Enerplus (ERF) 40-F 2016 FY Annual report (Canada)

      2016 FINANCIAL SUMMARY

Contents
Financial Summary	1
Highlights	3
Management’s Discussion and Analysis	5
Financial Statements	39
Five Year Detailed Statistical Review	66
Supplemental Information	68
Abbreviations & Definitions	76
Board of Directors	79
Officers	80
Corporate Information	81

      2016 FINANCIAL SUMMARY

	Three months ended					Twelve months ended
SELECTED FINANCIAL RESULTS	December 31,					December 31,
		2016		2015			2016		2015
Financial (000’s)
Adjusted Funds Flow(4)	$		107,730	$	102,674		$	305,605	$	493,101
Dividends to Shareholders			7,214		22,717			35,439		131,955
Net Income/(Loss)			840,325		(624,987)			397,416		(1,523,403)
Debt Outstanding, net of Cash and Restricted Cash			375,520		1,216,184			375,520		1,216,184
Capital Spending			57,462		89,490			209,135		493,403
Property and Land Acquisitions			118,452		8,794			126,126		9,552
Property Divestments			389,750		83,236			670,364		286,614
Debt to Adjusted Funds Flow Ratio(4)			1.2x		2.5x			1.2x		2.5x
Financial per Weighted Average Shares Outstanding
Net Income/(Loss) - Basic		$	3.49	$	(3.03)		$	1.75	$	(7.39)
Net Income/(Loss) - Diluted			3.43		(3.03)			1.72		(7.39)
Weighted Average Number of Shares Outstanding (000’s)			240,483		206,517			226,530		206,205
Selected Financial Results per BOE(1)(2)
Oil & Natural Gas Sales(3)		$	32.81	$	23.81		$	25.88	$	27.07
Royalties and Production Taxes			(7.60)		(4.75)			(5.77)		(5.63)
Commodity Derivative Instruments			1.12		7.50			2.36		7.40
Cash Operating Expenses			(7.22)		(8.68)			(7.31)		(8.75)
Transportation Costs			(3.44)		(2.98)			(3.14)		(2.95)
General and Administrative Expenses			(1.63)		(1.75)			(1.75)		(2.09)
Cash Share-Based Compensation			(0.17)		0.16			(0.09)		(0.02)
Interest, Foreign Exchange and Other Expenses			(0.97)		(2.94)			(1.28)		(2.78)
Current Tax Recovery			0.26		0.07			0.07		0.43
Adjusted Funds Flow(4)		$	13.16	$	10.44		$	8.97	$	12.68

	Three months ended					Twelve months ended
SELECTED OPERATING RESULTS	December 31,					December 31,
		2016		2015			2016		2015
Average Daily Production(2)
Crude Oil (bbls/day)			37,128		41,135			38,353		41,639
Natural Gas Liquids (bbls/day)			4,413		5,092			4,903		4,763
Natural Gas (Mcf/day)			284,515		364,065			299,214		360,733
Total (BOE/day)			88,960		106,905			93,125		106,524
% Crude Oil and Natural Gas Liquids			47%		43%			46%		44%
Average Selling Price(2)(3)
Crude Oil (per bbl)		$	53.91	$	43.04		$	44.84	$	48.43
Natural Gas Liquids (per bbl)			21.31		16.61			15.29		18.06
Natural Gas (per Mcf)			2.89		1.89			2.06		2.15
Net Wells Drilled			5		2			25		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 2016 FINANCIAL SUMMARY             1

	Three months ended					Twelve months ended
	December 31,					December 31,
Average Benchmark Pricing		2016		2015			2016		2015
WTI crude oil (US$/bbl)		$	49.29	$	42.18		$	43.32	$	48.80
AECO natural gas – monthly index (CDN$/Mcf)			2.81		2.65			2.09		2.77
AECO natural gas – daily index (CDN$/Mcf)			3.09		2.47			2.16		2.69
NYMEX natural gas – last day (US$/Mcf)			2.98		2.27			2.46		2.66
US/CDN average exchange rate			1.33		1.34			1.32		1.28

Share Trading Summary	CDN(1) – ERF		U.S.(2) – ERF
For the twelve months ended December 31, 2016	(CDN$)		(US$)
High	$	13.55	$	10.33
Low	$	2.68	$	1.84
Close	$	12.74	$	9.48

(1)      TSX and other Canadian trading data combined.

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

2016 Dividends per Share		CDN$		US$(1)
First Quarter Total	$	0.09	$	0.07
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	$	0.18	$	0.13

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

2ENERPLUS 2016 FINANCIAL SUMMARY

      2016 HIGHLIGHTS

Financial and Operational Highlights

· Fourth quarter 2016 production averaged 88,960 BOE per day, bringing annual average 2016 production to 93,125 BOE per day, in line with guidance of 93,000 BOE per day. Fourth quarter 2016 crude oil and natural gas liquids production averaged 41,541 barrels per day, impacted by severe weather in North Dakota during the quarter. Annual average 2016 liquids production was 43,256 barrels per day, within the guidance range of 43,000 to 44,000 barrels per day.

· Enerplus realized strong value from its non-core divestments in 2016, selling 13,500 BOE per day (60% natural gas) of production for aggregate proceeds of $670.4 million.

· The Company reported fourth quarter 2016 net income of $840.3 million, or $3.43 per diluted share. Net income was impacted by a gain on the sale of the Company’s non-operated North Dakota properties of $339.4 million, and a non-cash deferred tax recovery of $567.8 million primarily as a result of the reversal of a portion of the valuation allowance on the Company’s deferred tax asset. For the year ended December 31, 2016, Enerplus reported net income of $397.4 million, or $1.72 per diluted share, compared with a net loss of $1,523.4 million, or $7.39 per share, for the comparable 2015 period.

· Enerplus generated fourth quarter 2016 adjusted funds flow of $107.7 million, an increase of 34% from the previous quarter as a result of stronger commodity prices in the fourth quarter. The Company generated full year 2016 adjusted funds flow of $305.6 million, down 38% from the comparable 2015 period due to lower average commodity prices and lower hedging gains in 2016.

· Enerplus delivered strong operating cost performance in 2016 reflecting efficiency improvements and the divestment of higher cost properties. Fourth quarter operating expenses were $7.15 per BOE, a reduction of 18% compared to the same period in 2015. Full year 2016 operating expenses were $7.27 per BOE, a reduction of 17% compared to 2015.

· Fourth quarter 2016 cash G&A expenses were $1.63 per BOE, a reduction of 7% compared to the same period in 2015. Full year 2016 cash G&A expenses were $1.75 per BOE, a reduction of 16% compared to 2015. Enerplus’ lower G&A cost structure is, in part, a result of a reduction in staffing levels related to non-core asset divestments.

· Transportation expense in the fourth quarter of 2016 was $3.44 per BOE, up slightly from the previous quarter. Full year 2016 transportation expense was $3.14 per BOE, a 6% increase from the prior year period.

· Capital spending in the fourth quarter of 2016 was $57.5 million, with approximately 71% allocated to North Dakota. Full year 2016 capital spending totaled $209.1 million, slightly below annual 2016 guidance of $215.0 million.

· Enerplus significantly strengthened its balance sheet during 2016 having reduced its total debt, net of cash and restricted cash, by 69%, or $840.7 million, over the twelve-month period. Total debt, net of cash and restricted cash, at December 31, 2016 was $375.5 million, and was comprised of $23.2 million of bank indebtedness and $745.6 million of senior notes less $393.3 million in cash, including $392.0 million in restricted cash. The restricted cash balance reflects proceeds from the sale of the Company’s non-operated North Dakota properties which were placed in escrow in order to facilitate possible future like-kind transactions in accordance with U.S. federal tax regulations. Net debt to adjusted funds flow at year-end was 1.2 times.

Reserves Highlights

· Replaced 126% of 2016 production, adding 42.6 MMBOE (42% crude oil and natural gas liquids) of proved plus probable (“2P”) reserves from development activities (including revisions).

· Material reserves growth was realized in Enerplus’ North Dakota and Marcellus assets. The Company replaced 207% of 2016 North Dakota production, excluding production from Enerplus’ non-operated North Dakota assets which were sold at the end of 2016, adding 17.5 MMBOE of 2P reserves (including revisions). The Company also replaced 175% of 2016 Marcellus production, adding 125.0 Bcf of 2P reserves (including revisions).

· Finding and development (“F&D”) costs for proved developed producing (“PDP”) reserves decreased by 60% to $4.77 per BOE for 2016, generating a PDP reserves recycle ratio of 2.0 times based on a 2016 operating netback (before hedging) of $9.66 per BOE. Enerplus’ three-year average PDP reserves F&D cost was $10.37 per BOE.

ENERPLUS 2016 FINANCIAL SUMMARY             3

· F&D costs for 2P reserves decreased by 43% to $4.82 per BOE for 2016, including future development costs (“FDC”), generating a 2P reserves recycle ratio of 2.0 times. Enerplus’ three-year average 2P reserves F&D cost, including FDC, was $8.11 per BOE.

· Enerplus sold various non-core properties in 2016 representing 37.3 MMBOE of 2P reserves at a combined value of $20.38 per BOE. Total 2P reserves, net of divestments, were 382.5 MMBOE at year-end 2016, representing a 6% decrease from year-end 2015. Excluding acquisitions and divestments, 2P reserves increased by 2% in 2016.

· 2P reserves were comprised of 51% crude oil and natural gas liquids and 49% natural gas at year-end 2016.

· Total proved reserves account for 70% of 2P reserves. PDP reserves represent 71% of total proved reserves and 50% of 2P reserves.

4ENERPLUS 2016 FINANCIAL SUMMARY

      MD&A

EXHIBIT 99.3

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

The following discussion and analysis of financial results is dated February 23, 2017 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, 2016 and 2015 and for the years ended December 31, 2016, 2015 and 2014.

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, including the prior period comparatives. 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.

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 peers.

