded a realized foreign exchange gain of $19.1 million, due to the weakening Canadian dollar compared to a loss of $12.5 million and $0.1 million in 2017 and 2016, respectively.

Comparing December 31, 2018 to December 31, 2017, the Canadian dollar weakened relative to the U.S. dollar, resulting in an unrealized loss of $58.6 million. See Note 11 to the Financial Statements for further details. 

Capital Investment

($ millions)	2018		2017		2016
Capital spending	$	593.9	$	458.0	$	209.1
Office capital		6.5		2.7		1.5
Sub-total		600.4		460.7		210.6
Property and land acquisitions	$	25.8	$	13.3	$	126.1
Property divestments		(6.9)		(56.2)		(670.4)
Sub-total		18.9		(42.9)		(544.3)
Total(1)	$	619.3	$	417.8	$	(333.7)

(1) Excludes changes in non-cash investing working capital. See Note 17(b) of the Consolidated Financial Statements for additional information.

2018

Capital spending in 2018 totaled $593.9 million, in line with our guidance of $585 million. Our capital spending in 2018 was 30% higher than 2017, as we continued to execute on our growth plans. In 2018, we spent $474.4 million on our U.S. crude oil properties, $46.3 million on our Canadian crude oil properties, and $66.2 million on our Marcellus natural gas assets. Through our capital program in 2018, we added 65.7 MMBOE of gross proved plus probable reserves, replacing 194% of our 2018 production, before accounting for acquisitions and divestments.

Property and land acquisitions in 2018 totaled $25.8 million and included land acquisitions in Colorado and a property swap in North Dakota. We recorded net divestments of $6.9 million in 2018, primarily related to a property swap in North Dakota.

2017

Capital spending in 2017 totaled $458.0 million and was more than twice our spending levels in 2016, as we repositioned ourselves for growth. In 2017 we spent $343.0 million on our U.S. crude oil properties, $55.3 million on our Canadian crude oil properties, and $58.5 million on our Marcellus natural gas assets. In 2017, we added 58.0 MMBOE of gross proved plus probable reserves, replacing 189% of our 2017 production, before accounting for acquisitions and divestments.

We recorded net divestment proceeds of $56.2 million in 2017 consisting mainly of our second quarter sale of our Brooks waterflood property and Canadian shallow gas assets. Total divestments had combined production of 7,700 BOE/day and resulted in a $72.3 million reduction to future asset retirement obligations. Property and land acquisitions in 2017 totaled $13.3 million and included additional leases and minor undeveloped land.

16ENERPLUS 2018 FINANCIAL SUMMARY

2016

Capital spending in 2016 totaled $209.1 million and was focused on our core areas with spending of $136.4 million on our North Dakota crude oil properties, $44.4 million on our Canadian crude oil waterflood properties and $24.3 million on our Marcellus natural gas assets.

We recorded net divestment proceeds of $670.4 million in 2016. In Canada, we sold properties consisting mainly of natural gas assets, which included certain Deep Basin natural gas properties and non-core properties in northwest Alberta with combined production of approximately 8,500 BOE/day. On December 30, 2016, we closed the sale of our non-operated assets in North Dakota with production of approximately 5,000 BOE/day for proceeds of $392.0 million. Through our capital program in 2016 we added 43 MMBOE of gross proved plus probable reserves, replacing 126% of our 2016 production, before accounting for acquisitions and divestments.

Property and land acquisitions in 2016 totaled $126.1 million, largely due to our acquisition of a Canadian waterflood property for a purchase price of $110.3 million, net of closing adjustments.

2019 Guidance

Our capital spending guidance for 2019 is between $565 million and $635 million, and is expected to deliver annual liquids production growth of 9%. Our spending is focused on our core areas, with approximately $480 million allocated to North Dakota, $45 million to our Marcellus gas properties, $45 million to our Canadian crude oil waterflood properties, and $30 million allocated to the DJ Basin. 

Gain on Asset Sales and Note Repurchases

Under full cost accounting rules, divestments of oil and natural gas properties are generally accounted for as adjustments to the full cost pool with no recognition of a gain or loss. However, if not recognizing a gain or loss on the transaction would significantly alter the relationship between a cost centre’s capitalized costs and proved reserves, then a gain or loss must be recognized.  No gains or losses were recorded on asset sales in 2018. We recorded gains of $78.4 million during 2017 related to the divestment of our Brooks waterflood property and Canadian shallow gas assets. In 2016, a gain of $559.2 million was recorded on asset divestments, which included a gain of $339.4 million on the fourth quarter sale of our non-operated North Dakota property. Gains and losses are evaluated on a case by case basis for each asset sale, and future sales may or may not result in such treatment.

During 2018 and 2017 we did not repurchase any of our senior notes. During the first half of 2016, we recorded a total gain of $19.3 million on the repurchase of US$267 million of outstanding senior notes at prices between 90% of par and par value. 

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

($ millions, except per BOE amounts)	2018		2017		2016
DD&A expense	$	304.3	$	250.8	$	329.0
Per BOE	$	8.94	$	8.11	$	9.65

DD&A of property, plant and equipment (“PP&E”) is recognized using the unit‑of‑production method based on proved reserves. Total DD&A in 2018 increased from 2017 mainly due to a 10% percent increase in overall production. On a per BOE basis, DD&A for 2018 increased as  a result of higher capital spending and additional future development capital associated with undeveloped reserve additions. In 2017, DD&A decreased from the prior year mostly due to asset impairments recorded during 2016 under the U.S. GAAP full cost ceiling test methodology.

Impairments

PP&E

($ millions)	2018		2017		2016
Canada cost centre	$	—	$	—	$	89.4
U.S. cost centre		—		—		211.8
Total Impairments	$	—	$	—	$	301.2

Under U.S. GAAP, the full cost ceiling test is performed on a country‑by‑country cost centre basis using estimated after‑tax future net cash flows discounted at 10% from proved reserves (“Standardized Measure”), using constant prices as defined by the U.S. Securities and Exchange Commission (“SEC”). SEC constant prices are calculated as the unweighted average of the trailing twelve first‑day‑of‑the‑month commodity prices. Standardized Measure is not related to our capital spending investment criteria and is not a fair value-based measurement, but rather a prescribed accounting calculation. Under U.S. GAAP impairments are not reversed in future periods.

ENERPLUS 2018 FINANCIAL SUMMARY             17

The trailing twelve-month average crude oil and natural gas prices generally improved throughout 2018 and 2017 and no impairments were recorded. In comparison, trailing twelve-month average commodity prices weakened significantly in 2016, resulting in non‑cash impairments totaling $301.2 million (before taxes).

The following table outlines the twelve-month average trailing benchmark prices and exchange rates used in our ceiling test at December 31, 2018, 2017 and 2016:

	WTI Crude Oil		Exchange Rate	Edm Light Crude		U.S. Henry Hub		AECO Natural Gas
Year	US$/bbl		US/CDN	CDN$/bbl		Gas US$/Mcf		Spot CDN$/Mcf
2018	$	65.56	1.28	$	69.58	$	3.10	$	1.67
2017	$	51.34	1.30	$	63.57	$	2.98	$	2.32
2016	$	42.75	1.32	$	52.26	$	2.49	$	2.17

Many factors influence the allowed ceiling value versus our net capitalized cost base, making it difficult to predict with reasonable certainty the value of impairment losses from future ceiling tests. For the next year, the primary factors include future first‑day‑of‑the‑month commodity prices, reserves revisions, our capital expenditure levels and timing, acquisition and divestment activity, as well as production levels, which affect DD&A expense.  There is the potential for trailing twelve-month average commodity prices to decline, impacting the ceiling value which could result in non-cash impairments.

Goodwill

Goodwill is tested for impairment annually or more frequently if events or changes in circumstances indicate that goodwill may be impaired. We first perform a qualitative assessment of goodwill by evaluating potential indicators of impairment, and if it is more likely than not that the fair value of the reporting unit is less than its carrying value we perform a quantitative impairment test. If the carrying value of the reporting unit exceeds its fair value, goodwill is written down to its implied fair value with an offsetting charge to earnings in the Consolidated Statements of Income/(Loss) in the Financial Statements.

