Enerplus Announces Third Quarter 2019 Results

All financial information contained within this news release has been prepared in accordance with U.S. GAAP, except as noted under "Non-GAAP Measures". This news release includes forward-looking statements and information within the meaning of applicable securities laws. Readers are advised to review the "Forward-Looking Information and Statements" at the conclusion of this news release. A full copy of Enerplus' Third Quarter 2019 Financial Statements and MD&A are available on the Company's website at www.enerplus.com, under its SEDAR profile at www.sedar.com and on the EDGAR website at www.sec.gov.

CALGARY, Nov. 8, 2019 /CNW/ - Enerplus Corporation ("Enerplus" or the "Company") (TSX & NYSE: ERF) today reported its third quarter 2019 operating and financial results. Cash flow from operating activities for the third quarter was $159.8 million and adjusted funds flow was $175.3 million. Third quarter net income was $65.2 million, or $0.28 per share, and adjusted net income was $61.9 million, or $0.27 per share.

HIGHLIGHTS

• Third quarter total production was 107,181 BOE per day, up 6% quarter-over-quarter
• Third quarter liquids production was 60,121 barrels per day, up 14% quarter-over-quarter
• 2019 production guidance tightened to 100,000 to 101,000 BOE per day (from 99,000 to 102,000 BOE per day) with liquids production of 54,250 to 54,750 barrels per day (from 54,000 to 55,500 barrels per day)
• Third quarter capital spending was $151.5 million; 2019 capital spending guidance is now $625 million (from $610 to $630 million)
• Repurchased 7.1 million shares during the third quarter for $64.8 million
• Since initiating its share repurchase program, Enerplus has repurchased 24.2 million shares, or approximately 10% of shares outstanding
• Maintained strong financial flexibility; ended the third quarter with a net debt to adjusted funds flow ratio of 0.7 times

"In the third quarter of 2019, we continued to build on our track record of strong execution and financial discipline," stated Ian C. Dundas, President and Chief Executive Officer. "We grew our high-return production in North Dakota by 18% quarter-over-quarter, maintained our focus on costs, and returned over $70 million to shareholders through share repurchases and dividends. Year to date, we have now returned approximately $200 million to shareholders. Our 2019 plan remains on track to deliver 9 to 10% annual liquids production growth and 15% on a per share basis, while maintaining our low financial leverage."

THIRD QUARTER FINANCIAL AND OPERATIONAL SUMMARY

Production
Production in the third quarter increased by 6% from the prior quarter to average 107,181 BOE per day, including oil and natural gas liquids production of 60,121 barrels per day, an increase of 14% from the prior quarter. The sequential production growth was driven by North Dakota volumes which increased 18% from the prior quarter. Natural gas production decreased 2% quarter-over-quarter, averaging 282 MMcf per day.

Capital activity in the fourth quarter is expected to be approximately 30% lower compared to the third quarter and will be primarily related to drilling in North Dakota. Enerplus expects modestly lower sequential production in the fourth quarter and is providing fourth quarter production guidance of 103,000 to 107,000 BOE per day with liquids production of 58,000 to 60,000 barrels per day.

Adjusted Funds Flow and Adjusted Net Income
Adjusted funds flow for the third quarter was $175.3 million compared to $186.0 million in the previous quarter. Third quarter 2019 adjusted net income was $61.9 million ($0.27 per share) compared to $74.3 million ($0.32 per share) in the previous quarter.

Pricing Realizations and Cost Structure
Enerplus' third quarter 2019 realized Bakken oil price differential was US$3.61 per barrel below WTI, 20% weaker compared to the prior quarter. With wider Bakken oil differentials expected to persist through the fourth quarter, Enerplus is revising its full-year Bakken differential guidance to US$3.60 per barrel below WTI (from US$3.25 per barrel below WTI). The Company continues to manage differential risk through fixed physical sales and in the fourth quarter has 24,800 barrels per day of Bakken oil production sold at US$2.69 per barrel below WTI.

The Company's realized Marcellus natural gas price differential averaged US$0.44 per Mcf below NYMEX during the third quarter, a 23% improvement from the prior quarter. Enerplus is maintaining its full-year 2019 Marcellus differential guidance at US$0.35 per Mcf below NYMEX.

Third quarter operating expenses were $7.06 per BOE, transportation expenses were $3.96 per BOE and cash G&A expenses were $1.19 per BOE. Combined, these expenses were 7% lower compared to the previous quarter. Enerplus is reducing its full-year 2019 guidance for cash G&A expenses to $1.40 per BOE (from $1.45 per BOE).