The following table provides a reconciliation of our production volumes:

		Year ended December 31,
Average Daily Production Volumes	2016		2015		2014
Company interest production volumes
Crude oil (bbls/day)		38,353		41,639		40,208
Natural gas liquids (bbls/day)		4,903		4,763		3,565
Natural gas (Mcf/day)		299,214		360,733		356,142
Company interest production volumes (BOE/day)		93,125		106,524		103,130
Royalty volumes
Crude oil (bbls/day)		7,198		7,471		7,731
Natural gas liquids (bbls/day)		932		971		775
Natural gas (Mcf/day)		50,270		59,077		55,114
Royalty volumes (BOE/day)		16,508		18,288		17,692
Net production volumes
Crude oil (bbls/day)		31,155		34,168		32,477
Natural gas liquids (bbls/day)		3,971		3,792		2,790
Natural gas (Mcf/day)		248,944		301,656		301,028
Net production volumes (BOE/day)		76,617		88,236		85,438

ENERPLUS 2016 FINANCIAL SUMMARY             5

2016 FOURTH QUARTER OVERVIEW

Fourth quarter production averaged 88,960 BOE/day, in line with our target of 89,000 BOE/day, and a decrease of 3,117 BOE/day compared to third quarter production of 92,077 BOE/day. In the U.S. production during the fourth quarter was impacted by approximately 1,700 BOE/day of price related curtailments in the Marcellus and fewer on-streams in North Dakota along with severe winter weather. Canadian production was consistent with the prior quarter, with production from our November asset acquisition of a  Canadian waterflood property offsetting price related shut-ins and minor non-core asset divestments. Operating costs increased somewhat in the fourth quarter, to $58.5 million or $7.15/BOE from $56.2 million or $6.64/BOE in the third quarter, due to additional weather related costs in December.

We reported net income of $840.3 million and adjusted funds flow of $107.7 million in the fourth quarter compared to a net loss of $100.7 million and adjusted funds flow of $80.1 million in the third quarter. Both net income and adjusted funds flow benefited from a $29.1 million or 15% increase in net oil and natural gas sales compared to the third quarter, with improved pricing offsetting the impact of lower production volumes. Net income also increased as a result of a non-cash deferred tax recovery of $567.8 million due to the reversal of a portion of the valuation allowance on our deferred tax asset and a $339.4 million gain on the sale of non-operated North Dakota properties. 

On November 15, 2016, we closed the previously announced purchase of a Canadian waterflood property for proceeds of $110.3 million.  

On December 30, 2016, we closed the previously announced sale of our non-operated North Dakota properties with production of approximately 5,000 BOE/day for proceeds of $392.0 million.

Selected Fourth Quarter Canadian and U.S. Financial Results

	Three months ended						Three months ended
	December 31, 2016						December 31, 2015
(millions, except per unit amounts)	Canada		U.S.		Total		Canada		U.S.		Total
Average Daily Production Volumes(1)
Crude oil (bbls/day)		12,417		24,711		37,128		13,790		27,345		41,135
Natural gas liquids (bbls/day)		1,160		3,253		4,413		1,771		3,321		5,092
Natural gas (Mcf/day)		68,437		216,078		284,515		135,898		228,167		364,065
Total average daily production (BOE/day)		24,983		63,977		88,960		38,210		68,695		106,905
Pricing(2)
Crude oil (per bbl)	$	48.44	$	56.66	$	53.91	$	38.11	$	45.53	$	43.04
Natural gas liquids (per bbl)		36.33		15.96		21.31		28.77		10.13		16.61
Natural gas (per Mcf)		3.13		2.82		2.89		2.46		1.55		1.89
Capital Expenditures
Capital spending	$	10.2	$	47.3	$	57.5	$	26.8	$	62.7	$	89.5
Acquisitions		111.2		7.2		118.4		0.7		8.1		8.8
Divestments		(1.5)		(388.3)		(389.8)		0.9		(84.1)		(83.2)
Netback(3) Before Hedging
Oil and natural gas sales	$	78.9	$	189.7	$	268.6	$	84.0	$	150.2	$	234.2
Royalties		(11.0)		(40.1)		(51.1)		(9.0)		(25.8)		(34.8)
Production taxes		(0.4)		(10.6)		(11.0)		(1.5)		(10.5)		(12.0)
Cash operating expenses		(30.7)		(28.4)		(59.1)		(54.4)		(30.9)		(85.3)
Transportation costs		(3.2)		(25.0)		(28.2)		(5.2)		(24.1)		(29.3)
Netback before hedging	$	33.6	$	85.6	$	119.2	$	13.9	$	58.9	$	72.8
Other Expenses
Commodity derivative instruments loss/(gain)	$	33.0	$	—	$	33.0	$	(31.1)	$	—	$	(31.1)
General and administrative expense(4)		21.0		7.0		28.0		10.4		8.1		18.5
Current income tax recovery		—		(2.1)		(2.1)		(0.4)		(0.3)		(0.7)

(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.

6ENERPLUS 2016 FINANCIAL SUMMARY

Comparing the fourth quarter of 2016 with the same period in 2015:

· Average daily production was 88,960 BOE/day, down 17% or approximately 17,945 BOE/day from 106,905 BOE/day in 2015 primarily due to our non-core Canadian asset divestments and lower capital spending.

· Despite a significant reduction in capital spending, U.S. production declined only modestly over the period as a result of strong well performance. This was offset somewhat by the divestment of 1,000 BOE/day of our non-operated North Dakota properties during the fourth quarter of 2015. U.S. crude oil production decreased 10% or 2,634 BOE/day from the fourth quarter of 2016 to the fourth quarter of 2015, while natural gas production decreased 5% or 2,015 BOE/day over the same period.

· Capital spending decreased to $57.5 million compared to $89.5 million in the fourth quarter of 2015. The majority of our capital investment in the fourth quarter was focused on our core areas, with spending of $41.1 million on our North Dakota crude oil properties, $10.2 million on our Canadian crude oil waterflood properties and $4.2 million on our Marcellus natural gas properties.

· Operating expenses decreased to  $58.5 million ($7.15/BOE) compared to $85.6 million ($8.71/BOE) in the fourth quarter of 2015 as a result of ongoing cost efficiencies and the divestment of higher operating cost Canadian properties throughout 2016.

· Cash general and administrative (“G&A”) expenses decreased to $13.4 million ($1.63/BOE) compared to $17.2 million ($1.75/BOE) in 2015 due to reductions in staffing levels and the success of our ongoing cost saving initiatives.

· We reported net income of $840.3 million in the fourth quarter of 2016 compared to a net loss of $625.0 million in the fourth quarter of 2015. The improvement year over year was primarily the result of a non-cash deferred tax recovery of $567.8 million due to the reversal of a portion of our valuation allowance on our deferred tax asset, compared to a non-cash deferred tax provision of $294.4 million on our deferred tax asset in the same period of 2015. Net income also benefitted from a gain of $339.4 million on the sale of our non-operated North Dakota property and a $221.0 million decrease in the non-cash impairment charge on our crude oil and natural gas assets compared to the fourth quarter of 2015.  

· Adjusted funds flow increased to $107.7 million compared to $102.7 million in the fourth quarter of 2015. The increase in adjusted funds flow was a result of significantly higher commodity prices, which were offset in part by lower production volumes and a $64.1 million decrease in cash gains on commodity hedges.

 2016 OVERVIEW AND 2017 OUTLOOK

Summary of Guidance and Results	Original 2016 Guidance	Revised 2016 Guidance	2016 Results	2017 Guidance
Capital spending ($ millions)	$ 200	$ 215	$ 209	$ 450
Average annual production (BOE/day)	90,000 - 94,000	93,000	93,125	86,000 – 90,000
Crude oil and natural gas liquids volumes (bbls/day)	43,000 - 45,000	43,000 - 44,000	43,256	40,000 – 43,000
Average royalty and production tax rate                                                                        (% of oil and natural gas sales)	23%	22%	22%	23%
Operating expenses (per BOE)	$ 9.50	$ 7.50	$ 7.27	$ 7.85
Transportation costs (per BOE)	$ 3.30	$ 3.15	$ 3.14	$ 3.90
Cash G&A expenses (per BOE)	$ 2.10	$ 1.80	$ 1.75	$ 1.80

2016 Overview

We improved our financial position in 2016 despite the weakness and volatility in commodity prices. We achieved this through ongoing cost reductions, strong operational results, a disciplined capital program and a successful non-core asset divestment program.

Average annual production was 93,125 BOE/day, consistent with our guidance of 93,000 BOE/day. Crude oil and liquids volumes were 43,256 bbls/day, within our guidance range of 43,000 – 44,000 bbls/day.

ENERPLUS 2016 FINANCIAL SUMMARY             7

Our capital spending for the year totaled $209.1 million, slightly below our guidance of $215 million due to weather related deferrals of spending in the fourth quarter.

Operating expenses and cash G&A expenses came in under our guidance, at $7.27/BOE and $1.75/BOE, respectively, compared to guidance of $7.50/BOE and $1.80/BOE, respectively. The outperformance was a result of our ongoing cost saving initiatives and our continued effort to focus our business through the sale of higher cost, non-core assets.

Net income for 2016 was $397.4 million, a significant increase from our net loss of $1,523.4 million in 2015 primarily due to a $1,051.3 million decrease in non-cash asset impairments,  along with $578.5 million in realized gains on asset divestments and senior note prepayments. 

Adjusted funds flow decreased 38% to $305.6 million in 2016 from $493.1 million in 2015. This was due to a $161.7 million decrease in net oil and gas sales over the period as a result of lower production volumes and weaker commodity prices, along with a $207.4 million decrease in realized gains on commodity hedges. These reductions were offset by significant cost savings in operating, interest and cash G&A expenses.

We continued to focus our portfolio  during 2016, divesting of certain non-operated crude oil assets in the U.S. and lower margin crude oil and natural gas assets in Canada for aggregate proceeds of $670.4 million. These assets had associated production of approximately 13,500 BOE/day.

On May 31, 2016, we completed an equity financing of 33,350,000 common shares at a price of $6.90 per share for gross proceeds of $230.1 million ($220.4 million net of issue costs).

Proceeds from both the asset divestments and equity financing were used to reduce our total debt, net of cash and restricted cash, by 69% or $840.7 million compared to the prior year. Net debt at December 31, 2016 was $375.5 million, comprised of $23.2 million of bank indebtedness and $745.6 million of senior notes less $393.3 million in cash and restricted cash. At December 31, 2016, we were approximately 3% drawn on our $800 million senior unsecured bank credit facility.

2017 Outlook

Our focus for 2017 is to deliver profitable growth and generate strong returns on capital while maintaining our balance sheet strength. Accordingly, we have increased our capital budget for 2017 to $450 million, with the majority directed to our North Dakota crude oil properties. We expect this spending level to generate significant liquids growth, with a 25% increase in liquids production from the beginning of 2017 to the fourth quarter of 2017, driven by 50% growth in our total North Dakota production over the same period.

Annual 2017 production is expected to average between 86,000 – 90,000 BOE/day, with crude oil and natural gas liquids production expected to average between 40,000 – 43,000 bbls/day. Following a limited completions program in North Dakota in the fourth quarter of 2016, capital spending is forecast to begin to ramp-up in the first half of 2017, driving strong liquids production growth in the back half of the year. Total fourth quarter production is expected to average 92,000 – 97,000 BOE/day, with a fourth quarter liquids production target of 45,000 - 50,000 bbls/day.