Our annual goodwill impairment assessments at December 31, 2018,  2017, and 2016 resulted in no impairment.  

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 to be $126.1 million at December 31, 2018, compared to $117.7 million at December 31, 2017. The increase was largely due to an increase in expected remediation and reclamation estimates and a decrease in our weighted average credit-adjusted risk-free rate used to determine the net present value of the liability. See Note 8 to the Financial Statements for further information.

We take an active approach to managing our abandonment, reclamation and remediation obligations. During 2018, we spent $11.3 million (2017 – $12.9 million) on our asset retirement obligations and we expect to spend approximately $12.0 million in 2019. The majority of our abandonment, reclamation and remediation costs are expected to be incurred between 2025 and 2055. We do not reserve cash or assets for the purpose of funding our future asset retirement obligations. Any abandonment, reclamation and remediation costs are anticipated to be funded out of cash flow and available credit facilities.

Income Taxes

($ millions)	2018		2017		2016
Current tax expense/(recovery)	$	(27.1)	$	(48.0)	$	(2.4)
Deferred tax expense/(recovery)		130.3		129.9		(234.8)
Total tax expense/(recovery)	$	103.2	$	81.9	$	(237.2)

Our current tax recovery in 2018 was $27.1 million compared to $48.0 in 2017. The recoveries primarily related to the reclassification of AMT refunds from our deferred income tax asset in the amounts of $27.2 million and $50.1 million, respectively. The remaining $27.2 million in AMT refunds are expected to be reclassified to current tax in 2019 and 2020. 

18ENERPLUS 2018 FINANCIAL SUMMARY

The total tax expense in 2018 was $103.2 million compared to $81.9 in 2017 primarily due to higher overall income in 2018. The deferred tax expense in 2017 included $46.2 million from the remeasurement of our U.S. deferred income tax assets for the federal income tax rate reduction from 35% to 21% after enactment of the U.S. Tax Cuts and Jobs Act, offset by the reversal of the valuation allowance previously recorded on our AMT refund. We assess the recoverability of our deferred income tax assets each period to determine whether it is, more likely than not, all or a portion of our deferred income tax assets will be realized. We consider available positive and negative evidence including future taxable income and reversing existing temporary differences in making this assessment. Our overall deferred income tax asset, net of valuation allowance, was $465.1 million as at December 31, 2018 (2017 - $569.9 million). Our remaining valuation allowance is primarily related to our net capital loss carryforward balance. We do not anticipate future capital gains that will allow us to utilize these losses.

Our estimated tax pools at December 31, 2018 are as follows:

Pool Type ($ millions)	2018
Canada
Canadian oil and gas property (“COGPE”)	$	6
Canadian development expenditures (“CDE”)		91
Canadian exploration expenditures (“CEE”)		238
Undepreciated capital costs (“UCC”)		149
Non-capital losses and other credits		428
	$	912
U.S.
Alternative minimum tax credit (“AMT”)	$	58
Net operating losses		1,052
Depletable and depreciable assets		870
	$	1,980
Total tax pools and credits	$	2,892
Capital losses	$	1,226

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, 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. Our senior debt to adjusted EBITDA ratio decreased to 0.9x at December 31, 2018 from 1.2x at December 31, 2017 as a result of an increase in our trailing twelve-month EBITDA, which benefited from increased revenue in 2018. Our net debt to adjusted funds flow ratio improved to 0.4x at December 31, 2018 from 0.6x at December 31, 2017 as a result of the significant increase in our adjusted funds flow in 2018. 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 December 31, 2018 increased slightly to $333.5 million compared to $325.8 million at December 31, 2017. Total debt was comprised of $696.8 million in senior notes less $363.3 million in cash. The increase compared to the prior year was a result of the impact of a weaker Canadian dollar at December 31, 2018 on our U.S. dollar denominated senior notes, which more than offset a $16.8 million increase in cash. Our next scheduled senior note repayments of $30 million and US$22 million are due in May and June 2019, respectively, with remaining maturities extending to 2026. At December 31, 2018, we were undrawn on our $800 million bank facility.

Our adjusted payout ratio, which is calculated as cash dividends plus capital and office expenditures divided by adjusted funds flow, was 84% for 2018 compared to 93% in 2017. After adjusting for net acquisition and divestment proceeds, our funding surplus for the year ended December 31, 2018 was $104.9 million compared to $77.2 million in 2017. A portion of the funding surplus in 2018 was used to return approximately $79.0 million of capital to shareholders through repurchasing 5,925,084 common shares under the NCIB at an average price of $13.33 per share.  The Company also paid $29.3 million in dividends in 2018. We expect to continue to pay monthly dividends to our shareholders of $0.01 per share, however, if economic conditions change we may make adjustments.

Our working capital deficiency, excluding cash and cash equivalents and current derivative assets and liabilities, increased to $143.1 million at December 31, 2018 from $107.6 million at December 31, 2017. We expect to finance our working capital deficit and our ongoing working capital requirements through cash, adjusted funds flow and our bank credit facility. In addition, we have sufficient liquidity to meet our financial commitments for the near term, as disclosed under “Commitments” below.

ENERPLUS 2018 FINANCIAL SUMMARY             19

During the fourth quarter, we completed a one-year extension of our $800 million senior, unsecured, covenant‑based bank credit facility, which now matures on October 31, 2021. There were no significant amendments to the agreement terms or debt covenants. Drawn fees on our bank credit facility range between 125 and 315 basis points over Banker’s Acceptance rates, with current drawn fees of 125 basis points over Banker’s Acceptance rates based on our current reported senior net debt to adjusted EBITDA ratio. The bank credit facility ranks equally with our senior unsecured covenant‑based notes.

At December 31, 2018 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 as material documents on our SEDAR profile at www.sedar.com.   

The following table lists our financial covenants at December 31, 2018:

Covenant Description		December 31, 2018
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%	21%
	Minimum Ratio
Adjusted EBITDA to interest (1)	4.0x	21.3x

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, 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 December 31, 2018 were $209.7 million and $782.8 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%.

Counterparty Credit

OIL AND NATURAL GAS SALES COUNTERPARTIES

Our oil and natural gas receivables are with customers in the oil and gas industry and are subject to normal credit risks. Concentration of credit risk is mitigated by marketing production to numerous purchasers under normal industry sale and payment terms. A credit review process is in place to assess and monitor our counterparties’ creditworthiness on a regular basis. This process involves reviewing and ratifying our corporate credit guidelines, assessing the credit ratings of our counterparties and setting exposure limits. When warranted, we obtain financial assurances such as letters of credit, parental guarantees or third-party insurance to mitigate a portion of our credit risk. This process is utilized for both our oil and natural gas sales counterparties as well as our financial derivative counterparties.

FINANCIAL DERIVATIVE COUNTERPARTIES

We are exposed to credit risk in the event of non‑performance by our financial counterparties regarding our derivative contracts. We mitigate this risk by entering into transactions with major financial institutions, the majority of which are members of our bank syndicate. We have International Swaps and Derivatives Association (“ISDA”) agreements in place with the majority of our financial counterparties. These agreements provide some credit protection by generally allowing parties to aggregate amounts owing to each other under all outstanding transactions and settle with a single net amount in the case of a credit event. To date we have not experienced any losses due to non‑performance by our derivative counterparties. All of our derivative counterparties are considered investment grade. At December 31, 2018, we had $91.5 million in mark-to-market assets offset by $1.9 million of mark‑to‑market liabilities resulting in a net asset position of $89.6 million.  

20ENERPLUS 2018 FINANCIAL SUMMARY

Dividends

($ millions, except per share amounts)	2018		2017		2016
Cash dividends  (1)	$	29.3	$	29.0	$	35.4
Per weighted average share (Basic)	$	0.12	$	0.12	$	0.16

(1) Excludes changes in non-cash financing working capital. See Note 17(b) of the Consolidated Financial Statements for additional information.

We reported total dividends of $29.3 million or $0.12 per share to our shareholders in 2018. During 2017 and 2016, we reported total dividends of $29.0 million or $0.12 per share and $35.4 million or $0.16 per share, respectively.

Effective for our April 2016 dividend, we reduced our monthly dividend to $0.01 per share from $0.03 per share.

