Enerplus Announces Fourth Quarter Update, 2019 Budget and Three-Year Outlook

CALGARY, Jan. 25, 2019 /CNW/ - Enerplus Corporation ("Enerplus" or the "Company") (TSX & NYSE: ERF) today announced fourth quarter 2018 production at the high-end of its guidance range, its 2019 exploration and development capital budget of $565 to $635 million and a three-year outlook through 2021.

"We're focused on maximizing returns, driving profitable growth and positioning our business for strong free cash flow generation," stated Ian C. Dundas, President and Chief Executive Officer. "Our 2019 plan is expected to generate double-digit returns on capital employed and competitive oil production per share growth while operating within cash flow based on prevailing commodity prices. Importantly, if we see commodity prices improve, we would expect to generate meaningful free cash flow."

Dundas continued, "We also remain committed to returning capital to shareholders. We returned over $100 million to shareholders in 2018 through dividends and share repurchases and we believe continuing to repurchase our shares represents a compelling capital allocation opportunity."  

Fourth Quarter 2018 Update

• Achieved the high-end of fourth quarter and 2018 annual production guidance
• Fourth quarter production of approximately 97,800 BOE per day, including liquids of 54,400 barrels per day
• 2018 annual production of approximately 93,200 BOE per day, including liquids of 49,900 barrels per day
  
  
• Capital spending in the fourth quarter was $72.1 million, resulting in full year 2018 capital spending of $593.9 million, in line with the Company's guidance of $585 million
  
  
• Repurchased 5.4 million shares in the fourth quarter for $70.5 million, bringing total repurchases in 2018 to $79.0 million (5.9 million shares), further enhancing per share growth and return of capital to shareholders

Highlights of the 2019 Budget and Three-Year Outlook

• Three-year outlook through 2021 focused on maximizing financial returns, competitive oil growth and enhancing free cash flow generation
• Second-half weighted growth profile in 2019 with annual liquids production growth of approximately 9% at the mid-point of guidance (11% liquids production per share growth)
• Approximately 10% to 13% annual liquids production growth in 2020 and 2021
• Over the three-year period capital spending is expected to be balanced with adjusted funds flow at US$50 per barrel WTI and US$3 per Mcf NYMEX, with free cash flow at prices above these levels
  
  
• 2019 capital budget of $565 to $635 million
• Capital spending plan based on a US$50 to US$55 per barrel WTI oil price environment
• Capital spending and adjusted funds flow balanced at US$50 per barrel WTI and US$3 per Mcf NYMEX with significant free cash flow anticipated in a rising oil price environment
  
  
• 2019 production guidance of 94,000 to 100,000 BOE per day, including 52,500 to 56,000 barrels per day of liquids
  
  
• Expect to continue repurchasing shares in 2019
  
  
• Price protection on more than 60% of 2019 forecast net oil production, hedged largely through three-way collar structures with average purchased put options at US$55 per barrel WTI and average upside participation to US$65 per barrel WTI
  
  
• Net debt to adjusted funds flow ratio expected to remain below 0.6 times in 2019 based on US$50 per barrel WTI

2019 Operating Plan

Enerplus has allocated 80% of its 2019 capital budget to its North Dakota development to fund a 42 net well drilling program with 30 to 38 net operated completions.

Enerplus plans to spend 7.5% of its 2019 capital budget across its Canadian operations. Capital activity includes drilling approximately four net producer/injector wells, along with ongoing polymer injection for existing projects, and facilities maintenance and optimization.

Enerplus plans to spend 7.5% of its 2019 capital budget in the Marcellus to drill one net well and bring five net wells on production.

In the DJ Basin Enerplus plans to continue delineation drilling and progressing midstream options under a measured capital program. The Company plans to spend 5% of its 2019 capital budget in the DJ Basin on infrastructure and to drill and complete five gross (four net) wells.

The Company's $565 to $635 million capital budget includes an allocation for non-drilling/completion capital, primarily related to infrastructure in the DJ Basin, maintenance and optimization spending, and capitalized G&A expenses. The allocation across assets is shown in the table below.

Approximate Capital Allocation	2019 Budget
North Dakota	80.0%
Canada	7.5%
Marcellus	7.5%
DJ Basin	5.0%
Total	100%

2019 Guidance

The Company expects to deliver average 2019 production of between 94,000 to 100,000 BOE per day, with crude oil and natural gas liquids production expected to average between 52,500 to 56,000 barrels per day.