To support our 2017 capital program, we have increased our 2017 crude oil hedging program to 63% of our forecast crude oil production volumes, after royalties, and 23% of our natural gas production, after royalties.  We have also added crude oil hedges in 2018 and 2019 on approximately 44% and 14%, respectively, based on our forecasted 2017 net crude oil production.

Operating expenses are expected to average approximately $7.85/BOE in 2017, modestly higher than 2016 levels as we expect to increase our corporate weighting of liquids production in 2017.

We expect cash G&A expenses in 2017 to average approximately $1.80/BOE. Although we expect total costs to decrease year over year, our per BOE expenses will remain flat due to lower production volumes.

Transportation costs are expected to average $3.90/BOE in 2017, an increase from 2016 levels. The increase is largely attributable to additional firm transportation commitments in the Marcellus that came into effect in August 2016 that deliver to higher priced markets, along with lower production volumes due to the non-operated year-end 2016 divestment and a weaker Canadian dollar projected in 2017 compared to 2016. 

8ENERPLUS 2016 FINANCIAL SUMMARY

RESULTS OF OPERATIONS

Production

Average Daily Production Volumes	2016	2015	2014
Crude oil (bbls/day)	38,353	41,639	40,208
Natural gas liquids (bbls/day)	4,903	4,763	3,565
Natural gas (Mcf/day)	299,214	360,733	356,142
Total daily sales (BOE/day)	93,125	106,524	103,130

Production in 2016 averaged 93,125 BOE/day, in line with our guidance of 93,000 BOE/day. Crude oil and liquids volumes were 43,256 bbls/day, within our guidance range of 43,000 – 44,000 bbls/day. The 13% decrease in average production compared to the prior year was primarily due to the sale of non-core properties during the fourth quarter of 2015 and throughout the first three quarters of 2016 with associated production of approximately 11,800 BOE/day, and our reduced capital spending program compared to the prior year.

Our U.S. production decreased a modest 2% compared to 2015 despite our reduced capital spending. The decrease was primarily due to a 1,200 BOE/day or 4% reduction in Marcellus natural gas production due to lower investment and price related production curtailments during the year. In North Dakota, strong production from our crude oil properties offset the impact of decline and the fourth quarter 2015 sale of a portion of our non-operated properties.

Canadian production volumes decreased 12,310 BOE/day or 31% compared to the prior year, largely due to asset divestments. Price related shut-ins and asset declines also impacted Canadian production, but were offset somewhat by our November, 2016 acquisition of a Canadian waterflood property.

Our crude oil and natural gas liquids production accounted for 46% of our total average daily production in 2016, compared to 44% in 2015.

In 2015, production increased 3% over 2014 to average 106,524 BOE/day. Crude oil production increased 4% from the prior year due to 6,000 BOE/day or 28% growth in our North Dakota crude oil volumes. Our natural gas production was relatively consistent with 2014 at 360,733 Mcf/day, with 8% growth in our Marcellus production offset by decline in Canadian natural gas volumes over the same period.

2017 Guidance

We expect annualaverage production for 2017 of 86,000 – 90,000 BOE/day, including 40,000 – 43,000 bbls/day of crude oil and natural gas liquids. As a result of our increased capital spending program of $450 million, we expect strong production growth in the second half of the year, with liquids production expected to grow 25% from the beginning of 2017 to the end of the year. Accordingly, we are providing fourth quarter total average production guidance of 92,000 – 97,000 BOE/day and fourth quarter liquids production guidance of 45,000 – 50,000 bbls/day. This guidance includes the full year impact of our 2016 acquisitions and divestments, including the December 30, 2016 sale of 5,000 BOE/day non‑operated North Dakota properties and the November 15, 2016 acquisition of a Canadian waterflood property.

ENERPLUS 2016 FINANCIAL SUMMARY             9

Pricing

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

Pricing (average for the period)	2016		2015		2014
Benchmarks
WTI crude oil (US$/bbl)	$	43.32	$	48.80	$	93.00
AECO natural gas – monthly index ($/Mcf)		2.09		2.77		4.42
AECO natural gas – daily index ($/Mcf)		2.16		2.69		4.51
NYMEX natural gas – last day (US$/Mcf)		2.46		2.66		4.41
US/CDN average exchange rate		1.32		1.28		1.10
US/CDN period end exchange rate		1.34		1.38		1.16
Enerplus selling price(1)
Crude oil ($/bbl)	$	44.84	$	48.43	$	86.28
Natural gas liquids ($/bbl)		15.29		18.06		51.72
Natural gas ($/Mcf)		2.06		2.15		3.94
Average differentials
MSW Edmonton – WTI (US$/bbl)	$	(3.21)	$	(3.93)	$	(7.17)
WCS Hardisty – WTI (US$/bbl)		(13.84)		(13.52)		(19.40)
Transco Leidy monthly – NYMEX (US$/Mcf)		(1.15)		(1.52)		(1.95)
TGP Z4 300L monthly – NYMEX (US$/Mcf)		(1.21)		(1.58)		(2.04)
AECO monthly – NYMEX (US$/Mcf)		(0.89)		(0.50)		(0.41)
Enerplus realized differentials(1)
Canada crude oil – WTI (US$/bbl)	$	(13.21)	$	(13.34)	$	(17.36)
Canada natural gas – NYMEX (US$/Mcf)		(0.80)		(0.44)		(0.34)
Bakken crude oil – WTI (US$/bbl)		(7.46)		(9.44)		(12.94)
Marcellus natural gas – NYMEX (US$/Mcf)		(0.93)		(1.37)		(1.43)

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

CRUDE OIL AND NATURAL GAS LIQUIDS

Our realized crude oil price in 2016 averaged $44.84/bbl, a 7% decrease compared to 2015. Benchmark WTI crude oil prices fell by 11% versus 2015 due to the continued oversupply of crude oil in the global markets for most of the year. In the fourth quarter of 2016,  the Organization of the Petroleum Exporting Countries (“OPEC”) and certain non-OPEC nations agreed to reduce production by approximately 1.8 million bbls/day through June 2017, which resulted in WTI prices strengthening at the end of the year to US$53.72/bbl.

Our Bakken sales price differential improved by 21% year over year, averaging US$7.46/bbl below WTI due to declining regional production and stronger local refinery demand. With the Dakota Access Pipeline expected to be completed and in service around mid-year 2017, increasing regional takeaway capacity, we are expecting our 2017 Bakken crude oil differential to improve to US$4.50/bbl below WTI, from our previous guidance of US$6.00/bbl below WTI. Canadian light sweet crude prices also improved, resulting in our Canadian realized price differentials to WTI narrowing slightly compared to the prior year.

We realized an average of $15.29/bbl on our natural gas liquids production, which was 15% lower than 2015 and largely in line with changes in underlying crude oil prices.

NATURAL GAS

Our realized natural gas price averaged $2.06/Mcf in 2016, a 4% decrease from 2015 realized prices but considerably stronger than the changes in benchmark prices during the period. NYMEX prices fell by 8% and AECO monthly prices fell by 25% compared to 2015 in response to excess inventories due to a warm winter in early 2016. However, with lower production levels and warmer than average summer temperatures in the U.S., NYMEX prices improved substantially over the course of the year and into 2017. In Alberta, concerns over congestion on regional pipelines due to continued production growth resulted in AECO prices averaging US$0.89/Mcf below NYMEX in 2016 compared to US$0.50/Mcf below NYMEX in 2015. Our overall realized natural gas price outperformed the benchmarks due to much stronger Marcellus basis differentials and the positive impact of our term AECO physical sales with fixed basis differentials at prices much narrower than where AECO basis market prices averaged.

In the Marcellus, the Tennessee Gas Pipeline Zone 4 - 300 Leg and Transco Leidy monthly benchmark differentials averaged US$1.21/Mcf and US$1.15/Mcf below NYMEX compared to US$1.58/Mcf and US$1.52/Mcf below NYMEX in 2015. The strengthening in local Marcellus prices was due to additional pipeline capacity coming into service, as well as higher weather

10ENERPLUS 2016 FINANCIAL SUMMARY

related demand in the region. Our realized sales price benefitted from August to December 2016 as we began to transport 30,000 Mcf/day of production to markets south of the Marcellus producing region, allowing us to realize sales prices closer to NYMEX pricing. This resulted in an average Marcellus realized sales price differential before transportation costs of US$0.93/Mcf below NYMEX, a 32% improvement from 2015.

We expect our realized Marcellus differentials in 2017 to continue to improve due to further pipeline capacity additions and stronger regional demand alleviating some of the constraints in the region. There is the potential for differentials to widen in certain periods of the year as seasonal demand falls and until sufficient pipeline capacity is built to fully relieve the congestion. We expect our Marcellus natural gas realized differential to average US$0.90/Mcf below NYMEX in 2017.

Monthly Crude Oil Prices

Monthly Natural Gas Prices

FOREIGN EXCHANGE

The Canadian dollar was volatile throughout 2016, beginning the year near a thirteen year low of 1.47 USD/CDN and strengthening to 1.25 USD/CDN in late April before closing the year at 1.34 USD/CDN. Overall, the Canadian dollar weakened relative to the U.S. dollar, averaging 1.32 USD/CDN. The majority of our oil and natural gas sales are based on U.S. dollar denominated indices, and a weaker Canadian dollar relative to the U.S. dollar increases the amount of our realized sales. Because we report in Canadian dollars, the weaker Canadian dollar also increases our U.S. dollar denominated costs, capital spending and the cost of our U.S. dollar denominated senior notes.

ENERPLUS 2016 FINANCIAL SUMMARY             11

Monthly USD/CDN Exchange Rate

Price Risk Management  

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

As of February 23, 2017, we have hedged approximately 18,000 bbls/day of our crude oil production for 2017, which represents approximately 63% of our forecasted 2017 crude oil production, after royalties. For 2018, we have hedged 12,500 bbls/day, which represents approximately 44% of our forecasted 2017 crude oil production, after royalties. We have also added hedges through 2019 to protect the long term economics of a portion of our capital program. 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 in any given month, the three way collars provide a limited amount of protection above the WTI index prices equal to the difference between the strike price of the purchased and sold puts. Overall, we continue to expect our crude oil hedge contracts to protect a significant portion of our adjusted funds flow.

As of February 23, 2017, we have hedged approximately 50,000 Mcf/day of our natural gas production for 2017 using NYMEX three way collars. This represents approximately 23% of our 2017 forecasted 2017 natural gas production, after royalties. When NYMEX prices settle below the sold put strike price in any given month, the three way collars provide a limited amount of protection above the NYMEX index prices equal to the value between the strike price of the purchased and sold puts.