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

	2018		2017		2016
Share capital ($ millions)	$	3,337.6	$	3,386.9	$	3,366.0
Common shares outstanding (thousands)		239,411		242,129		240,483
Weighted average shares outstanding – basic (thousands)		244,076		241,929		226,530
Weighted average shares outstanding – diluted (thousands)		247,261		247,874		231,293

During 2018, a total of 668,000 shares were issued pursuant to our stock option plan resulting in additional share capital of $9.1 million, and $0.7 million transferred from paid-in capital to share capital (2017 and 2016 – nil). During 2018, a total of 2,539,000 shares were issued pursuant to our treasury‑settled LTI plans and $23.4 million was transferred from paid-in capital to share capital (2017 – 1,646,000 and $21.0 million; 2016 – 594,000 and $9.4 million).

On March 21, 2018, Enerplus announced the acceptance of its NCIB by the Toronto Stock Exchange (“TSX”). The bid allows Enerplus to purchase up to 17,095,598 common shares on the TSX, the New York Stock Exchange and/or alternative Canadian trading systems over a period of twelve months commencing on March 26, 2018. All common shares purchased under the bid will be cancelled. During the year ended December 31, 2018, the Company repurchased 5,925,084 common shares under the NCIB at an average price of $13.33 per share, for total consideration of $79.0 million. Of the amount paid, $82.6 million was recorded to share capital and $3.6 million was credited to accumulated deficit. Subsequent to the year, and up to February 20, 2019, the Company repurchased 586,953 common shares under the NCIB at an average price of $11.40 per share, for consideration of $6.7 million.  The Company also received approval from the Board of Directors to renew the NCIB upon expiry of the existing term on March 25, 2019, subject to approval by the TSX.  The proposed renewal will be for 7% of public float (within the meaning under the TSX rules) consistent with the current bid.

On May 31, 2016, 33,350,000 common shares were issued at a price of $6.90 per share for gross proceeds of $230.1 million ($220.4 million, net of issue costs before tax).

At February 20, 2019, we had 238,824,149 shares outstanding. In addition, an aggregate of 8,599,059 common shares may be issued to settle outstanding grants under the PSU, RSU, and stock option plans, assuming the maximum payout multiplier of 2.0 times for the PSUs.

For further details see Note 13 to the Financial Statements.

ENERPLUS 2018 FINANCIAL SUMMARY             21

Commitments

We have the following minimum annual commitments:

													Total
			Minimum Annual Commitment Each Year										Committed
($ millions)	Total		2019		2020		2021		2022		2023		after 2023
Senior notes(1)	$	696.8	$	60.0	$	111.3	$	111.3	$	109.9	$	108.6	$	195.7
Transportation commitments(2)		367.6		36.8		37.9		34.1		31.4		30.3		197.1
Processing commitments		16.2		3.5		3.2		1.5		1.5		1.5		5.0
Drilling and completions		51.4		20.0		20.0		11.4		—		—		—
Office lease commitments		73.7		9.4		10.7		11.2		11.3		11.4		19.7
Sublease recoveries		(15.4)		(3.2)		(3.4)		(3.2)		(2.4)		(1.7)		(1.5)
Net office lease commitments		58.3		6.2		7.3		8.0		8.9		9.7		18.2
Total commitments(3)(4)	$	1,190.3	$	126.5	$	179.7	$	166.3	$	151.7	$	150.1	$	416.0

(1) Interest payments have not been included.

(2) Includes additional firm transportation commitments executed subsequent to year-end.

(3) Crown and surface royalties, production taxes, lease rentals and mineral taxes (hydrocarbon production rights) have not been included as amounts paid depend on future ownership, production, prices and the legislative environment.

(4) US$ commitments have been converted to CDN$ using the December 31, 2018 foreign exchange rate of 1.3637.

In the Marcellus, we have firm transportation agreements in place for approximately 66,000 Mcf/day, which expire between 2020 and 2036. This includes an agreement for firm pipeline capacity on the Tennessee Gas Pipeline from our Marcellus producing region to downstream connections for 30,000 Mcf/day of natural gas until mid-2027, reducing to 15,000 Mcf/day for an additional 9 years, with a total estimated transportation commitment of US$90.4 million through 2036. We have also entered into a binding contract for five years of firm transportation capacity for 30,000 Mcf/day on the PennEast pipeline project. This project has been approved by the Federal Energy Regulatory Commission, however, it is currently awaiting state level approvals with an expected in-service date during 2020. In the Bakken region, subsequent to year end, we entered into a multi-year contract for firm pipeline capacity to transport a portion of our crude oil production to the U.S. Gulf Coast. 

In Canada, we have various firm transportation agreements for approximately 3,200 BOE/day of our crude oil and natural gas liquids production in 2019, decreasing to approximately 1,400 BOE/day on average from 2020 to 2027. We also have firm natural gas transportation contracts in 2019 for approximately 48,000 Mcf/day. At December 31, 2018, we have firm natural gas liquids fractionation contracts for 1,100 BOE/day through 2027.

Our commitments and contingencies are more fully described in Note 15 to the Financial Statements.

22ENERPLUS 2018 FINANCIAL SUMMARY

SELECTED ANNUAL CANADIAN AND U.S. FINANCIAL RESULTS

	Year ended							Year ended
	December 31, 2018							December 31, 2017
(millions, except per unit amounts)		Canada		U.S.		Total		Canada		U.S.		Total
Average Daily Production Volumes(1)
Crude oil (bbls/day)			9,282		36,142		45,424		10,779		26,156		36,935
Natural gas liquids (bbls/day)			1,064		3,422		4,486		1,193		2,665		3,858
Natural gas (Mcf/day)			27,497		232,340		259,837		46,228		217,278		263,506
Total average daily production (BOE/day)			14,929		78,287		93,216		19,677		65,034		84,711
Pricing(2)
Crude oil (per bbl)		$	55.50	$	79.49	$	74.59	$	51.87	$	61.50	$	58.69
Natural gas liquids (per bbl)			45.22		23.05		28.31		38.13		26.38		30.01
Natural gas (per Mcf)			2.90		3.49		3.42		3.30		3.19		3.21
Capital Expenditures
Capital spending		$	53.3	$	540.6	$	593.9	$	56.5	$	401.5	$	458.0
Acquisitions			4.2		21.6		25.8		4.7		8.6		13.3
Divestments			1.2		(8.1)		(6.9)		(56.6)		0.4		(56.2)
Netback(3) Before Hedging
Oil and natural gas sales		$	237.9	$	1,373.0	$	1,610.9	$	276.3	$	865.5	$	1,141.8
Royalties			(39.6)		(278.6)		(318.2)		(49.3)		(171.8)		(221.1)
Production taxes			(3.1)		(84.2)		(87.3)		(3.3)		(51.0)		(54.3)
Cash operating expenses			(75.2)		(163.1)		(238.3)		(82.1)		(115.6)		(197.7)
Transportation costs			(11.4)		(112.1)		(123.5)		(13.3)		(98.0)		(111.3)
Netback before hedging		$	108.6	$	735.0	$	843.6	$	128.3	$	429.1	$	557.4
Other Expenses
Commodity derivative instruments loss/(gain)		$	(88.2)	$	—	$	(88.2)	$	(14.3)	$	—	$	(14.3)
General and administrative expense(4)			43.3		32.5		75.8		48.9		25.4		74.3
Current income tax expense/(recovery)			(0.4)		(26.7)		(27.1)		(0.4)		(47.6)		(48.0)

(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.

THREE YEAR SUMMARY OF KEY MEASURES

($ millions, except per share amounts)	2018		2017		2016
Oil and natural gas sales, net of royalties	$	1,292.7	$	920.7	$	722.7
Net income/(loss)		378.3		237.0		397.4
Per share (Basic)		1.55		0.98		1.75
Per share (Diluted)		1.53		0.96		1.72
Adjusted net income(1)		344.8		132.2		240.2
Cash flow from operating activities		738.8		476.1		312.3
Adjusted funds flow(1)		753.5		524.1		305.6
Cash dividends(2)		29.3		29.0		35.4
Per share (Basic)(2)		0.12		0.12		0.16
Total assets		3,118.3		2,645.8		2,638.9
Total debt		696.8		672.4		768.8
Total debt net of cash(1)		333.5		325.8		375.5

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

(2) Calculated based on dividends paid or payable.