As a result of the 2018 investment profile with only modest fourth quarter capital activity, combined with the Company's decision to slow completions activity early in 2019 due to the significant oil price volatility, production in the first quarter of 2019 is expected to decline from the fourth quarter of 2018. Following this, production is expected to meaningfully increase with strong growth forecast for the second half of 2019.

The Company's realized Bakken crude oil price differential below WTI is projected to be US$4.00 per barrel in 2019. This includes the impact of Enerplus' 16,000 barrels per day of fixed physical differential sales at approximately US$3.00 per barrel below WTI. For the Marcellus, the Company expects robust natural gas price realizations during the first quarter of 2019 due to the seasonality of some of its market exposure, with realizations moderating during the remainder of the year. Enerplus expects its realized Marcellus natural gas price differential below NYMEX to average US$0.30 per Mcf in 2019.

Operating expenses in 2019 are forecast to be higher than 2018 levels as a result of the higher liquids weighting in the Company's 2019 production mix, combined with increased use of electronic submersible pumps in North Dakota. Operating expenses are expected to average $8.00 per BOE in 2019.

Transportation expenses are expected to average $4.00 per BOE in 2019, modestly higher year-over-year due to additional transportation commitments that provide access to higher crude oil prices.

A summary of Enerplus' 2019 guidance is provided below.

2019 Guidance
Capital spending		$565 to $635 million
Average annual production		94,000 – 100,000 BOE/d
Average annual crude oil and natural gas liquids production		52,500 – 56,000 bbl/d
Average royalty and production tax rate		25%
Operating expense		$8.00/BOE
Transportation expense		$4.00/BOE
Cash G&A expense		$1.50/BOE
2019 Differential/Basis Outlook^(1)
U.S. Bakken crude oil differential (compared to WTI crude oil)		US$(4.00)/bbl
Marcellus basis (compared to NYMEX natural gas)		US$(0.30)/Mcf

(1)   Excluding transportation costs

Three-Year Outlook

With second-half weighted production growth in 2019, Enerplus expects to deliver approximately 9% annual liquids production growth at the midpoint of its guidance range. Thereafter in 2020 and 2021, Enerplus expects to grow its liquids production by 10% to 13% per year. This growth outlook is underpinned by the Company's high-return, light oil asset in North Dakota. Over the three-year period, capital spending is expected to be balanced with adjusted funds flow at approximately US$50 per barrel WTI and US$3 per Mcf NYMEX natural gas, with free cash flow at prices above these levels.

Share Repurchase Update

During the fourth quarter of 2018, Enerplus repurchased 5,380,784 common shares under its Normal Course Issuer Bid at an average share price of $13.10. In total during 2018 Enerplus repurchased 5,925,084 common shares at an average share price of $13.33 at a cost of $79.0 million. When combined with dividends, Enerplus returned over $100 million to shareholders in 2018.

Risk Management Update

Using swaps and collar structures, Enerplus has an average of 23,100 barrels per day of crude oil protected in 2019 (approximately 63% of net production at guidance midpoint). Enerplus added additional natural gas hedges in 2019 and now has an average of 65,700 Mcf per day protected in 2019 (approximately 34% of net production at guidance midpoint).

Commodity Hedging Detail (As at January 24, 2019)

	WTI Crude Oil (US$/bbl)^(1)					Nymex Natural Gas (US$/Mcf)^(1)
	Jan 1 – Mar 31, 2019	Apr 1 – Jun 30, 2019	Jul 1, – Sep 30, 2019	Oct 1, –  Dec 31, 2019	Jan 1, – Dec 31, 2020	Jan 1, – Mar 31, 2019	Apr 1, – Oct 31, 2019
Swaps
Sold Swaps	$53.73	-	-	-	-	$4.23	$2.85
Volume (bbls/d or Mcf/d)	3,000	-	-	-	-	50,000	70,000
Collars
Sold Puts	$44.28	$44.50	$44.64	$44.64	$46.88	-	-
Volume (bbls/d or Mcf/d)	17,000	23,500	24,500	24,500	16,000	-	-
Purchased Puts	$54.12	$54.59	$54.81	$54.81	$57.50	$3.80	-
Volume (bbls/d or Mcf/d)	17,000	23,500	24,500	24,500	16,000	50,000	-
Sold Calls	$64.12	$65.52	$65.95	$65.99	$72.50	$6.01	-
Volume (bbls/d or Mcf/d)	17,000	23,500	24,500	24,500	16,000	50,000	-

(1)	Based on weighted average price (before premiums).
(2)	The total average deferred premium spent on the three-way collars is US$1.61/bbl from January 1, 2019 to December 31, 2020.