12ENERPLUS 2016 FINANCIAL SUMMARY

The following is a summary of our financial contracts in place at February 23, 2017, expressed as a percentage of our anticipated production volumes, after royalties, for 2017:

	WTI Crude Oil (US$/bbl)(1)					NYMEX Natural Gas (US$/Mcf)(1)
	Jan 1, 2017 –	Jul 1, 2017 –	Jan 1, 2018 –	Jan 1, 2019 –	Apr 1, 2019 –	Jan 1, 2017 –
	Jun 30, 2017	Dec 31, 2017	Dec 31, 2018	Mar 31, 2019	Dec 31, 2019	Dec 31, 2017
Swaps
Sold Swaps	$ 53.50	$ 53.50	$ 53.73	$ 53.73	-	-
%	7%	7%	11%	11%	-	-
Three Way Collars						.
Sold Puts	$ 38.94	$ 39.62	$ 43.13	$ 45.00	$ 43.75	$ 2.06
%	49%	63%	33%	3%	14%	23%
Purchased Puts	$ 50.29	$ 50.61	$ 54.00	$ 56.00	$ 54.69	$ 2.75
%	49%	63%	33%	3%	14%	23%
Sold Calls	$ 61.14	$ 60.33	$ 63.09	$ 70.00	$ 66.18	$ 3.41
%	49%	63%	33%	3%	14%	23%

(1) Based on weighted average price (before premiums) assuming average annual production of 88,000 BOE/day for 2017, less royalties and production taxes of 23%.

We did not have any foreign exchange contracts in place during 2016. In comparison, during 2015, we recorded realized foreign exchange losses of $39.2 million on foreign exchange costless collars and foreign exchange gains of $39.9 million and $3.3 million, respectively, on the unwind of our US$175 million foreign exchange swap and the final settlement of the foreign exchange swap on our US$54 million senior notes.  

ACCOUNTING FOR PRICE RISK MANAGEMENT

Commodity Risk Management Gains/(Losses)
($ millions)	2016		2015		2014
Cash gains/(losses):
Crude oil	$	75.0	$	217.2	$	7.0
Natural gas		5.3		70.5		(3.5)
Total cash gains/(losses)	$	80.3	$	287.7	$	3.5
Non-cash gains/(losses):
Crude oil	$	(96.2)	$	(99.8)	$	182.0
Natural gas		(13.5)		(45.2)		48.9
Total non-cash gains/(losses)	$	(109.7)	$	(145.0)	$	230.9
Total gains/(losses)	$	(29.4)	$	142.7	$	234.4

(Per BOE)	2016		2015		2014
Total cash gains/(losses)	$	2.36	$	7.40	$	0.09
Total non-cash gains/(losses)		(3.22)		(3.73)		6.14
Total gains/(losses)	$	(0.86)	$	3.67	$	6.23

During 2016, we realized cash gains of $75.0 million on our crude oil contracts and $5.3 million on our natural gas contracts. In comparison, in 2015 we realized cash gains of $217.2 million on our crude oil contracts and $70.5 million on our natural gas contracts. During 2014, we realized cash gains of $7.0 million on our crude oil contracts and cash losses of $3.5 million on our natural gas contracts. The cash gains in each year were due to contracts which provided floor protection above market prices, while cash losses were a result of natural gas prices rising above our fixed price swap positions.

As the forward markets for crude oil and natural gas fluctuate and new contracts are executed and 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 and natural gas contracts represented net loss positions of $28.8 million and $9.5 million, respectively, at December 31, 2016, and net gain positions of $67.4 million and $4.0 million, respectively, at December 31, 2015. The change in fair value of our crude oil and natural gas contracts represented losses of $96.2 million and $13.5 million, respectively, during 2016 and losses of $99.8 million and $45.2 million, respectively, during 2015.

ENERPLUS 2016 FINANCIAL SUMMARY             13

Revenues

($ millions)	2016		2015		2014
Oil and natural gas sales	$	882.1	$	1,052.4	$	1,849.3
Royalties		(159.4)		(168.0)		(323.1)
Oil and natural gas sales, net of royalties	$	722.7	$	884.4	$	1,526.2

Oil and natural gas sales revenue for 2016 totaled $882.1 million, a decrease of 16% from $1,052.4 million in 2015. The decrease in revenue was a result of the continued decline in commodity prices compared to the prior year along with lower production due to non-core asset divestments and lower capital spending.

In 2015, oil and natural gas sales revenue decreased 43% to $1,052.4 million from $1,849.3 million in 2014 as a result of weak commodity prices, offset somewhat by growth in production volumes.

Royalties and Production Taxes

($ millions, except per BOE amounts)	2016		2015		2014
Royalties	$	159.4	$	168.0	$	323.1
Per BOE	$	4.67	$	4.32	$	8.58
Production taxes	$	37.4	$	50.9	$	81.5
Per BOE	$	1.10	$	1.31	$	2.17
Royalties and production taxes	$	196.8	$	218.9	$	404.6
Per BOE	$	5.77	$	5.63	$	10.75
Royalties and production taxes (% of oil and natural gas sales)		22%		21%		22%

Royalties are paid to government entities, land owners and mineral rights owners. Production taxes include state production taxes, Pennsylvania impact fees, freehold mineral taxes and Saskatchewan resource surcharges. A large percentage of our production is from U.S. properties where royalty rates are generally not as sensitive to commodity price levels.

Royalties and production taxes were in line with our guidance for 2016, averaging 22% of oil and natural gas sales, before transportation. Royalties and production taxes decreased to $196.8 million in 2016 from $218.9 million in 2015 primarily due to lower production volumes, a decrease in realized crude oil and natural gas prices and a 1.5% rate reduction of production taxes in North Dakota. In 2015, royalties and production taxes decreased to $218.9 million from $404.6 million in the prior year primarily due to decreased realized crude oil and natural gas prices.

2017 Guidance

Weexpect royalty and production taxes in 2017 to average 23% of our oil and gas sales, before transportation. The increase compared to 2016 is due to the higher percentage of U.S. production as a result of additional capital spending and growth in our U.S. assets, as well as the divestment of our non-core Canadian properties during 2016.

Operating Expenses

($ millions, except per BOE amounts)	2016		2015		2014
Cash operating expenses	$	249.0	$	340.1	$	347.3
Non-cash (gains)/losses(1)		(1.1)		0.4		1.3
Total operating expenses	$	247.9	$	340.5	$	348.6
Per BOE	$	7.27	$	8.76	$	9.26

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

Operating expenses during 2016 were $247.9 million or $7.27/BOE, beating our guidance of $7.50/BOE, largely due to higher than expected production volumes from our lower operating cost Marcellus properties during the fourth quarter. Compared to 2015, expenses decreased $92.6 million or 27% primarily due to successful cost saving initiatives, lower repairs and maintenance costs and the divestment of higher operating cost Canadian properties throughout 2016.

Operating expenses during 2015 were $340.5 million or $8.76/BOE compared to $348.6 million or $9.26/BOE in 2014. The improvement resulted mainly from cost savings and a continued increase in the U.S. weighting of production, which has lower

14ENERPLUS 2016 FINANCIAL SUMMARY

operating metrics. This was offset in part by the impact of a weaker Canadian dollar on our U.S. dollar denominated operating expenses.

2017 Guidance

We expect operatingexpenses of $7.85/BOE in 2017. The modest increase from 2016 is a result of the expected increase in the corporate weighting of our liquids production.

Transportation Costs

($ millions, except per BOE amounts)	2016		2015		2014
Transportation costs	$	107.1	$	114.7	$	101.2
Per BOE	$	3.14	$	2.95	$	2.69

Transportation costs increased on a per BOE basis throughout the year to average $3.14/BOE in 2016, consistent with our guidance of $3.15/BOE and a 6% increase compared to $2.95/BOE in 2015. The increase was primarily due to the increased weighting of U.S. production with higher associated transportation costs and additional firm transportation commitments in the Marcellus, effective August 2016.

Transportation costs increased to $2.95/BOE in 2015 compared to $2.69/BOE in 2014 as a result of increasing U.S. production and costs associated with securing U.S. pipeline capacity. The impact of a weakening Canadian dollar on our U.S. transportation costs further increased our total reported expense.

2017 Guidance

We expect transportation costs of $3.90/BOE in 2017. The increase from 2016 is largely attributable to additional firm transportation commitments in the Marcellus that came into effect in August 2016 to deliver production to higher priced markets,  lower production volumes due to the year-end 2016 divestment of non-operated North Dakota properties and a weaker Canadian dollar projected in 2017.

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. Certain prior period amounts have been reclassified to conform with current period presentation.

ENERPLUS 2016 FINANCIAL SUMMARY             15

	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

	Year ended December 31, 2015
Netbacks by Property Type		Crude Oil		Natural Gas		Total
Average Daily Production			49,069 BOE/day		344,730 Mcfe/day		106,524 BOE/day
Netback(1) $ per BOE or Mcfe			(per BOE)		(per Mcfe)		(per BOE)
Oil and natural gas sales		$	43.67	$	2.15	$	27.07
Royalties and production taxes			(10.54)		(0.24)		(5.63)
Cash operating expenses			(11.98)		(1.00)		(8.75)
Transportation costs			(1.84)		(0.65)		(2.95)
Netback before hedging		$	19.31	$	0.26	$	9.74
Cash gains/(losses)			12.13		0.56		7.40
Netback after hedging		$	31.44	$	0.82	$	17.14
Netback before hedging ($ millions)		$	345.7	$	33.0	$	378.7
Netback after hedging ($ millions)		$	562.9	$	103.5	$	666.4

	Year ended December 31, 2014
Netbacks by Property Type		Crude Oil		Natural Gas		Total
Average Daily Production			45,225 BOE/day		347,430 Mcfe/day		103,130 BOE/day
Netback(1) $ per BOE or Mcfe			(per BOE)		(per Mcfe)		(per BOE)
Oil and natural gas sales		$	79.12	$	4.28	$	49.13
Royalties and production taxes			(19.78)		(0.61)		(10.75)
Cash operating expenses			(11.76)		(1.21)		(9.23)
Transportation costs			(1.89)		(0.55)		(2.69)
Netback before hedging		$	45.69	$	1.91	$	26.46
Cash gains/(losses)			0.42		(0.03)		0.09
Netback after hedging		$	46.11	$	1.88	$	26.55
Netback before hedging ($ millions)		$	754.3	$	241.9	$	996.2
Netback after hedging ($ millions)		$	761.3	$	238.4	$	999.7

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

Crude oil and natural gas netbacks per BOE after hedging were lower during 2016 compared to 2015 and 2014 primarily due to the weakness in commodity prices compared to both the prior years and lower realized hedging gains compared to 2015, partially offset by significant improvements in our operating costs. During 2016, our crude oil properties accounted for 85% and 87% of our netback before and after hedging, respectively.