ENERPLUS 2018 FINANCIAL SUMMARY             23

2018 versus 2017

Net oil and natural gas sales were $1,292.7 million in 2018 compared to $920.7 million in 2017 due to higher realized commodity prices, increased production and higher crude oil and natural gas liquids weighting in 2018.

We reported net income of $378.3 million in 2018 compared to $237.0 million in 2017. The increase in 2018 was primarily due to increased oil and natural gas sales and higher gains on commodity derivative instruments, which were offset in part by no gains on asset divestments and increased foreign exchange losses compared to 2017.

Cash flow from operating activities and adjusted funds flow increased to $738.8 million and $753.5 million, respectively, in 2018 from $476.1 million and $524.1 million in 2017. The increase was mainly due to a $372.0 million increase in net oil and gas natural gas sales, offset by realized losses on derivative instruments and higher operating expenses and production taxes resulting from higher production.

2017 versus 2016

Net oil and natural gas sales were $920.7 million in 2017 compared to $722.7 million in 2016 due to higher realized commodity prices, offset by the impact of lower production volumes as a result of our asset divestments over that period.

We reported net income of $237.0 million in 2017 compared to $397.4 million in 2016. The decrease in 2017 was primarily due to a $480.8 million decrease in gains being recorded on the divestment of assets during the period and a gain recorded in 2016 for $19.3 million related to the prepayment of senior notes. We also recorded a deferred tax expense of $129.9 million in 2017 compared to a deferred tax recovery of $234.8 million in 2016, due to higher net income before taxes and the impact of the U.S. Tax Legislation on our U.S. deferred income tax assets.

Cash flow from operating activities and adjusted funds flow increased to $476.1 million and $524.1 million, respectively, in 2017 from $312.3 million and $305.6 million in 2016. The increase was mainly due to a $198.0 million increase in net oil and gas natural gas sales, lower operating costs, interest, and cash G&A expenses, offset by lower realized cash gains on commodity hedges. Adjusted funds flow in 2017 benefited from a $50.1 million AMT refund realized in 2018.

QUARTERLY FINANCIAL INFORMATION

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

Oil and natural gas sales, net of royalties, increased in 2018 compared to 2017 due to an increase in realized commodity prices and higher production volumes.  Although production levels increased throughout 2018, declining commodity prices during the fourth quarter of 2018 resulted in lower net sales for this period.  

Net income increased to $378.3 million in 2018 due to higher net sales and non-cash gains on commodity derivatives as commodity prices fell during the fourth quarter.

During 2017,  we reported net income of $237.0 million which included a gain of $78.4 million on the divestment of certain Canadian assets during the second quarter.

24ENERPLUS 2018 FINANCIAL SUMMARY

ENVIRONMENT

We strive to carry out our activities and operations in compliance with all applicable regulations and best industry practices. Our operations are subject to laws and regulations concerning pollution, protection of the environment and the handling of hazardous materials and waste. We set corporate targets and mandates to maintain our strong environmental performance and execute environmental initiatives to become more energy efficient and to reduce, reuse and recycle water and minimize waste.

We have a Safety and Social Responsibility Policy (“S&SR Policy”), which articulates our commitment to health and safety, stakeholder engagement, environmental and regulatory compliance. Our Board of Directors and President & Chief Executive Officer are ultimately accountable for ensuring compliance with the S&SR Policy. The Safety & Social Responsibility Committee of our Board of Directors (the “S&SR Committee”) is responsible for overseeing our S&SR performance, ensuring there are adequate systems in place to support ongoing compliance, and to plan the Company’s activities in a safe and socially responsible manner.

We have established processes and programs designed to evaluate and minimize health, safety, and environmental risks, and strive for continuous improvement in our S&SR performance. We also actively participate in industry recognized programs that support our sustainability goals. 

The S&SR Policy articulates our commitment to protecting the health and safety of all persons and communities involved in, or affected by, our business activities, and articulates our commitment to the environment. It states we endeavor to: (i) proactively manage our impact on the environment and consider innovative improvement opportunities; (ii) work to reduce our environmental impact in the areas in which we operate; (iii) improve our water and land use practices; (iv) limit the waste we generate; (v) prevent and manage environmental releases; (vi) provide transparent disclosure; and (vii) provide resources and training to meet our environmental commitments. Our commitment to building meaningful and transparent relationships, engaging with our stakeholders, and adhering to responsible development of resources and regulatory compliance is also stated.

We intend to continue to improve energy efficiencies and proactively manage our greenhouse gas emissions in compliance with applicable government regulations, including regulations enacted at the provincial, state, and federal levels in which we operate.

There are inherent risks of spills and pipeline leaks at our operating sites and clean‑up costs may be significant. However, we have an active site inspection program, corrosion risk management strategy and asset integrity management program to help minimize this risk. In addition, we carry environmental insurance to help mitigate the cost of releases should they occur.

Some of our operations use hydraulic fracturing techniques, which involves the injection of pressurized fluids, sand, and small amounts of additives into a well bore. Government and regulatory agencies continue to frame regulations related to this process. We believe we are in compliance with all current government regulations and industry best practices in the U.S. and Canada.

The S&SR Committee regularly reviews health, safety, environmental and regulatory updates, and risks. At present, we believe we are, and expect to continue to be, in compliance with all material applicable environmental laws and regulations and we have included appropriate amounts in our capital expenditure budget to continue to meet our ongoing environmental obligations. However, increased capital and operating costs may be incurred if regulations in Canada or the U.S. impose more stringent compliance requirements.

We publish a Corporate Sustainability Report in accordance with the Global Reporting Initiative (GRI) international standard. The report summarizes our environmental, safety, social responsibility and governance performance, and can be found on our website at www.enerplus.com.  

Overall, we strive to operate in a socially responsible manner and believe our health, safety and environmental initiatives and performance confirm our ongoing commitment to environmental stewardship and the health and safety of our employees, contractors, and the public in the communities in which we operate.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with U.S. GAAP requires management to make certain judgments and estimates. Due to the timing of when activities occur compared to the reporting of those activities, management must estimate and accrue operating results and capital spending. Changes in these judgments and estimates could have a material impact on our financial results and financial condition.

ENERPLUS 2018 FINANCIAL SUMMARY             25

Oil and Natural Gas Properties and Reserves

Enerplus follows the full cost method of accounting for oil and natural gas properties. The process of estimating reserves is critical in determining several accounting estimates including the Company’s depletion, ceiling test, valuation allowance on deferred income tax and gain or loss calculations. Estimating reserves requires significant judgments based on available geological, geophysical, engineering and economic data. These estimates may change substantially as data from ongoing development and production activities becomes available, and as economic conditions impacting oil and natural gas prices, operating costs and royalty burdens change. Reserves estimates impact net income through depletion, the determination of asset retirement obligation and the application of impairment tests. Revisions or changes in reserves estimates can have either a positive or a negative impact on net income.

Asset Impairment

Ceiling Test

Under the full cost method of accounting for PP&E, we are subject to quarterly calculations of a ceiling or limitation on the amount of our oil and natural gas properties that can be capitalized on our balance sheet by cost centre. If the net capitalized costs of our oil and natural gas properties exceed the cost centre ceiling, we are subject to a ceiling test write‑down to the extent of such excess. These write‑downs reduce net income and impact shareholders’ equity in the period of occurrence and result in lower depletion expense in future periods. The volume and discounted present value of our proved reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. However, the associated prices of oil and natural gas that are used to calculate the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that we use the unweighted arithmetic average price of oil and natural gas as of the first day of each month for the 12‑month period ending at the balance sheet date. If average oil and natural gas prices decline, or if we have downward revisions to our estimated proved reserves, it is possible that further write‑downs of our oil and natural gas properties could occur in the future. Under U.S. GAAP impairments are not reversed in future periods.