Capital Expenditures and Balance Sheet Position
Exploration and development capital spending in the third quarter was $151.5 million and was associated with drilling 16.9 net wells and bringing 13.3 net wells on production across the Company's operations. Enerplus has revised its full-year 2019 capital spending guidance to $625 million (from $610 to $630 million).

At the end of the third quarter, Enerplus had total debt of $618.4 million, cash of $97.0 million and was undrawn on its $800 million bank credit facility. The Company's net debt to adjusted funds flow ratio was 0.7 times. Subsequent to the quarter, Enerplus renewed its bank credit facility to October 31, 2023 and amended it to a U.S. dollar denominated facility of US$600 million.

Share Repurchases

The Company repurchased 7.1 million shares during the third quarter for total consideration of $64.8 million. Subsequent to the quarter and up to November 6, 2019, the Company repurchased 2.7 million shares for a total consideration of $23.6 million and has now repurchased the maximum number of shares under its existing NCIB (7% of the public float within the meaning under the TSX rules). Enerplus today announced that its Board of Directors has approved an increase to the maximum number of shares that may be repurchased under the NCIB to 10% of the public float, representing an additional 7.1 million shares, until the expiry of its NCIB on March 25, 2020. Enerplus will continue to evaluate future share repurchases as a function of the value and returns underpinning the investment, alternative capital allocation opportunities and the Company's financial capacity.

Since initiating its share repurchase program in the third quarter of 2018 up to and including November 6, 2019, the Company has repurchased and cancelled 24.2 million shares, representing approximately 10% of shares outstanding, for total consideration of $257.8 million.

ASSET ACTIVITY

Average Daily Production⁽¹⁾

	Three months ended September 30, 2019					Nine months ended September 30, 2019
	Crude Oil (Mbbl/d)	Natural Gas Liquids (Mbbl/d)	Natural gas (MMcf/d)	Total Production (Mboe/d)		Crude Oil (Mbbl/d)	Natural Gas Liquids (Mbbl/d)	Natural gas (MMcf/d)	Total Production (Mboe/d)
Williston Basin	45.7	4.2	29.1	54.8		38.7	3.8	27.0	46.9
Marcellus	-	-	227.6	37.9		-	-	224.7	37.4
Canadian Waterfloods	8.4	0.1	3.8	9.2		8.6	0.1	3.6	9.3
Other^(2)	0.8	0.8	21.9	5.3		0.9	0.9	20.8	5.3
Total	55.0	5.1	282.4	107.2		48.1	4.7	276.1	98.9

(1)	Table may not add due to rounding.
(2)	Comprises DJ Basin and non-core properties in Canada.

Summary of Wells Drilled⁽¹⁾

	Three months ended September 30, 2019						Nine months ended  September 30, 2019
	Operated			Non-Operated			Operated			Non-Operated
	Gross	Net		Gross	Net		Gross	Net		Gross	Net
Williston Basin	17	14.9		4	1.6		43	37.2		7	2.7
Marcellus	-	-		6	0.4		-	-		23	0.9
Canadian Waterfloods	-	-		-	-		1	1.0		-	-
Other^(2)	-	-		-	-		5	4.4		2	0.5
Total	17	14.9		10	2.0		49	42.6		32	4.1

(1)	Table may not add due to rounding.
(2)	Comprises DJ Basin and non-core properties in Canada.

Summary of Wells Brought On-Stream⁽¹⁾

	Three months ended September 30, 2019						Nine months ended  September 30, 2019
	Operated			Non-Operated			Operated			Non-Operated
	Gross	Net		Gross	Net		Gross	Net		Gross	Net
Williston Basin	11	8.0		1	0.1		40	34.3		5	2.0
Marcellus	-	-		13	0.9		-	-		40	4.3
Canadian Waterfloods	-	-		-	-		1	1.0		-	-
Other^(2)	5	4.4		-	-		5	4.4		2	0.5
Total	16	12.4		14	0.9		46	39.7		47	6.8

(1)	Table may not add due to rounding.
(2)	Comprises DJ Basin and non-core properties in Canada.

Williston Basin
Williston Basin production averaged 54,800 BOE per day (83% oil) during the third quarter of 2019, including 51,646 BOE per day in North Dakota (84% oil), an increase of 18% from the prior quarter. The Company drilled 17 gross operated wells (88% average working interest) and brought 11 gross operated wells (72% average working interest) on production during the third quarter.