16ENERPLUS 2016 FINANCIAL SUMMARY

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”) and our stock option plan. See Note 10 and Note 14 to the Financial Statements for further details.

($ millions)	2016		2015		2014
Cash:
G&A expense	$	59.8	$	81.3	$	83.5
Share-based compensation expense		3.1		0.9		(1.2)
Non-Cash:
Share-based compensation expense		27.0		19.6		13.4
Equity swap loss/(gain)		(3.6)		2.1		9.3
Total G&A expenses	$	86.3	$	103.9	$	105.0

(Per BOE)	2016		2015		2014
Cash:
G&A expense	$	1.75	$	2.09	$	2.22
Share-based compensation expense		0.09		0.02		(0.03)
Non-Cash:
Share-based compensation expense		0.80		0.51		0.36
Equity swap loss/(gain)		(0.11)		0.05		0.24
Total G&A expenses	$	2.53	$	2.67	$	2.79

Cash G&A expenses in 2016 totaled $59.8 million ($1.75/BOE), outperforming our guidance of $1.80/BOE and a decrease of 26% from $81.3 million ($2.09/BOE) in 2015. The reduction from 2015 was primarily due to continued cost savings initiatives and the impact of ongoing staff reductions as we continue to divest of non-core assets and focus our business. 

Our share price increased significantly during 2016, resulting in cash SBC expense of $3.1 million ($0.09/BOE) compared to an expense of $0.9 million ($0.02/BOE) in 2015. Following the settlement of the final grants of our cash-settled Restricted Share Unit (“RSU”) plans during the year, the Director Share Unit (“DSU”) plan is our only remaining LTI plan that we intend to settle in cash. We recorded non‑cash SBC of $27.0 million ($0.80/BOE) in 2016 compared to $19.6 million ($0.51/BOE) in 2015. The increase in non‑cash SBC was a result of an improvement in our performance multiplier based on our relative return in the Toronto Stock Exchange Oil and Gas Producers Index,  along with additional grants issued under the treasury-settled LTI plans rather than the cash-settled plans.    

Cash G&A expenses in 2015 were $81.3 million ($2.09/BOE) compared to $83.5 million ($2.22/BOE) in 2014. The decrease in cash G&A expenses compared to 2014 was primarily due to a 20% reduction in staff levels offset by one‑time severance charges. Cash SBC expense was $0.9 million ($0.02/BOE) in 2015 compared to a recovery of $1.2 million ($0.03/BOE) in 2014. We recorded non‑cash SBC of $19.6 million ($0.51/BOE) in 2015 compared to $13.4 million ($0.36/BOE) in 2014. The increase in non‑cash SBC was a result of additional grants issued under the treasury‑settled LTI plans.

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 $3.6 million on these hedges in 2016 (2015 - $2.1 million loss; 2014 – $9.3 million loss). As of December 31, 2016, we have 470,000 units hedged at a weighted average price of $16.89/share.

2017 Guidance

We expectour cash G&A expense to be approximately $1.80/BOE in 2017, consistent with 2016 despite lower expected production levels.

ENERPLUS 2016 FINANCIAL SUMMARY             17

Interest Expense

($ millions)	2016		2015		2014
Interest on senior notes and bank facility	$	45.4	$	66.5	$	62.2
Non-cash interest expense		-		-		0.6
Total interest expense	$	45.4	$	66.5	$	62.8

Interest on our senior notes and bank credit facility in 2016 decreased 32% to $45.4 million compared to $66.5 million in 2015. The decrease in interest expense corresponds to a decrease in the aggregate principal amount of our outstanding senior notes following our repurchase of US$267 million of senior notes during the first half of 2016. The repurchase was funded by asset divestment proceeds and lower interest rate bank debt, which was repaid following our May 31, 2016 equity financing and the closing of our second quarter Canadian non-core asset divestment.

Interest expense increased to $66.5 million in 2015 from $62.8 million in 2014 due to the impact of a weaker Canadian dollar on our U.S. dollar denominated interest payments and an increased weighting of senior notes with higher interest rates compared to our bank credit facility following our US$200 million private placement in September 2014. Non-cash amounts recorded in 2014 consisted of unrealized losses on the interest component of our cross currency interest rate swap. See Note 11 to the Financial Statements for further details.

At December 31, 2016, approximately 97% of our debt consisted of fixed interest rate senior notes and approximately 3% was floating bank debt with weighted average interest rates of 5.0% and 2.6%, respectively.

Foreign Exchange

($ millions)	2016		2015		2014
Realized loss/(gain)	$	0.1	$	(8.7)	$	11.2
Unrealized loss/(gain)		(40.6)		182.6		45.9
Total foreign exchange loss/(gain)	$	(40.5)	$	173.9	$	57.1
US/CDN average exchange rate		1.32		1.28		1.10
US/CDN period end exchange rate		1.34		1.38		1.16

We recorded a net foreign exchange gain of $40.5 million in 2016 compared to losses of $173.9 million and $57.1 million in 2015 and 2014, respectively. Our foreign exchange exposure relates to fluctuations in the Canadian and U.S. dollar exchange rate.

In 2016, we recorded a realized loss of $0.1 million on day‑to‑day transactions denominated in foreign currencies, compared to a gain of $8.7 million and a loss of $11.2 million in 2015 and 2014, respectively. In 2015, realized foreign exchange included a gain of $39.9 million on the unwind of our US$175 million foreign exchange swaps and a gain of $3.3 million on the final settlement of our US$54 million senior notes and the corresponding foreign exchange swap. These gains were offset by cumulative losses of $39.2 million on our foreign exchange collars with final settlements in December 2015. In 2014, we recorded a $15.8 million loss on the final settlement of our cross currency interest rate swap and a gain of $0.7 million on our costless collars.

Unrealized foreign exchange gains and losses are recorded on the translation of our U.S. dollar denominated debt and working capital at each period end. Comparing December 31, 2016 to December 31, 2015, the Canadian dollar strengthened relative to the U.S. dollar and we reduced our U.S. dollar denominated senior notes by 33%, resulting in an unrealized gain of $40.6 million. See Note 12 to the Financial Statements for further details.

18ENERPLUS 2016 FINANCIAL SUMMARY

Capital Investment

($ millions)	2016		2015		2014
Capital spending	$	209.1	$	493.4	$	811.0
Office capital		1.5		4.5		7.0
Sub-total		210.6		497.9		818.0
Property and land acquisitions	$	126.1	$	9.5	$	18.5
Property divestments		(670.4)		(286.6)		(203.6)
Sub-total		(544.3)		(277.1)		(185.1)
Total	$	(333.7)	$	220.8	$	632.9

2016

Capital spending in 2016 totaled $209.1 million, slightly below our revised guidance of $215 million due to some weather related deferrals of spending during the fourth quarter. We continued to focus capital on our core areas during 2016, spending $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.  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.

We recorded net divestment proceeds of $670.4 million in 2016. In Canada, we sold properties for combined proceeds of $281.0 million with production of approximately 8,500 BOE/day. Sold properties consisted mainly of natural gas assets, and included certain Deep Basin natural gas properties with production of 5,400 BOE/day and non-core properties in northwest Alberta with production of 2,300 BOE/day. Divestments resulted in a $35.6 million reduction to future asset retirement obligations. 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, which was reported as restricted cash at December 31, 2016.

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.

2015

Capital spending in 2015 totaled $493.4 million and included spending of $302.3 million on our North Dakota crude oil properties, $115.7 million on our Canadian crude oil properties, $32.2 million on our Marcellus assets and $40.4 million on our Deep Basin properties in Canada. Through our capital program in 2015 we added 42 MMBOE of gross proved plus probable reserves, replacing 108% of our 2015 production, before accounting for acquisitions and divestments.

During 2015, we recorded net divestment proceeds of $286.6 million. In Canada, we divested of assets for combined proceeds of $198.9 million with production of approximately 4,900 BOE/day including the sale of our Pembina waterflood assets and certain non-core shallow gas assets with production of 2,700 BOE/day. In the U.S., we divested of assets for combined proceeds of $87.7 million with production of approximately 1,250 BOE/day, including the sale of a portion of our non‑operated North Dakota properties for proceeds of $80.4 million, and our operated Marcellus assets for proceeds of $3.5 million.

Property and land acquisitions in 2015 totaled $9.5 million and included minor acquisitions of leases and undeveloped land.

2014

Capital spending in 2014 totaled $811.0 million and included spending of $343.7 million on our North Dakota crude oil properties, $176.6 million on our Canadian crude oil properties, $158.8 million on our Marcellus assets and $124.5 million on our deep gas properties in Canada. Through our capital program in 2014 we added 75 MMBOE of gross proved plus probable reserves, replacing over 200% of our 2014 production.

Property divestments in 2014 totaled $203.6 million. In Canada we divested of natural gas properties in the Deep Basin area with production of approximately 3,100 BOE/day for proceeds of $91.0 million and recognized the remaining $65.8 million of proceeds on the 2013 sale of our undeveloped Montney acreage. During the first quarter, we sold our gross overriding royalty interest in the Jonah natural gas property in Wyoming with production of approximately 400 BOE/day for proceeds of $44.0 million, after closing adjustments. Property and land acquisitions in 2014 totaled $18.5 million and included several minor acquisitions across our core areas.

ENERPLUS 2016 FINANCIAL SUMMARY             19

2017 Guidance

To re-position ourselves for growth in 2017, we are increasing our capital spending guidance to $450 million, more than twice our spending levels in 2016. We will continue to focus our spending on our core areas, with $330 million currently allocated to North Dakota crude oil properties, $60 million to Canadian waterflood crude oil properties and $60 million to the Marcellus natural gas properties.

Gain on Asset Sales and Note Repurchases

We recorded gains of $559.2 million on asset divestments during 2016, including a gain of $339.4 million on the fourth quarter sale of our non-operated North Dakota property. No gains were recorded on asset sales in 2015 or 2014. Under full cost accounting rules, divestments of oil and natural gas properties are generally accounted for as adjustments to the full cost pool with no recognition of a gain or loss. However, if not recognizing a gain or loss on the transaction would significantly alter the relationship between a cost centre’s capitalized costs and proved reserves, then a gain or loss must be recognized. Gains and losses are evaluated on a case by case basis for each asset sale, and future sales may or may not result in such treatment.