Goodwill

Enerplus recognizes goodwill relating to business acquisitions when the total purchase price exceeds the fair value of the net assets acquired. Goodwill is allocated to reporting units and is assessed for impairment at least annually. To assess impairment, the Company first evaluates qualitative factors, such as industry and market considerations and overall financial performance, to determine whether events or changes in circumstances indicate that goodwill may be impaired. If it is more likely than not that the fair value of the reporting unit is less than its carrying value including goodwill, a quantitative impairment test is performed. If the carrying amount of the reporting unit exceeds its related fair value, goodwill is written down to its implied fair value. The fair value used in the impairment test is based on estimates of discounted future cash flows which involve assumptions of natural gas and liquids reserves, including commodity prices, future costs and discount rates.

Income Taxes

Management makes certain estimates in calculating deferred tax assets and liabilities, as well as income tax expense. These estimates often involve judgment regarding differences in the timing and recognition of revenue and expense for tax and financial reporting purposes as well as the tax basis of our assets and liabilities at the balance sheet date before tax returns are completed. Additionally, we must assess the likelihood we will be able to recover or utilize our deferred tax assets. We must record a valuation allowance against a deferred tax asset where all or a portion of that asset is not expected to be realized. In evaluating whether a valuation allowance should be applied, we consider evidence such as future taxable income, among other factors, both positive and negative. This determination involves numerous judgments and assumptions and includes estimating factors such as commodity prices, production and other operating conditions. If any of those factors, assumptions or judgments change, the deferred tax asset could change, and in particular decrease in a period where we determine it is more likely than not that the asset will not be realized. Alternatively, a valuation allowance may be reversed where it is determined it is more likely than not that the asset will be realized.

Asset Retirement Obligation

Management calculates the asset retirement obligation based on estimated costs to abandon, reclaim and remediate its ownership interest in all wells, facilities and pipelines and the estimated timing of the costs to be incurred in future periods. The fair value estimate is capitalized to PP&E as part of the cost of the related asset and depleted over its useful life. There are uncertainties related to asset retirement obligations and the impact on the financial statements could be material as the eventual timing and costs for the obligations could differ from our estimates. Factors that could cause our estimates to differ include any changes to laws or regulations, reserves estimates, costs and technology.

26ENERPLUS 2018 FINANCIAL SUMMARY

Business Combinations

Management makes various assumptions in determining the fair value of any acquired company’s assets and liabilities in a business combination. The most significant assumptions and judgments made relate to the estimation of the fair value of the oil and gas properties. To determine the fair value of these properties, we, and independent evaluators, estimate oil and gas reserves and future prices of crude oil and natural gas.

Derivative Financial Instruments

We utilize derivative financial instruments to manage our exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. Fair values of derivative contracts fluctuate depending on the underlying estimate of future commodity prices, foreign currency exchange rates, interest rates and counterparty credit risk.

RECENT U.S. GAAP ACCOUNTING AND RELATED PRONOUNCEMENTS

Effective in 2018, Enerplus adopted ASC 606 – Revenue from contracts with customers. The adoption of this standard had no impact on the Consolidated Financial Statements, with the exception of additional note disclosures. See Notes 2(o) and 9 to the Consolidated Financial Statements for further details.

Effective January 1, 2019, Enerplus is required to adopt ASC 842 – Leases.  The adoption of this standard is expected to have a material impact on the Company’s Consolidated Financial Statements. See Note 2(o) to the Consolidated Financial Statements for further details.

Refer to Note 2(o) in our Financial Statements for a detailed listing of Standards and Interpretations that were issued but not yet effective at December 31, 2018.

RISK FACTORS AND RISK MANAGEMENT 

Commodity Price Risk

Our operating results and financial condition are dependent on the prices we receive for our crude oil, natural gas liquids, and natural gas production. These prices have fluctuated widely in response to a variety of factors including global and domestic supply and demand of crude oil, natural gas and natural gas liquids, economic conditions including currency fluctuations, weather conditions, the level of consumer demand, the ability to export oil and liquefied natural gas and natural gas liquids from North America and the supply and price of imported oil and liquefied natural gas, the production and storage levels of North American crude oil, natural gas and natural gas liquids, political stability, transportation facilities, availability of processing, fractionation and refining facilities, the effect of world-wide energy conservation and greenhouse gas reduction measures, the price and availability of alternative fuels and existing and proposed changes to government regulations.

A future decline in crude oil or natural gas prices may have a material adverse effect on our operations and cash flows, financial condition, borrowing ability, levels of reserves and resources and the level of expenditures for the development of our oil and natural gas reserves or resources. Certain oil or natural gas wells may become or remain uneconomic to produce if commodity prices are low, thereby impacting our production volumes, or our desire to market our production in unsatisfactory market conditions. Furthermore, we may be subject to the decisions of third party operators or to legislative decisions by regional governments who, independently and using different economic parameters, may decide to curtail or shut-in jointly owned production or to mandate industry-wide production curtailments.

We may use financial derivative instruments and other hedging mechanisms to help limit the adverse effects of crude oil, natural gas liquids, and natural gas price volatility. However, we do not hedge all of our production and expect there will always be a portion that remains unhedged. Furthermore, we may use financial derivative instruments that offer only limited protection within selected price ranges. To the extent price exposure is hedged, we may forego the benefits that would otherwise be experienced if commodity prices increase. At February 20, 2019, approximately 63% of our 2019 forecasted crude oil production, net of royalties, and 34% of our 2019 forecasted natural gas production, net of royalties, are hedged at price levels disclosed in the “Price Risk Management” section above. For 2020 we have also hedged approximately 43%, of our forecasted 2019 crude oil production, net of royalties. Refer to the “Price Risk Management” section for further details on our price risk management program.

ENERPLUS 2018 FINANCIAL SUMMARY             27

Regulatory Risk and Greenhouse Gas Emissions

Government royalties, environmental laws and regulatory requirements can have a significant financial and operational impact on us. As an oil and gas producer, we operate under federal, provincial, state, tribal and municipal legislation and regulation that govern such matters as royalties, land tenure, prices, production rates, various environmental protection controls, well and facility design and operation, income taxes, and the exportation of crude oil, natural gas and other products. We may be required to apply for regulatory approvals in the ordinary course of business. To the extent that we fail to comply with applicable government regulations or regulatory approvals, we may be subject to compliance and enforcement actions that are either remedial or punitive to deter future noncompliance. Such actions include fines or fees, notices of noncompliance, warnings, orders, curtailment, administrative sanctions, and prosecution.

Government regulations may be changed from time to time in response to economic or political conditions, including the election of new state, provincial or federal leaders. Additionally, our entry into new jurisdictions or adoption of new technology may attract additional regulatory oversight which could result in higher costs or require changes to proposed operations. Canadian and U.S. governments have enhanced their oversight and reporting obligations associated with fracturing procedures and increased their scrutiny of the usage and disposal of chemicals and water used in fracturing procedures. Additionally, various levels of Canadian and U.S. governments are considering or have implemented legislation to reduce emissions of greenhouse gases, including volatile organic compounds (“VOC”), and methane gas emissions.

The exercise of discretion by governmental authorities under existing regulations, the implementation of new regulations or the modification of existing regulations could negatively impact the development of oil and gas properties and assets, reduce demand for crude oil and natural gas or impose increased costs on oil and gas companies including taxes, fees or other penalties.

Although we have no control over these regulatory risks, we continuously monitor changes in these areas by participating in industry organizations, conferences, exchanging information with third party experts and employing qualified individuals to assess the impact of such changes on our financial and operating results. Accordingly, while we continue to prepare to meet the potential requirements at each of the provincial, state and federal levels, the actual cost impact and its materiality to our business remains uncertain.