Marcellus
Marcellus production averaged 228 MMcf per day during the third quarter, down 2% from the previous quarter. The Company participated in drilling six gross non-operated wells (6% average working interest) and brought 13 gross non-operated wells (7% average working interest) on production during the quarter.

DJ Basin
Enerplus brought five gross operated wells (88% average working interest) on production in the third quarter in the DJ Basin. The Company continued to vary its completion design on these wells utilizing both higher and lower proppant and fluid intensities, aiming to further understand the associated well performance and cost structures. Enerplus is encouraged by the early stage production performance of the wells which are in line with the Company's expectations.

2019 GUIDANCE

The Company's updated guidance, with changes noted, is provided in the table below.

2019 Guidance
Capital spending	$625 million (from $610 to $630 million)
Average annual production	100,000 to 101,000 BOE/day (from 99,000 to 102,000 BOE/day)
Average annual crude oil and natural gas liquids production	54,250 to 54,750 bbls/day (from 54,000 to 55,500 bbls/d)
Q4 average production	103,000 to 107,000 BOE/day
Q4 average crude oil and natural gas liquids production	58,000 to 60,000 bbls/d
Average royalty and production tax rate	25%
Operating expense	$7.90/BOE
Transportation expense	$4.00/BOE
Cash G&A expense	$1.40/BOE (from $1.45/BOE)

2019 Full-Year Differential/Basis Outlook^(1)
U.S. Bakken crude oil differential (compared to WTI crude oil)	US$(3.60)/bbl (from US$(3.25)/bbl)
Marcellus natural gas sales price differential (compared to NYMEX natural gas)	US$(0.35)/Mcf

(1)	Excluding transportation costs.

PRICE RISK MANAGEMENT

Enerplus continues to manage price risk through commodity hedging. Enerplus has an average of 24,500 barrels per day of crude oil protected for the remainder of 2019 and 16,000 barrels per day protected in 2020.

For natural gas, Enerplus has entered into offsetting swaps through October 31, 2019, effectively locking in gains of US$0.51 per Mcf on the Company's original NYMEX hedges through this term.

Commodity Hedging Detail (As at November 6, 2019)

	WTI Crude Oil (US$/bbl)^(1)		NYMEX Natural Gas (US$/Mcf)
	Oct 1 – Dec 31, 2019	Jan 1 – Dec 31, 2020	Oct 1 – Oct 31, 2019
Swaps
Sold Swaps	-	-	$2.85
Volume (bbls/d or Mcf/d)	-	-	90,000
Purchased Swaps	-	-	$2.34
Volume (bbls/d or Mcf/d)	-	-	90,000
Three-Way Collars
Sold Puts	$44.64	-	-
Volume (bbls/d or Mcf/d)	24,500	-	-
Purchased Puts	$54.81	-	-
Volume (bbls/d or Mcf/d)	24,500	-	-
Sold Calls	$65.99	-	-
Volume (bbls/d or Mcf/d)	24,500	-	-
Put Spreads
Sold Puts	-	$46.88	-
Volume (bbls/d or Mcf/d)	-	16,000	-
Purchased Puts	-	$57.50	-
Volume (bbls/d or Mcf/d)	-	16,000	-

(1)	The total average deferred premium on outstanding hedges is US$2.14/bbl from October 1, 2019 to December 31, 2020.

Q3 2019 CONFERENCE CALL DETAILS

A conference call hosted by Ian C. Dundas, President and CEO will be held at 9:00 AM MT (11:00 AM ET) today to discuss these results. Details of the conference call are as follows:

Date:	Friday, November 8, 2019
Time:	9:00 AM MT (11:00 AM ET)
Dial-In:	587-880-2171 (Alberta)
	1-888-390-0546 (Toll Free)
Conference ID:	30294000
Audiocast:	https://event.on24.com/wcc/r/2100379/B276E7CC02EFC7703F1C9F77C135DD36

To ensure timely participation in the conference call, callers are encouraged to dial in 15 minutes prior to the start time to register for the event. A telephone replay will be available for 30 days following the conference call and can be accessed at the following numbers:

Replay Dial-In:	1-888-390-0541 (Toll Free)
Replay Passcode:	294000 #

SELECTED FINANCIAL AND OPERATING RESULTS

SELECTED FINANCIAL RESULTS		Three months ended September 30,						Nine months ended September 30,
		2019			2018			2019			2018
Financial (000's)
Net Income		$	65,181		$	86,923		$	169,423		$	128,964
Cash Flow from Operating Activities			159,806			216,098			505,748			517,165
Adjusted Funds Flow^(4)			175,277			210,351			530,070			539,221
Dividends to Shareholders - Declared			6,836			7,355			21,032			22,022
Total Debt Net of Cash^(4)			521,379			313,591			521,379			313,591
Capital Spending			151,520			193,264			519,521			521,818
Property and Land Acquisitions			13,344			1,702			18,280			16,366
Property Divestments			(168)			(762)			9,899			6,026
Net Debt to Adjusted Funds Flow Ratio^(4)			0.7x			0.4x			0.7x			0.4x
Financial per Weighted Average Shares Outstanding
Net Income - Basic		$	0.28		$	0.35		$	0.72		$	0.53
Net Income - Diluted			0.28			0.35			0.71			0.52
Weighted Average Number of Shares Outstanding (000's) - Basic			228,908			245,235			234,403			244,659
Weighted Average Number of Shares Outstanding (000's) - Diluted			231,529			250,957			237,399			250,048
Selected Financial Results per BOE^(1)(2)
Oil & Natural Gas Sales^(3)		$	40.75		$	52.32		$	43.02		$	48.03
Royalties and Production Taxes			(10.80)			(13.39)			(10.86)			(12.03)
Commodity Derivative Instruments			0.53			(2.68)			0.54			(1.32)
Cash Operating Expenses			(7.06)			(6.80)			(7.83)			(7.01)
Transportation Costs			(3.96)			(3.70)			(3.97)			(3.60)
Cash General and Administrative Expenses			(1.19)			(1.35)			(1.32)			(1.49)
Cash Share-Based Compensation			—			0.02			(0.02)			(0.09)
Interest, Foreign Exchange and Other Expenses			(0.49)			(0.81)			(0.65)			(0.94)
Current Income Tax Recovery/(Expense)			—			(0.01)			0.72			(0.01)
Adjusted Funds Flow^(4)		$	17.78		$	23.60		$	19.63		$	21.54

SELECTED OPERATING RESULTS		Three months ended September 30,						Nine months ended September 30,
		2019			2018			2019			2018
Average Daily Production^(2)
Crude Oil (bbls/day)			55,023			48,867			48,141			43,892
Natural Gas Liquids (bbls/day)			5,098			4,563			4,736			4,487
Natural Gas (Mcf/day)			282,360			260,591			276,063			259,629
Total (BOE/day)			107,181			96,861			98,888			91,651
% Crude Oil and Natural Gas Liquids			56%			55%			53%			53%
Average Selling Price ^(2)(3)
Crude Oil (per bbl)		$	67.76		$	83.98		$	69.64		$	78.58
Natural Gas Liquids (per bbl)			5.97			25.95			13.97			28.85
Natural Gas (per Mcf)			2.13			3.22			3.00			3.14
Net Wells Drilled			17			17			47			49

(1)	Non-cash amounts have been excluded.
(2)	Based on Company interest production volumes. See "Presentation of Production Information" below.
(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 this news release.

		Three months ended September 30,						Nine months ended September 30,
Average Benchmark Pricing		2019			2018			2019			2018
WTI crude oil (US$/bbl)		$	56.45		$	69.50		$	57.06		$	66.75
Brent (ICE) crude oil (US$/bbl)			62.00			75.97			64.74			72.68
NYMEX natural gas – last day (US$/Mcf)			2.23			2.90			2.67			2.90
USD/CDN average exchange rate			1.32			1.31			1.33			1.29

Share Trading Summary		CDN^(1) - ERF			U.S.^(2) - ERF
For the three months ended September 30, 2019		(CDN$)			(US$)
High		$	11.16		$	8.43
Low		$	7.32		$	5.50
Close		$	9.87		$	7.44

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

2019 Dividends per Share		CDN$			US$^(1)
First Quarter Total		$	0.03		$	0.02
Second Quarter Total			0.03		$	0.02
Third Quarter Total			0.03			0.02
Total Year to Date		$	0.09		$	0.06

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

Currency and Accounting Principles
All amounts in this news release are stated in Canadian dollars unless otherwise specified. All financial information in this news release has been prepared and presented in accordance with U.S. GAAP, except as noted below under "Non-GAAP Measures".

Barrels of Oil Equivalent
This news release also contains references to "BOE" (barrels of oil equivalent). Enerplus has adopted the standard of six thousand cubic feet of natural gas to one barrel of oil (6 Mcf: 1 bbl) when converting natural gas to BOEs. BOEs may be misleading, particularly if used in isolation. The foregoing conversion ratios are based on an energy equivalency conversion method primarily applicable at the burner tip and do not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading.