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)	2016		2015		2014
DD&A expense	$	329.0	$	508.2	$	567.7
Per BOE	$	9.65	$	13.06	$	15.08

DD&A of property, plant and equipment (“PP&E”) is recognized using the unit‑of‑production method based on proved reserves. DD&A has decreased from 2014 to 2016 primarily due to the quarterly asset impairments recorded during 2015 and 2016 under the U.S. GAAP full cost ceiling test methodology.

Impairments

PP&E

($ millions)	2016		2015		2014
Canada cost centre	$	89.4	$	286.7	$	—
U.S. cost centre		211.8		1,065.7		—
Total Impairments	$	301.2	$	1,352.4	$	—

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 using SEC constant prices (“Standardized Measure”). SEC 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.

The trailing twelve month average crude oil and natural gas prices have decreased significantly in 2016 and 2015, resulting in non‑cash impairments totaling $301.2 million and $1,352.4 million (before tax), respectively. We did not record any impairments on our oil and natural gas properties in 2014.

The following table outlines the twelve month average trailing benchmark prices and exchange rates used in our ceiling test at December 31, 2016, 2015 and 2014:

								AECO Natural
	WTI Crude Oil		Exchange Rate	Edm Light Crude		U.S. Henry Hub		Gas Spot
Year	US$/bbl		US/CDN	CDN$/bbl		Gas US$/Mcf		CDN$/Mcf
2016	$	42.75	1.32	$	52.26	$	2.49	$	2.17
2015	$	50.28	1.27	$	59.38	$	2.58	$	2.69
2014	$	94.99	1.09	$	94.84	$	4.30	$	4.60

20ENERPLUS 2016 FINANCIAL SUMMARY

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. Although the twelve month average trailing commodity prices are below current levels, there is the potential for prices to decline further, impacting the ceiling value which could result in further non-cash impairments.

Goodwill

Goodwill impairment testing is performed annually or more frequently if events or changes in circumstances indicate that goodwill may be impaired. We 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 quantitative impairment tests. 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 as at December 31, 2016 and 2015 indicated no impairment.

Asset Retirement Obligation

In connection with our operations, we incur abandonment and reclamation 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 and reclaim 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 $181.7 million at December 31, 2016, compared to $206.4 million at December 31, 2015. The decrease was largely due to the removal of $35.6 million of asset retirement obligations related to asset divestments during 2016. See Note 8 to the Financial Statements for further information.

We take an active approach to managing our abandonment, reclamation and remediation obligations. During 2016, we spent $8.4 million (2015 – $14.9 million) on our asset retirement obligations and we expect to spend approximately $13.1 million in 2017. The majority of our abandonment and reclamation 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 and reclamation costs are anticipated to be funded out of cash flow and available credit facilities.

Income Taxes

($ millions)	2016		2015		2014
Current tax expense/(recovery)	$	(2.4)	$	(16.9)	$	5.0
Deferred tax expense/(recovery)		(234.8)		(150.6)		132.8
Total tax expense/(recovery)	$	(237.2)	$	(167.5)	$	137.8

Our current tax recovery mainly relates to a refund of U.S. Alternative Minimum Tax (“AMT”) from a prior period.

The total tax recovery in 2016 was $237.2 million, compared to $167.5 million in 2015. The increased recovery in 2016 is due primarily to the removal of a portion of our valuation allowance recorded in 2015 due to higher future taxable income projected this year compared to 2015.  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 have considered available positive and negative evidence, including future taxable income and reversing existing temporary differences in making this assessment. This assessment is primarily the result of projecting future taxable income using December 30 benchmark forward prices for 2017,  held constant and adjusted for other significant items affecting taxable income.  Had we utilized forecast prices and costs to estimate future taxable income we expect that all of our deferred income tax assets would be realized and no valuation allowance would be required. Our overall deferred income tax asset, net of valuation allowance, is $733.4 million as at December 31, 2016 (2015 - $516.1 million).

In 2015, our total tax recovery was $167.5 million compared to an expense of $137.8 million in 2014. The recovery in 2015 was due primarily to lower income, which was impacted by a $1,352.4 million non‑cash charge for asset impairments and a valuation allowance recorded against a portion of our deferred income tax asset.  

ENERPLUS 2016 FINANCIAL SUMMARY             21

Our estimated tax pools at December 31, 2016 are as follows:

Pool Type ($ millions)	2016
Canada
Canadian development expenditures (“CDE”)	$	63
Canadian exploration expenditures (“CEE”)		236
Undepreciated capital costs (“UCC”)		166
Non-capital losses and other credits		397
	$	862
U.S.
Alternative minimum tax credit (“AMT”)	$	112
Net operating losses		894
Depletable and depreciable assets		1,370
	$	2,376
Total tax pools and credits	$	3,238
Capital losses	$	1,224

Capital losses reflect the balance of unused capital losses available for carry‑forward in Canada. These capital losses have an indefinite carry‑forward period however can only be used to offset capital gains. We do not anticipate future capital gains that will allow us to utilize the capital losses. Therefore, a full valuation allowance has been applied to the deferred tax asset in respect of these capital losses.

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 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. At December 31, 2016, our senior debt to adjusted EBITDA ratio was 0.8x and our net debt to adjusted funds flow ratio was 1.2x, a significant improvement from 2.2x and 2.5x, respectively, at December 31, 2015. 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.

We strengthened our financial position significantly in 2016, reducing our net debt by 69% over the twelve month period. The overall reduction in debt was funded through proceeds from our May 2016 equity issuance and our ongoing non-core asset divestment program. On May 31, 2016, we completed an equity financing for 33,350,000 common shares at a price of $6.90 per share for gross proceeds of $230.1 million ($220.4 million, net of issue costs). Asset divestments throughout 2016 resulted in aggregate divestment proceeds of $670.4 million. This additional liquidity was used to repay our bank credit facility, repurchase US$267 million of senior notes during the first half of 2016, at prices ranging from 90% of par to par value, and purchase our Canadian waterflood property in November for $110.3 million.

Net acquisition and divestment proceeds include $392.0 million from the sale of non-operated North Dakota properties, which were classified as restricted cash on the December 31, 2016 balance sheet. As of the date of this report, we expect to continue to hold these funds in escrow for a period of up to 180 days from the date of closing to facilitate possible future like-kind transactions in accordance with U.S. federal tax regulations. 

Total debt, net of cash and restricted cash, at December 31, 2016 was $375.5 million compared to $1,216.2 million at December 31, 2015. Total debt was comprised of $23.2 million of bank indebtedness and $745.6 million of senior notes less $393.3 million in cash, including restricted cash. Our next scheduled senior notes repayment of US$22 million is due in June 2017 with remaining maturities extending to 2026.

Our adjusted payout ratio, which is calculated as cash dividends plus capital and office expenditures divided by adjusted funds flow, was 80% for 2016 compared to 128% in 2015. After adjusting for net acquisition and divestment proceeds, our funding surplus for the year ended December 31, 2016 was $603.8 million compared to $144.8 million in 2015. 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 current deferred financial and tax balances, decreased to $94.4 million at December 31, 2016 from $104.0 million at December 31, 2015. We expect to finance our working capital deficit and our ongoing

22ENERPLUS 2016 FINANCIAL SUMMARY

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.

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, 2019. There were no other amendments to the agreement terms or debt covenants. Drawn fees on our bank credit facility range between 150 and 315 basis points over Banker’s Acceptance rates, with current drawn fees of 170 basis points. The bank credit facility ranks equally with our senior unsecured covenant‑based notes.

At December 31, 2016 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 as at December 31, 2016:

Covenant Description		December 31, 2016
Bank Credit Facility:	Maximum Ratio
Senior debt to adjusted EBITDA	3.5x	0.8x
Total debt to adjusted EBITDA	4.0x	0.8x
Total debt to capitalization	50%	23%
Senior Notes:	Maximum Ratio
Senior debt to adjusted EBITDA(1)	3.0x – 3.5x	0.8x
Senior debt to consolidated present value of total proved reserves(2)	60%	28%
	Minimum Ratio
Adjusted EBITDA to interest	4.0x	20.4x

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.

“EBITDA” is calculated as net income less interest, taxes, depletion, depreciation, amortization, accretion and non‑cash gains and losses. EBITDA is calculated on a trailing twelve month basis and is adjusted for material acquisitions and divestments. EBITDA for the three months and the trailing twelve months ended December 31, 2016 were $451.8 million and $921.0 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) Senior Debt to adjusted EBITDA maximum ratio for the senior notes may increase to 3.5x for a period of 6 months, after which the ratio decreases to 3.0x.

(2) Maximum 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 great 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. At December 31, 2016, we had $40.9 million of mark‑to‑market liabilities. The majority of our outstanding derivative contracts are with financial institutions which are members of our bank syndicate. All of our derivative counterparties are considered investment grade.

ENERPLUS 2016 FINANCIAL SUMMARY             23

Dividends

($ millions, except per share amounts)	2016		2015		2014
Cash dividends	$	35.4	$	132.0	$	199.3
Stock dividend plan		—		—		21.8
Total dividends to shareholders	$	35.4	$	132.0	$	221.1
Per weighted average share (Basic)	$	0.16	$	0.64	$	1.08

We reported total dividends of $35.4 million or $0.16 per share to our shareholders in 2016. During 2015 and 2014 we reported total dividends of $132.0 million or $0.64 per share and $221.1 million or $1.08 per share, respectively.

Cash dividends for 2016 represented approximately 12% of adjusted funds flow, compared to approximately 27% in 2015 and 23% in 2014. In September 2014, we elected to suspend our stock dividend plan, thereby eliminating any dilution resulting from issuing shares as part of our dividend plan.

To provide additional financial flexibility and to better balance adjusted funds flow with capital and dividends, we reduced our monthly dividend to $0.01 per share, effective with our April 2016 payment. During 2015, we reduced our monthly dividend twice, from $0.09 per share to $0.05 per share in April and to $0.03 per share in December. 

The dividend is part of our strategy to create shareholder value; however, a sustained low price environment may impact our ability to pay dividends. We continue to monitor commodity prices and economic conditions and are prepared to make adjustments as necessary.

Shareholders’ Capital

	2016		2015		2014
Share capital ($ millions)	$	3,366.0	$	3,133.5	$	3,120.0
Common shares outstanding (thousands)		240,483		206,539		205,732
Weighted average shares outstanding – basic (thousands)		226,530		206,205		204,510
Weighted average shares outstanding – diluted (thousands)		231,293		206,205		207,424

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).