Access to Transportation and Processing Capacity

Market access for crude oil, natural gas liquids and natural gas production in Canada and the U.S. is dependent on our ability, and the ability of our buyers as applicable, to obtain transportation capacity on third party pipelines and rail as well as access to processing facilities. As production increases in the regions where we operate,  it is possible production may exceed the existing capacity of the gathering, pipeline, processing or rail infrastructure. While third party pipelines, processors and independent rail operators generally expand capacity to meet market needs, there can be differences in timing between the growth of production and the growth of capacity. There are occasionally operational reasons for curtailing transportation and processing capacity. Accordingly, there can be periods where transportation and processing capacity is insufficient to accommodate all the production from a given region, causing added expense and/or volume curtailments for all shippers. Our assets are concentrated in specific regions where government or other third parties could limit or ban the shipping of commodities by truck, pipeline or rail. Special interest groups could also oppose infrastructure development and/or expansion resulting in a delay or even the cancellation of the required infrastructure, further impeding our ability to produce and market our products. Additionally, the transportation of crude oil by rail has been under closer scrutiny by government regulatory agencies in Canada and the U.S. over the past few years. As a result, transporting crude oil by rail may carry a higher cost versus traditional pipeline infrastructure or other means of transporting production.

We monitor this risk for both the short and longer term through dialogue and review with the third party pipelines and other market participants. Where available and commercially appropriate, given the production profile and commodity, we attempt to mitigate transportation and processing risk by contracting for firm pipeline or processing capacity or using other means of transportation, including trucking or selling to third parties that have access to pipeline or rail capacity.

Access to Field Services

Our ability to drill, complete and tie‑in wells in a timely manner may be impacted by our access to service providers and supplies. Activity levels in each area may limit our access to these resources, restricting our ability to execute our capital plans in a timely manner. In addition, field service costs are influenced by market conditions and therefore can become cost prohibitive.

Although we have entered into service contracts for a portion of field services that will secure some of our drilling and fracturing services through 2019, access to field services and supplies in other areas of our business will continue to be subject to market availability.

28ENERPLUS 2018 FINANCIAL SUMMARY

Risk of Increased Capital or Operating Costs

Higher capital or operating costs associated with our operations will directly impact our capital efficiencies and cash flow. Capital costs of completions, specifically the costs of proppant, and operating costs such as electricity, chemicals, gas processing, supplies, energy services and labour costs, are a few of the costs that are susceptible to material fluctuation. Although we have a portion of our 2019 capital and operating costs protected with existing agreements and contract reopeners, changing regulatory conditions, such as those in the U.S. requiring that certain raw materials be sourced from the U.S., may result in higher than expected supply costs.

Risk of Curtailed or Shut-in Production

Should we be required to curtail or shut‑in production as a result of low commodity prices, environmental regulation, government regulation or third party operational practices, it could result in a reduction to cash flow and production levels and may result in additional operating and capital costs for the well to achieve prior production levels. In addition, curtailments or shut‑ins may cause damage to the reservoir and may prevent us from achieving production and operating levels that were in place prior to the curtailment or shutting‑in of the reservoir. With regard to curtailment, the Government of Alberta announced industry-wide mandatory crude oil production curtailments on December 9, 2018. However, based on our current and anticipated Alberta oil production levels, we are currently exempt from this legislation. Combined with the ongoing volatility in commodity prices, any shortage in pipeline infrastructure in producing regions where we operate may result in discounted prices and an ongoing risk of price-related production curtailments.

Risk of Public Opposition and Activism

The oil and natural gas industry elicits concerns over climate change, as well as general public opposition to the industry. As a result, industry participants such as Enerplus may be subject to increased public activism, as well as extensive environmental regulation. Activist activity may result in increased costs due to delays or damage.

The expansion of our business activities, both geographically and with a focus on exploration, may draw increased attention from shareholder activists who oppose our strategy, which could have an adverse effect on market value. Our ongoing participation in the Canadian and U.S. capital markets may expose us to greater risk of class action lawsuits related to securities law, title, contractual and environmental matters.

Access to Capital Markets

Our access to capital has allowed us to fund a portion of our acquisitions and development capital program through issuance of equity and debt in past years. Continued access to capital is dependent on our ability to optimize our existing assets and to demonstrate the advantages of the acquisition or development program that we are financing at the time, as well as investors’ view of the oil and gas industry overall. We may not be able to access the capital markets in the future on terms favorable to us, or at all. Our continued access to capital markets is dependent on corporate performance and investor perception of future performance (both corporately and for the oil and gas sector in general).

We are required to assess our “foreign private issuer” status under U.S. securities laws on an annual basis. If we were to lose our status as a “foreign private issuer” under U.S. securities laws, we may have restricted access to capital markets for a period of time until the required approvals are in place from the SEC.

Anticipated Benefits of Acquisitions or Divestments

From time to time, we may acquire additional crude oil and natural gas properties and related assets. Achieving the anticipated benefits of such acquisitions will depend in part on successfully consolidating functions and integrating operations, procedures, and personnel in a timely and efficient manner, as well as our ability to realize the anticipated growth opportunities from combining and integrating the acquired assets and properties into our existing business. These activities will require the dedication of substantial management effort, time, capital, and other resources, which may divert management's focus, capital and other resources from other strategic opportunities and operational matters during this process. The risk factors specified in this MD&A relating to the crude oil and natural gas business and our operations, reserves and resources apply equally to future properties or assets that we may acquire. We conduct due diligence in connection with acquisitions, but there is no assurance that we will identify all the potential risks and liabilities related to such properties.

ENERPLUS 2018 FINANCIAL SUMMARY             29

When acquiring assets, we are subject to inherent risks associated with predicting the future performance of those assets. We may make certain estimates and assumptions respecting the characteristics of the assets we acquire, that may not be realized over time. As such, assets acquired may not possess the value we attribute to them, which could adversely impact our future cash flows. To the extent that we make acquisitions with higher growth potential, the higher risks often associated may result in increased chances that actual results may vary from our initial estimates. An initial assessment of an acquisition may be based on a report by engineers or firms of engineers that have different evaluation methods, approaches, and assumptions than those of our engineers, and these initial assessments may differ significantly from our subsequent assessments. There is also no assurance that the acquired assets will be viewed favourably by our investors and could result in a negative effect to the price of our common shares.

Certain acquisitions, and in particular acquisitions of higher risk/higher growth assets and the development of those acquired assets, may require capital expenditures and we may not receive cash flow from operating activities from these acquisitions for several years, or in amounts less than anticipated. Accordingly, the timing and amount of capital expenditures may adversely affect our cash flow.

We may also seek to divest of properties and assets from time to time. These divestments may consist of non‑core properties or assets, or may consist of assets or properties that are being monetized to fund alternative projects or development or debt repayments. There can be no assurance that we will be successful, that we will realize the amount of desired proceeds, or that such divestments will be viewed positively by the financial markets. Divestments may negatively affect our results of operations or the trading price of our common shares. In addition, although divestments typically transfer future obligations to the buyer, we may not be exempt from certain future obligations, including abandonment, reclamation, and/or remediation if applicable, which may have an adverse effect on our operations and financial condition.

Changes in Income Tax and Other Laws

Income tax, other laws or government incentive programs relating to the oil and gas industry may change in a manner that adversely affects us or our security holders. Canadian, U.S. and foreign tax authorities may interpret applicable tax laws, tax treaties or administrative positions differently than we do or may disagree with how we calculate our income for tax purposes in a manner which is detrimental to us and our security holders.

We monitor developments with respect to pending legal changes and work with the industry and professional groups to ensure that our concerns with any changes are made known to various government agencies. We obtain confirmation from independent legal counsel and advisors with respect to the interpretation and reporting of material transactions.

Health, Safety and Environmental Risk

Health, safety and environmental risks impact our workforce and operating costs and result in the enhancement of our business practices and standards. There may be risks associated with hydraulic fracturing or produced water disposal including the risk of induced seismicity with the injection of fluid into any reservoir. We expect regulatory frameworks will be amended or continue to emerge in this regard. Although Enerplus proactively mitigates perceived risks involved in the hydraulic fracturing process, increased capital and operating costs may be incurred if regulations in Canada or the U.S. impose more stringent compliance requirements surrounding hydraulic fracturing. The impact of such changes on our business could increase our cost of compliance and the risk of litigation and environmental liability.

We have an S&SR department that develops standards and systems to manage health, safety and environmental risks, and regulatory compliance. The S&SR Committee of our Board of Directors is responsible for overseeing the organization’s health, safety and environmental performance and ensuring there are adequate systems in place to support ongoing compliance, and to plan activities in a safe and socially responsible manner. We have insurance to cover a portion of our property losses, liability and business interruption. At present, we believe we are, and expect to continue to be, in compliance with all material applicable environmental laws and regulations and have included appropriate amounts in our capital expenditure budget to continue to meet our ongoing environmental obligations.