Presentation of Production Information
Under U.S. GAAP oil and gas sales are generally presented net of royalties and U.S. industry protocol is to present production volumes net of royalties. Under Canadian industry protocol oil and gas sales and production volumes are presented on a gross basis before deduction of royalties. To continue to be comparable with its Canadian peer companies, the summary results contained within this news release presents Enerplus' production and BOE measures on a before royalty company interest basis. All production volumes and revenues presented herein are reported on a "company interest" basis, before deduction of Crown and other royalties, plus Enerplus' royalty interest.  

FORWARD-LOOKING INFORMATION AND STATEMENTS

This news release 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 news release contains forward-looking information pertaining to the following: expected fourth quarter and 2019 average production volumes, timing thereof and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting our adjusted funds flow; the results from our drilling program and the timing of related production; oil and natural gas prices and differentials and our commodity risk management program in 2019 and in the future; expectations regarding our realized oil and natural gas prices; future royalty rates on our production and future production taxes; anticipated cash G&A, share-based compensation and financing expenses; expected operating and transportation costs; our anticipated shares repurchases under current and future normal course issuer bids; capital spending levels in 2019 and impact thereof on our production levels and land holdings; 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; 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; our future acquisitions and dispositions, expecting timing thereof and use of proceeds therefrom; and the amount of future cash dividends that we may pay to our shareholders.

The forward-looking information contained in this news release reflects several material factors and expectations and assumptions of Enerplus including, without limitation: that we will conduct our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; that lack of adequate infrastructure will not result in curtailment of production and/or reduced realized prices beyond our current expectations; current commodity price, differentials and cost assumptions; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve and contingent resource volumes; the continued availability of adequate debt and/or equity financing and adjusted funds flow to fund our capital, operating and working capital requirements, and dividend payments as needed; the continued availability and sufficiency of our adjusted funds flow and availability under our bank credit facility to fund our working capital deficiency; the availability of third party services; and the extent of our liabilities. In addition, our updated 2019 guidance contained in this news release is based on the rest of the year prices of: a WTI price of US$54.00/bbl, a NYMEX price of US$2.40/Mcf, and a USD/CDN exchange rate of 1.32. Enerplus believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct

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

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

NON-GAAP MEASURES

In this news release, we use the terms "adjusted funds flow", "adjusted net income", "net debt to adjusted funds flow ratio" and "total debt net of cash" as measures to analyze operating performance, leverage and liquidity. "Adjusted funds flow" is calculated as cash flow generated from operating activities but before changes in non-cash operating working capital and asset retirement obligation expenditures. "Adjusted net income" is calculated as net income adjusted for unrealized derivative instrument gain/loss, unrealized foreign exchange gain/loss, the tax effect of these items and the impact of statutory changes to the Company's corporate tax rate. "Net debt to adjusted funds flow ratio" is calculated as total debt net of cash and cash equivalents, divided by a trailing 12 months of adjusted funds flow. "Total debt net of cash" is calculated as senior notes plus any outstanding bank credit facility balance, minus cash and cash equivalents. Calculation of these terms is described in Enerplus' MD&A under the "Non-GAAP Measures" section.

Enerplus believes that, in addition to net earnings and other measures prescribed by U.S. GAAP, the terms "adjusted funds flow", "adjusted net income", "net debt to adjusted funds flow", and "total debt net of cash" are useful supplemental measures as they provide an indication of the results generated by Enerplus' principal business activities. However, these measures are not measures recognized by U.S. GAAP and do not have a standardized meaning prescribed by U.S. GAAP. Therefore, these measures, as defined by Enerplus, may not be comparable to similar measures presented by other issuers. For reconciliation of these measures to the most directly comparable measure calculated in accordance with U.S. GAAP, and further information about these measures, see disclosure under "Non-GAAP Measures" in Enerplus' Third Quarter 2019 MD&A.

Electronic copies of Enerplus Corporation's Third Quarter 2019 MD&A and Financial Statements, along with other public information including investor presentations, are available on its website at www.enerplus.com. Shareholders may, upon request, receive a printed copy of the Company's audited financial statements at any time. For further information, please contact Investor Relations at 1-800-319-6462 or email [email protected].

Follow @EnerplusCorp on Twitter at https://twitter.com/EnerplusCorp.

Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation

SOURCE Enerplus Corporation

ENERPLUS CORPORATION, The Dome Tower, Suite 3000, 333 - 7th Avenue SW, Calgary, Alberta T2P 2Z1, T. 403-298-2200 F. 403-298-2211, www.enerplus.com

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