During 2016, a total of 594,000 shares (2015 – 807,000; 2014 – 2,974,000) and $9.4 million of additional equity (2015 – $13.3 million; 2014 – $53.2 million) was issued pursuant to the treasury‑settled LTI plans. For further details see Note 14 to the Financial Statements.

At February 23, 2017, we had 241,010,880 shares outstanding.

Commitments

As at December 31, 2016 we had the following minimum annual commitments:

													Total
			Minimum Annual Commitment Each Year										Committed
($ millions)	Total		2017		2018		2019		2020		2021		after 2021
Bank credit facility(1)	$	23.2	$	—	$	—	$	23.2	$	—	$	—	$	—
Senior notes(1)		746		30		29.5		59.5		109.6		109.6		407.9
Transportation commitments		293.6		31.9		29.1		24.6		22.8		19.5		165.7
Processing commitments		42.9		11.4		10.1		10.1		1.6		1.6		8.1
Drilling and completions		29.1		29.1		—		—		—		—		—
Office lease commitments		88.3		12.2		12.0		10.5		10.8		10.8		32.0
Sublease recoveries		(9.3)		(2.0)		(1.6)		(1.7)		(1.8)		(1.5)		(0.7)
Net office lease commitments		79.1		10.2		10.4		8.8		9.1		9.3		31.2
Total commitments(2)(3)	$	1,213.6	$	112.2	$	79.2	$	126.3	$	143.0	$	140.0	$	612.9

(1) Interest payments have not been included.

(2) 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.

24ENERPLUS 2016 FINANCIAL SUMMARY

(3) US$ commitments have been converted to CDN$ using the December 31, 2016 foreign exchange rate of 1.3427.

In the Marcellus, we have firm sales contracts for up to 65,000 Mcf/day through 2026. We also have firm transportation agreements in place for approximately 66,000 Mcf/day, which expire between 2020 and 2033. This includes the agreement for additional interstate pipeline capacity on the Tennessee Gas Pipeline from our Marcellus producing region to downstream connections that became effective in August 2016. Under this agreement, we are committed to a US$0.63/Mcf demand toll for 30,000 Mcf/day of natural gas for 11 years, reducing to 15,000 Mcf/day for an additional 9 years, with a total estimated transportation commitment of $148.3 million extending to 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 is currently pending regulatory approval with an expected in‑service date of 2018. 

In Canada, we have various firm transportation agreements for approximately 2,700 BOE/day of our crude oil and natural gas liquids production in 2017, decreasing to approximately 1,800 BOE/day on average from 2018 to 2027. We also have firm natural gas transportation contracts in 2017 for approximately 99,000 Mcf/day. At December 31, 2016, we have firm natural gas liquids fractionation contracts for 825 BOE/day, which increase to 1,125 BOE/day from April 2017 through 2026.

Our Canadian office lease is committed to 2024 and our U.S. office lease expires in 2019. Annual costs of these lease commitments include rent and operating fees. Our office lease commitments are shown net of sublease agreements, which we entered into to reduce our obligations.

Our commitments, contingencies and guarantees are more fully described in Note 16 to the Financial Statements.

SELECTED ANNUAL CANADIAN AND U.S. FINANCIAL RESULTS

	Year ended							Year ended
	December 31, 2016							December 31, 2015
(millions, except per unit amounts)		Canada		U.S.		Total		Canada		U.S.		Total
Average Daily Production Volumes(1)
Crude oil (bbls/day)			13,089		25,264		38,353		15,165		26,474		41,639
Natural gas liquids (bbls/day)			1,408		3,495		4,903		1,997		2,766		4,763
Natural gas (Mcf/day)			79,057		220,157		299,214		136,924		223,809		360,733
Total average daily production (BOE/day)			27,673		65,452		93,125		39,983		66,541		106,524
Pricing(2)
Crude oil (per bbl)		$	39.91	$	47.39	$	44.84	$	45.28	$	50.23	$	48.43
Natural gas liquids (per bbl)			27.52		10.36		15.29		29.41		9.88		18.06
Natural gas (per Mcf)			2.20		2.00		2.06		2.83		1.74		2.15
Capital Expenditures
Capital spending		$	44.4	$	164.7	$	209.1	$	157.7	$	335.7	$	493.4
Acquisitions			114.4		11.7		126.1		3.6		5.9		9.5
Divestments			(281.0)		(389.4)		(670.4)		(198.9)		(87.7)		(286.6)
Netback(3) Before Hedging
Oil and natural gas sales		$	269.2	$	612.9	$	882.1	$	414.4	$	638.0	$	1052.4
Royalties			(35.8)		(123.6)		(159.4)		(44.8)		(123.2)		(168.0)
Production taxes			(2.5)		(34.9)		(37.4)		(5.5)		(45.4)		(50.9)
Cash operating expenses			(135.7)		(113.3)		(249.0)		(216.7)		(123.4)		(340.1)
Transportation costs			(14.0)		(93.1)		(107.1)		(22.6)		(92.1)		(114.7)
Netback before hedging		$	81.2	$	248.0	$	329.2	$	124.8	$	253.9	$	378.7
Other Expenses
Commodity derivative instruments loss/(gain)		$	29.4	$	—	$	29.4	$	(142.7)	$	—	$	(142.7)
General and administrative expense(4)			63.9		22.4		86.3		77.0		26.9		103.9
Current income tax expense/(recovery)			(0.7)		(1.7)		(2.4)		(0.8)		(16.1)		(16.9)

(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 2016 FINANCIAL SUMMARY             25

THREE YEAR SUMMARY OF KEY MEASURES

($ millions, except per share amounts)	2016		2015		2014
Oil and natural gas sales, net of royalties	$	722.7	$	884.4	$	1,526.2
Net income/(loss)		397.4		(1,523.4)		299.1
Per share (Basic)		1.75		(7.39)		1.46
Per share (Diluted)		1.72		(7.39)		1.44
Adjusted funds flow(1)		305.6		493.1		859.0
Cash and stock dividends(2)		35.4		132.0		221.1
Per share (Basic)(2)		0.16		0.64		1.08
Total assets		2,638.9		2,581.2		4,031.5
Debt net of cash and restricted cash		375.5		1,216.2		1,134.9

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

(2) Calculated based on dividends paid or payable. Cash and stock dividends to shareholders per share may not correspond to actual dividends as a result of using the annual weighted average shares outstanding.

2016 versus 2015

Net oil and natural gas sales were $722.7 million in 2016 compared to $884.4 million in 2015 due to weaker commodity prices and lower production volumes as a result of our asset divestments over the period.

We reported net income of $397.4 million in 2016 compared to a net loss of $1,523.4 million in 2015 primarily due to decreases of $1,051.3 million in non-cash asset impairment charges and $179.2 in DD&A recorded on our crude oil and natural gas assets and gains of $578.5 million realized in 2016 on our asset divestments and the prepayment of senior notes.

Adjusted funds flow decreased 38% to $305.6 million in 2016 from $493.1 million in 2015. The decrease was mainly a result of a $207.4 million decrease in realized gains on commodity hedges and a  $161.7 million decline in net crude oil and gas sales over the period, offset by a combined decrease in cash operating costs, interest expense and cash G&A expenses of $133.7 million.

2015 versus 2014

In 2015, oil and natural gas sales, net income and adjusted funds flow decreased due to weak commodity prices, which were somewhat offset by production growth. A net loss was realized in 2015 primarily as a result of non‑cash asset impairment charges of $1,352.4 million and a non‑cash valuation allowance on our deferred income tax asset, along with lower oil and natural gas sales revenue and a $91.7 million decrease in total gains on commodity hedges. Adjusted funds flow benefited from realized cash gains on our commodity hedges, which increased to $287.7 million in 2015 compared to $3.5 million in 2014.

QUARTERLY FINANCIAL INFORMATION

	Oil and
	Natural Gas
	Sales, Net of		Net		Net Income/(Loss) Per Share
($ millions, except per share amounts)	Royalties		Income/(Loss)		Basic		Diluted
2016
Fourth Quarter	$	217.4	$	840.3	$	3.49	$	3.43
Third Quarter		188.3		(100.7)		(0.42)		(0.42)
Second Quarter		174.3		(168.5)		(0.77)		(0.77)
First Quarter		142.7		(173.7)		(0.84)		(0.84)
Total 2016	$	722.7	$	397.4	$	1.75	$	1.72
2015
Fourth Quarter	$	199.4	$	(625.0)	$	(3.03)	$	(3.03)
Third Quarter		228.3		(292.7)		(1.42)		(1.42)
Second Quarter		251.7		(312.5)		(1.52)		(1.52)
First Quarter		205.0		(293.2)		(1.42)		(1.42)
Total 2015	$	884.4	$	(1,523.4)	$	(7.39)	$	(7.39)

26ENERPLUS 2016 FINANCIAL SUMMARY

Oil and natural gas sales, net of royalties decreased in 2016 compared to 2015 due to a decline in commodity prices along with lower production due to non-core asset divestments. During 2015, the impact of weak commodity prices was somewhat offset by increasing production. Net income increased in 2016 largely due to a decrease in non-cash asset impairments on our crude oil and natural gas assets and gains realized on asset divestments. The net loss reported in 2015 was a result of non-cash asset impairments and valuation allowances on our deferred tax asset related to the decrease in the twelve month average commodity prices.

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 improve 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, environmental, stakeholder engagement, 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 and execute 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 in British Columbia, Alberta and at the federal level in Canada and the U.S.

There are inherent risks of spills and pipeline leaks at our operating sites and clean‑up costs may be significant. However, we have active site inspection, corrosion risk management and asset integrity management programs 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.

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 2016 FINANCIAL SUMMARY             27

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 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 Property, Plant and Equipment, 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. 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

Goodwill, which represents the excess of purchase price over fair value of net assets acquired, is assessed for impairment at least annually at December 31. Goodwill and all other assets and liabilities are allocated to reporting units. To assess impairment, the carrying amount of each reporting unit is determined and compared to the fair value of the reporting unit. If the carrying amount of the reporting unit is higher than its related fair value then goodwill is written down to the reporting unit’s implied fair value of goodwill. 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. That 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 changes, 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 and reclaim its net ownership interest in all wells and facilities 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.

28ENERPLUS 2016 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

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, 2016.

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 and economic conditions, including currency fluctuations, weather conditions, 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 further decline in crude oil or natural gas prices may have a material adverse effect on our operations, 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 who, independently and using different economic parameters, may decide to curtail production.

We may use financial derivative instruments and other hedging mechanisms to help limit the adverse effects of natural gas and crude oil 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 23, 2017, approximately 63% of our 2017 forecasted net crude oil production is hedged and approximately 23% of our 2017 forecasted net natural gas production is hedged at price levels disclosed in the “Price Risk Management” section above. We have also hedged approximately 44% and 14%, respectively, of our forecasted 2017 net crude oil production in 2018 and 2019. Refer to the “Price Risk Management” section for further details on our price risk management program.