Production Replacement Risk

Oil and natural gas reserves naturally deplete as they are produced over time. Our ability to replace production depends on our success in acquiring new land, reserves and/or resources and developing existing reserves and resources. Acquisitions of oil and gas assets will depend on our assessment of value at the time of acquisition and ability to secure the acquisitions generally through a competitive bid process.

Acquisitions and our development capital program are subject to investment guidelines, due diligence and review. Major acquisitions and our annual capital development budget are approved by the Board of Directors and where appropriate, independent reserve engineer evaluations are obtained.

30ENERPLUS 2018 FINANCIAL SUMMARY

Oil and Gas Reserves and Resources Risk

The value of our company is based on, among other things, the underlying value of our oil and gas reserves and resources. Geological and operational risks along with product price forecasts can affect the quantity and quality of reserves and resources and the cost of ultimately recovering those reserves and resources. Lower crude oil, natural gas liquids, and natural gas prices along with lower development capital spending associated with certain projects may increase the risk of write‑downs for our oil and gas property investments. Changes in reporting methodology as well as regulatory practices can result in reserves or resources write‑downs.

Each year, independent reserves engineers evaluate the majority of our proved and probable reserves as well as evaluate or audit the resources attributable to a significant portion of our undeveloped land. All reserves information, including our U.S. reserves, has been prepared in accordance with NI 51‑101 standards. For U.S. GAAP accounting purposes, our proved reserves are estimated to be technically the same as our proved reserves prepared under NI 51‑101 and have been adjusted for the effects of SEC constant prices. Independent reserves evaluations have been conducted on approximately 95% of the total proved plus probable net present value (discounted at 10% and using NI 51-101 standards) of our reserves at December 31, 2018. McDaniel & Associates Consultants Ltd. (“McDaniel”) evaluated 70% of our Canadian reserves and reviewed the internal evaluation completed by Enerplus on the remaining portion. McDaniel also evaluated 100% of the reserves associated with our U.S. tight oil assets. Netherland, Sewell & Associates, Inc. (“NSAI”) evaluated 100% of our U.S. Marcellus shale gas assets.

The evaluations of contingent resources associated with a portion of our Canadian waterflood properties and our North Dakota assets were conducted by Enerplus’ qualified reserves evaluators and audited by McDaniel. NSAI evaluated our Marcellus shale gas best estimate development pending contingent resources.

The Reserves Committee of the Board of Directors and the Board of Directors has reviewed and approved the reserves and resources reports of the independent evaluators.

Cyber Security Risks

We are subject to a variety of information technology and system risks as part of our normal course operations, including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach and destruction or interruption of our information technology systems by third parties or insiders. Although we have security measures and controls in place that are designed to mitigate these risks, a breach of our security and/or a loss of information could occur and result in a loss of material and confidential information, reputation damage, a breach in privacy laws and disruption to business activities. The significance of any such event is difficult to quantify, but may be material in certain circumstances and could have a material effect on our business, financial condition and results of operations.

Risk of Impairment of Oil and Gas Properties, Deferred Tax Assets and Goodwill

Under U.S. GAAP, the net capitalized cost of oil and gas properties, net of deferred income taxes, is limited to the present value of after‑tax future net revenue from proved reserves, discounted at 10%, and based on the unweighted average of the closing prices for the applicable commodity on the first day of the twelve months preceding the issuer’s reporting date. The amount by which the net capitalized costs exceed the discounted value will be charged to net income.

Under U.S. GAAP, the net deferred tax asset is limited to the estimate of future taxable income resulting from existing properties. We estimate future taxable income based on before‑tax future net revenue from proved plus probable reserves, undiscounted, using forecast prices, and adjusted for other significant items affecting taxable income. The amount by which the gross deferred tax assets exceed the estimate of future taxable income will be charged to net income, however these amounts can be reversed in future periods if future taxable income increases.

Goodwill is tested for impairment on an annual basis or more frequently if events or changes in circumstances indicate that goodwill may be impaired. We first perform a qualitative assessment by evaluating potential indicators of impairment, and if it is more likely than not that the fair value of the reporting unit is less than its carrying value, a quantitative impairment test is performed. If the carrying value of the reporting unit exceeds its fair value, goodwill is written down to its implied fair value with an offsetting charge to net income.

We recorded no impairment on our crude oil and natural gas assets in 2018 and 2017. Similarly, no impairment was recognized on our goodwill and deferred tax asset in 2018 and 2017. There is a risk of impairment on our oil and gas properties, deferred tax asset and goodwill if commodity prices weaken, costs increase, or if there is a downward revision to reserves. Please refer to the “Impairments” and “Income Taxes” sections of the MD&A and Notes 5 and 12 of the Financial Statements for further details.

ENERPLUS 2018 FINANCIAL SUMMARY             31

Counterparty and Joint Venture Credit Exposure

We are subject to the risk that the counterparties to our risk management contracts, marketing arrangements and operating agreements and other suppliers of products and services may default on their obligations under such agreements as a result of liquidity requirements or insolvency. Low oil and natural gas prices increase the risk of bad debts related to our joint venture and industry partners. A failure of our counterparties to perform their financial or operational obligations may adversely affect our operations and financial position. In addition to the usual delays in payment by purchasers of crude oil and natural gas, payments may also be delayed by, among other things: (i) capital or liquidity constraints experienced by our counterparties, including restrictions imposed by lenders; (ii) accounting delays or adjustments for prior periods; (iii) delays in the sale or delivery of products or delays in the connection of wells to a gathering system; (iv) weather related delays, such as freeze‑offs, flooding and premature thawing; (v) blow‑outs or other accidents; or (vi) recovery by the operator of expenses incurred in the operation of the properties or the establishment by the operator of reserves for these expenses. Any of these delays could reduce the amount of our cash flow and the payment of cash dividends to our shareholders in a given period and expose us to additional third-party credit risks.

A credit review process is in place to assess and monitor our counterparties’ credit worthiness on a regular basis. This includes reviewing and ratifying our corporate credit guidelines, assessing the credit ratings of our counterparties and setting exposure limits. When warranted we attempt to obtain financial assurances such as letters of credit, parental guarantees, or third-party insurance to mitigate our counterparty risk. In addition, we monitor our receivables against a watch list of publicly traded companies that have high debt‑to‑cash flow ratios or fully drawn bank facilities and, where possible, take our production in kind rather than relying on third party operators. In certain instances, we may be able to aggregate all amounts owing to each other and settle with a single net amount.

See the “Liquidity and Capital Resources” section for further information.

Title Defects or Litigation

Unforeseen title defects or litigation may result in a loss of entitlement to production, reserves and resources.

Although we conduct title reviews prior to the purchase of assets these reviews do not guarantee that an unforeseen defect in the chain of title will not arise. We maintain good working relationships with our industry partners; however, disputes may arise from time to time with respect to ownership of rights of certain properties or resources.

Foreign Currency Exposure

We have exposure to fluctuations in foreign currency as most of our senior notes are denominated in U.S. dollars. Our U.S. operations are directly exposed to fluctuations in the U.S. dollar when translated to our Canadian dollar denominated financial statements. We also have indirect exposure to fluctuations in foreign currency as our crude oil sales and a portion of our natural gas sales are based on U.S. dollar indices. Our oil and gas revenues are positively impacted when the Canadian dollar weakens relative to the U.S. dollar. However, our U.S. capital spending, transportation and operating costs, interest expense and U.S. dollar denominated debt are negatively impacted with a weak Canadian dollar.

Currently, we do not have any foreign exchange contracts in place to hedge our foreign exchange exposure. However, we continue to monitor fluctuations in foreign exchange and the impact on our operations.

Ability to Divest Properties

Recent regulatory changes in Alberta and Saskatchewan have increased the minimum corporate liability rating required of purchasers of crude oil and natural gas properties. As a result, the potential number of parties able to acquire our non-core assets has been reduced, we may not be able to obtain full value for such assets, or transactions may involve greater risk and complexity. The Supreme Court of Canada’s decision in the Redwater Energy Corporation case may also impact our ability to transfer licences, approvals or permits, and may result in increased costs and delays or require changes to our abandonment of projects and transactions. We also understand that further regulatory changes are being planned in Alberta and British Columbia, which may result in additional factors being considered when evaluating such transactions.   