Currency and Accounting Principles
All amounts in this news release are stated in Canadian dollars unless otherwise specified.

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 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. In order to continue to be comparable with its Canadian peer companies, unless otherwise stated, the information contained within this news release presents Enerplus' production and BOE measures on a before royalty company interest basis. All production volumes presented herein are reported on a "company interest" basis, before deduction of Crown and other royalties, plus Enerplus' royalty interest. This news release also contains references to the percentage of the Company's production that is hedged under commodity derivatives contracts, this percentage being based upon the Company's net of royalty production volumes.

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 2019 average production volumes, anticipated production growth through 2021, anticipated production mix and Enerplus' expected source of funding thereof; the proportion of Enerplus' anticipated oil and gas production that is hedged; our 2019 operating plans, including the results from our drilling program and the timing of related production; oil and natural gas prices and differentials and our commodity risk management programs; expected net debt to adjusted funds flow ratio in 2019; anticipated cash G&A, operating and transportation expenses; expected average royalty and production tax rate; expected capital spending levels in 2019 and in the future, its components and its impact on production; and expected share purchases in 2019 and sources of funding thereof. The purpose of our return on capital employed and other financial outlook contained in this press release is 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 news release reflects several material factors and expectations and assumptions of Enerplus including, without limitation: that Enerplus will conduct its operations and achieve results of operations as anticipated; that Enerplus' development plans will achieve the expected results; current commodity price 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 Enerplus' reserves and resources volumes; the continued availability of adequate debt and/or equity financing, cash flow and other sources to fund Enerplus' capital and operating requirements, and dividend payments as needed; availability of third party services; and the extent of its liabilities. In addition, Enerplus' 2019 guidance contained in this news release is based on the following: a WTI price of between US$50.00/bbl to US$55.00/bbl, a NYMEX price of US$3.00/Mcf, and a USD/CDN exchange rate of 1.32. In addition, Enerplus' three-year outlook contained in this news release is based on the following: a WTI price of between US$50.00/bbl to US$55.00/bbl, a NYMEX price of US$3.00/Mcf, Bakken oil price differential of US$4.00/bbl and a Marcellus natural gas price differential of US$0.30/Mcf. 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: changes, including future decline, in commodity prices; changes in realized prices for Enerplus' products; changes in the demand for or supply of Enerplus' products; unanticipated operating results, results from Enerplus' capital spending activities or production declines; curtailment of Enerplus' 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 development plans by Enerplus or by third party operators of Enerplus' properties; increased debt levels or debt service requirements; changes in estimates of Enerplus' oil and gas reserves and resources 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; failure to complete any anticipated acquisitions or divestitures; and certain other risks detailed from time to time in Enerplus' public disclosure documents (including, without limitation, those risks identified in its AIF, management's discussion and analysis ("MD&A"), and Form 40-F at December 31, 2017).

NON-GAAP MEASURES

In this news release, Enerplus uses the terms "adjusted funds flow", "free cash flow" and "net debt to adjusted funds flow" as measures to analyze operating performance, leverage and liquidity. "Adjusted funds flow" is calculated as net cash generated from operating activities but before changes in non-cash operating working capital and asset retirement obligation expenditures. "Free cash flow" is defined as "Adjusted funds flow less exploration and development capital spending".  "Net debt to adjusted funds flow ratio" is calculated as total debt net of cash, divided by a trailing 12 months of adjusted funds flow. Calculation of these terms is described in Enerplus' Third Quarter 2018 MD&A under the "Liquidity and Capital Resources" section.

Enerplus believes that, in addition to net earnings and other measures prescribed by U.S. GAAP, the terms "adjusted funds flow", "free cash flow" and "net debt to adjusted funds flow" 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 further information about these measures, see disclosure under "Non-GAAP Measures" in Enerplus' Third Quarter 2018 MD&A.

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

Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation

SOURCE Enerplus Corporation

please contact Investor Relations at 1-800-319-6462 or [email protected].

Related Links

http://www.enerplus.com