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, 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 2017 capital and operating costs protected with existing agreements, 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.

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.

ENERPLUS 2016 FINANCIAL SUMMARY             29

Although we have entered into service contracts for a portion of field services that will secure some of our drilling and fracturing services into 2017, access to field services and supplies in other areas of our business will continue to be subject to market availability.

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 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, although regional pipeline capacity has increased over the past several years, sales gas infrastructure capacity in northeastern Pennsylvania remains constrained relative to the amount of natural gas that can be produced. Combined with the ongoing volatility in natural gas prices, this may result in continued discounted prices and an ongoing risk of price-related production curtailments.

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.

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, 2016, our senior debt to adjusted EBITDA ratio was 0.8x. 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.

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.

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

30ENERPLUS 2016 FINANCIAL SUMMARY

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 evaluating or auditing 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 86% of the total proved plus probable net present value (discounted at 10% and using NI 51-101 standards) of our reserves at December 31, 2016. McDaniel & Associates Consultants Ltd. (“McDaniel”) evaluated 48% 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 best estimate development pending contingent resources associated with a portion of our Canadian waterflood properties and our Fort Berthold 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 and the Board of Directors has reviewed and approved the reserves and resources reports of the independent evaluators.

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

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 assets is limited to the estimate of future taxable income resulting from existing properties. We estimate our future taxable income based on before‑tax future net revenue from proved reserves, undiscounted, using benchmark 2017 forward prices on December 30, 2016, held constant 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.

In 2016 we reported a non-cash impairment of $301.2 million on our crude oil and natural gas assets, compared to $1,352.4 million in 2015, and a non-cash recovery of $234.8 million due in part to the reversal of a portion of the valuation allowance recorded on our deferred tax asset in 2015. While these amounts do not affect cash flow, the volatility in earnings may be viewed unfavourably in the market. There is risk of further impairment on our oil and gas properties and deferred tax asset if commodity prices weaken during 2017. Additional write-downs may lead to a breach of our Total Debt to Capitalization covenant under the bank credit facility, and we may not be able to renegotiate our covenants. 

Access to Transportation and Processing Capacity

Market access for crude oil, NGLs and natural gas production in Canada and the U.S. is dependent on our ability to obtain transportation capacity on third party pipelines and rail as well as access to processing facilities. Newer resource plays, such as the North Dakota Bakken and the Marcellus shale gas, generally experience a sharp production increase in the area which could 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 of the production from a given region, causing added expense and/or volume curtailments for all shippers. Our assets are concentrated in specific regions with varying levels of government that could limit or ban the shipping of commodities by truck, pipeline or rail. Special interest groups could also oppose infrastructure development 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 may come under closer scrutiny by government regulatory agencies in Canada and the U.S.. As a result, there may be incremental costs associated with transporting crude oil by rail, and there is a risk that access to rail transport may be constrained, depending upon any changes made to existing rail transport regulations.

We continuously 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

ENERPLUS 2016 FINANCIAL SUMMARY             31

attempt to mitigate transportation and processing risk by contracting for firm pipeline or processing capacity or using other means of transportation, including truck or selling to third parties that have access to rail capacity.  

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 debt repayments 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. 

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 generally 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.

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.

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 operations 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 and reclamation, which may have an adverse effect on our operations and financial condition.

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).

32ENERPLUS 2016 FINANCIAL SUMMARY

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 U.S. Securities and Exchange Commission.

Regulatory Risk & 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 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, 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, 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. Specifically, the Province of Alberta instituted the Climate Leadership Act in 2016, which, starting in 2023, sets a carbon tax of $30 per tonne of carbon dioxide equivalent emissions that occur from our Alberta operations. The Province of Alberta has also established a reduction goal of 45% for methane gas emissions for our Alberta operations by 2025.  The Act will likely increase electrical use costs for our Alberta operations as a carbon tax for electrical use comes into effect in 2017.

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.

Specifically, with respect to regulations for the reduction of greenhouse gas emissions, the Canadian federal government continues to seek alignment for the regulations to be issued in Canada with those of the U.S.. Accordingly, while we continue to prepare to meet the potential requirements, the actual cost impact and its materiality to our business remains uncertain on a federal level.

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 new 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. 

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 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

ENERPLUS 2016 FINANCIAL SUMMARY             33

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 and execute 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.

Changes in Income Tax and Other Laws

Income tax, other laws or government incentive programs relating to the oil and gas industry may be changed 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.

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.

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.

Interest Rate Exposure

We have exposure to movements in interest rates and credit markets as changing interest rates affect our borrowing costs and value of investments such as our shares as well as other equity investments.

We monitor the interest rate forward market and have fixed the interest rate on approximately 97% of our debt through our senior notes.

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.

34ENERPLUS 2016 FINANCIAL SUMMARY

ADJUSTED FUNDS FLOW SENSITIVITY

The sensitivities below reflect all commodity contracts listed in Note 15 to the Financial Statements and are based on 2017 guidance price levels. To the extent crude oil and natural gas prices change significantly from current levels, the sensitivities will no longer be relevant.

	Estimated Effect on
	2017 Adjusted Funds Flow
Sensitivity Table	per Share(1)
Change of $0.50 per Mcf in the price of NYMEX natural gas	$	0.21
Change of US$5.00 per barrel in the price of WTI crude oil	$	0.25
Change of 1,000 BOE/day in production	$	0.03
Change of $0.01 in the US/CDN exchange rate	$	0.02
Change of 1% in interest rate	$	0.03

(1) Assumes 240.5 million weighted average shares outstanding.

2017 GUIDANCE

A summary of our previously released 2017 guidance is below, including our updated Bakken crude oil differential of US$4.50/bbl below WTI (from $6.00/bbl previously). This guidance includes the impact of the 2016 fourth quarter non-operated North Dakota sale and Canadian waterflood purchase. No additional potential acquisitions or divestments have been included. This guidance is based on a WTI crude oil price of US$55.00/bbl, NYMEX natural gas price of US$3.00/Mcf, AECO natural gas price of $2.75/GJ and a US/CDN exchange rate of 1.35.

Summary of 2017 Expectations	Target
Capital spending	$450 million
Average annual production	86,000 – 90,000 BOE/day
Fourth quarter average production	92,000 – 97,000 BOE/day
Average annual crude oil and natural gas liquids production	40,000 – 43,000 bbls/day
Fourth quarter average annual crude oil and natural gas liquids production	45,000 – 50,000 bbls/day
Average royalty and production tax rate (% of gross sales, before transportation)	23%
Operating expenses	$7.85/BOE
Transportation costs	$3.90/BOE
Cash G&A expenses	$1.80/BOE

2017 Differential/Basis Outlook(1)

U.S. Bakken crude oil differential (compared to WTI crude oil)	US$(4.50)/bbl
Marcellus basis (compared to NYMEX natural gas)	US$(0.90)/Mcf

(1) Before field transportation costs

ENERPLUS 2016 FINANCIAL SUMMARY             35

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. The term 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)		2016		2015		2014
Oil and natural gas sales, net of royalties		$	722.7	$	884.4	$	1,526.2
Less:
Production taxes			(37.4)		(50.9)		(81.5)
Cash operating expenses(1)			(249.0)		(340.1)		(347.3)
Transportation costs			(107.1)		(114.7)		(101.2)
Netback before hedging		$	329.2	$	378.7	$	996.2
Cash gains/(losses) on derivative instruments			80.3		287.7		3.5
Netback after hedging		$	409.5	$	666.4	$	999.7

(1) Operating costs adjusted to exclude non‑cash gains on fixed price electricity swaps of $1.1 million in 2016 and non-cash losses of $0.4 million in 2015 and $1.3 million in 2014.

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

Reconciliation of Cash Flow from Operating Activities to Adjusted Funds Flow	Year ended December 31,
($ millions)	2016		2015		2014
Cash flow from operating activities	$	312.3	$	465.3	$	787.2
Asset retirement obligation expenditures		8.4		14.9		19.4
Changes in non-cash operating working capital		(15.1)		12.9		52.4
Adjusted funds flow	$	305.6	$	493.1	$	859.0

“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, including restricted cash, divided by a trailing 12 months of adjusted funds flow. This measure is not equivalent to debt to earnings before interest, taxes, depreciation, amortization, impairment and other non‑cash charges (“adjusted EBITDA”) and is not a debt covenant.

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

Calculation of Adjusted Payout Ratio	Year ended December 31,
($ millions)	2016		2015		2014
Dividends(1)	$	35.4	$	132.0	$	199.3
Capital and office expenditures		210.6		497.9		818.0
Sub-total	$	246.0	$	629.9	$	1,017.3
Adjusted funds flow	$	305.6	$	493.1	$	859.0
Adjusted payout ratio (%)		80%		128%		118%

(1) Cash dividends exclude stock dividend plan proceeds in 2014. The stock dividend plan was suspended during 2014.

36ENERPLUS 2016 FINANCIAL SUMMARY

“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, 2016
Net income/(loss)	$	397.4
Add:
Interest expense		45.4
Current and deferred tax expense/(recovery)		(237.2)
DD&A and asset impairment charges		630.1
Other non-cash charges(2)		91.5
Sub-total	$	927.2
Adjustment for material acquisitions and divestments(3)		(6.2)
Adjusted EBITDA	$	921.0

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

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

(3) EBITDA is adjusted for material acquisitions or divestments during the period with net proceeds greater than $50 million as if that acquisition or divestment had been made at the beginning of the period.

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 “debt net of cash”, “senior 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, 2016, 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, 2016 and ended December 31, 2016 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.

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 2017 total and fourth quarter 2017 average production volumes and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting our adjusted funds flow; the results from our drilling program and the timing of related production; oil and natural gas prices and differentials and our commodity risk management program in 2017 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; capital spending levels in 2017 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 and to negotiate relief if required; our future acquisitions and dispositions, expecting timing thereof and use of

ENERPLUS 2016 FINANCIAL SUMMARY             37

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; 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; our ability to negotiate debt covenant relief under our bank credit facility and outstanding senior notes if required; the availability of third party services; and the extent of our liabilities. In addition, our 2017 guidance contained in this MD&A is based on the following: a WTI price of US$55.00/bbl, a NYMEX price of US$3.00/Mcf, an AECO price of $2.75/GJ and a USD/CDN exchange rate of 1.35. 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 decline of 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, 2016).

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.

38ENERPLUS 2016 FINANCIAL SUMMARY