Debt covenants may be exceeded with no ability to negotiate covenant relief

Declines in oil and natural gas prices may result in a significant reduction in earnings or cash flow, which could lead us to increase drawn amounts under the bank credit facility to carry out our operations and fulfill our obligations. Significant reductions to cash flow, significant increases in drawn amounts under the bank credit facility or significant reductions to proved reserves may result in a breach of our debt covenants. If a breach occurs, there is a risk that we may not be able to negotiate covenant relief with one or more of our lenders. Failure to comply with debt covenants or negotiate relief may result in our indebtedness under the bank credit facility and senior note agreements becoming immediately due and payable, which may have a material adverse effect on our operations and financial condition.

32ENERPLUS 2018 FINANCIAL SUMMARY

Our most restrictive debt covenant is a maximum senior debt to adjusted EBITDA ratio of 3.5x for a period of up to six months, after which it drops to 3.0x. At December 31, 2018, our senior debt to adjusted EBITDA ratio was 0.9x. We routinely review our compliance with covenants based on actual and forecasted results and have the ability to adjust our capital spending levels and dividends or pursue asset divestments and equity issuances to comply with our covenants.

See the “Liquidity and Capital Resources” section for further information.

Interest Rate Exposure

Movements in interest rates and credit markets may affect our borrowing costs and value of investments such as our shares as well as other equity investments.

Currently, we do not have any floating interest rate debt. At December 31, 2018, we were undrawn on our $800 million bank credit facility and our debt consisted of fixed interest rate senior notes.

ADJUSTED FUNDS FLOW SENSITIVITY

The sensitivities below reflect all commodity contracts listed in Note 14 to the Financial Statements and are based on 2019 guidance price levels of: WTI - US$50.00/bbl, NYMEX - US$3.00/Mcf and a USD/CDN exchange rate of 1.32. To the extent crude oil and natural gas prices change significantly from current levels, the sensitivities will no longer be relevant.

	Estimated Effect on
	2019 Adjusted Funds Flow
Sensitivity Table	per Share(1)
Increase of US$5.00 per barrel in the price of WTI crude oil	$	0.20
Decrease of US$5.00 per barrel in the price of WTI crude oil	$	(0.17)
Change of US$0.50 per Mcf in the price of NYMEX natural gas	$	0.12
Change of 1,000 BOE/day in production	$	0.04
Change of $0.01 in the US/CDN exchange rate	$	0.02
Change of 1% in interest rate(2)	$	nil

(1) Calculated using 239.4 million shares outstanding at December 31, 2018.

(2) There is no impact to adjusted funds flow for an increase in interest rates, as Enerplus is currently undrawn on its floating interest rate bank credit facility and all outstanding senior notes are based on fixed interest rates. 

2019 GUIDANCE

A summary of our previously released 2019 guidance is below.

Summary of 2019 Expectations	Target
Capital spending	$565 - $635 million
Average annual production	94,000 – 100,000 BOE/day
Average annual crude oil and natural gas liquids production	52,500 – 56,000 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 differential (compared to NYMEX natural gas)	US$(0.30)/Mcf

(1) Excludes transportation costs. 

ENERPLUS 2018 FINANCIAL SUMMARY             33

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	Year ended December 31,
($ millions)		2018		2017		2016
Oil and natural gas sales, net of royalties		$	1,292.7	$	920.7	$	722.7
Less:
Production taxes			(87.3)		(54.3)		(37.4)
Cash operating expenses(1)			(238.3)		(197.7)		(249.0)
Transportation costs			(123.5)		(111.3)		(107.1)
Netback before hedging		$	843.6	$	557.4	$	329.2
Cash gains/(losses) on derivative instruments			(35.8)		8.6		80.3
Netback after hedging		$	807.8	$	566.0	$	409.5

(1) Total operating expenses have been adjusted to exclude non‑cash gains of nil in 2018, $0.6 million in 2017, and $1.1 million in 2016.

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

Reconciliation of Cash Flow from Operating Activities to Adjusted Funds Flow	Year ended December 31,
($ millions)		2018		2017		2016
Cash flow from operating activities		$	738.8	$	476.1	$	312.3
Asset retirement obligation expenditures			11.3		12.9		8.4
Changes in non-cash operating working capital			3.4		35.1		(15.1)
Adjusted funds flow		$	753.5	$	524.1	$	305.6

“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	Year ended December 31,
($ millions)		2018		2017		2016
Adjusted funds flow		$	753.5	$	524.1	$	305.6
Capital spending			(593.9)		(458.0)		(209.1)
Free cash flow		$	159.6	$	66.1	$	96.5

“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, asset impairment, gain on divestment of assets, gain on prepayment of senior notes, unrealized foreign exchange gain/loss, and the tax effect of these items.

Calculation of Adjusted Net Income	Year ended December 31,
($ millions)		2018		2017		2016
Net income/(loss)		$	378.3	$	237.0	$	397.4
Unrealized derivative instrument (gain)/loss			(124.3)		(6.2)		105.0
Asset impairment			-		-		301.2
Gain on divestment of assets			-		(78.4)		(559.2)
Gain on prepayment of senior notes			-		-		(19.3)
Unrealized foreign exchange (gain)/loss			58.6		(42.6)		(40.6)
Tax effect on above items			32.2		22.4		55.7
Adjusted net income		$	344.8	$	132.2	$	240.2

34ENERPLUS 2018 FINANCIAL SUMMARY

“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.

“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, depletion, 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 and office expenditures divided by adjusted funds flow.

Calculation of Adjusted Payout Ratio	Year ended December 31,
($ millions)		2018		2017		2016
Cash dividends		$	29.3	$	29.0	$	35.4
Capital and office expenditures			600.4		460.7		210.6
Sub-total		$	629.7	$	489.7	$	246.0
Adjusted funds flow		$	753.5	$	524.1	$	305.6
Adjusted payout ratio (%)			84%		93%		80%

“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)	December 31, 2018
Net income/(loss)	$	378.3
Add:
Interest		36.8
Current and deferred tax expense/(recovery)		103.2
DD&A and asset impairment		304.3
Other non-cash charges(2)		(39.8)
Adjusted EBITDA	$	782.8

(1) Adjusted EBITDA is calculated based on the trailing four quarters.

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

In addition, the Company uses certain financial measures within the “Overview” and “Liquidity and Capital Resources” sections 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”, “senior net debt to adjusted EBITDA”, “total debt to adjusted EBITDA”, “total debt to capitalization”, “maximum 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 controls 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 Issuers’ Annual and Interim Filings. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of Enerplus Corporation have concluded that, as at December 31, 2018, 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, 2018 and ended December 31, 2018 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, 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.

ENERPLUS 2018 FINANCIAL SUMMARY             35

FORWARD-LOOKING INFORMATION AND STATEMENTS

This MD&A contains certain forward-looking information and statements ("forward-looking information") within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", “guidance”, "ongoing", "may", "will", "project", "plans", “budget”, "strategy" and similar expressions are intended to identify forward-looking information. In particular, but without limiting the foregoing, this MD&A contains forward-looking information pertaining to the following: expected 2019 average production volumes, timing thereof and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting our adjusted funds flow; anticipated production volumes subject to curtailment; 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; operating and transportation costs; our anticipated share 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 2019 guidance contained in this MD&A is based on the following: a WTI price of US$50.00/bbl to US$55.00/bbl, a NYMEX price of US$3.00/Mcf, and a USD/CDN exchange rate of 1.32. 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 and Form 40-F as at December 31, 2018).

The purpose of our adjusted funds flow sensitivity is to assist readers in understanding our expected and targeted financial results, and this information may not be appropriate for other purposes. The forward-looking information contained in this MD&A speaks only as of the date of this MD&A, and we do not assume any obligation to publicly update or revise such forward-looking information to reflect new events or circumstances, except as may be required pursuant to applicable laws.

36ENERPLUS 2018 FINANCIAL SUMMARY