Enerplus Announces First Quarter 2018 Results

May 3, 2018

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' First Quarter 2018 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, May 3, 2018 /CNW/ - Enerplus Corporation ("Enerplus" or the "Company") (TSX & NYSE: ERF) is pleased to announce first quarter 2018 operating and financial results. The Company reported first quarter 2018 net income of $29.6 million or $0.12 per share.

HIGHLIGHTS

  • 2018 adjusted funds flow expected to exceed capital expenditures and dividends by approximately $100 million based on current forward strip pricing
  • Strong growth underway with second quarter liquids production expected to average between 48,000 to 50,000 barrels per day
  • Well positioned relative to 2018 production guidance including over 30% production growth in North Dakota year-over-year
  • First quarter 2018 adjusted funds flow of $155.2 million
  • Ended the first quarter of 2018 with a net debt to adjusted funds flow ratio of 0.5 times

"Our plans are well on track to continue to drive competitive, profitable growth while generating robust returns on capital," stated Ian C. Dundas, President and Chief Executive Officer. "With our continued margin expansion resulting from improved pricing realizations and reductions to our cost structure over the last year, we expect to generate meaningful free cash flow in 2018 under current strip prices. Additionally, we expect to deliver over 30% production growth from our high-returning North Dakota asset. Despite the improving crude oil price outlook, we remain committed to our disciplined approach to capital allocation focused on generating full-cycle returns and creating long-term value for our shareholders."

FIRST QUARTER FINANCIAL AND OPERATIONAL SUMMARY

Production
Production in the first quarter of 2018 averaged 85,080 BOE per day, including 41,528 barrels per day of crude oil (90%) and natural gas liquids (10%). As forecast, liquids production was lower compared to the prior quarter primarily due to downtime related to completions activity on adjacent properties and on-stream activity in North Dakota weighted to the back half of the first quarter.

Natural gas production for the first quarter averaged 261 MMcf per day, a 4% increase from the prior quarter primarily due to higher Marcellus production supported by stronger natural gas pricing.

The Company remains well positioned relative to its 2018 production guidance with strong growth underway in the second quarter. Four wells from a high-working interest six-well pad in North Dakota began flowing back at strong initial rates in late April, with the two remaining wells expected on-stream in early May. Based on field estimates, current liquids production is averaging approximately 49,000 barrels per day. Enerplus is expecting second quarter liquids production to average 48,000 to 50,000 barrels per day.

Net Income, Adjusted Funds Flow and Netback
Enerplus generated net income of $29.6 million in the first quarter of 2018, an increase from $15.3 million in the previous quarter as a result of lower non-cash income tax expense in the first quarter.

Adjusted funds flow was $155.2 million during the first quarter, compared to $199.6 million in the previous quarter which included $50.1 million related to the U.S. Alternative Minimum Tax refund. Adjusted funds flow remained strong in the first quarter supported by higher benchmark oil and natural gas prices and a hedging gain related to the unwinding of a portion of the Company's AECO - NYMEX basis contracts.

Enerplus' netback, before commodity hedging, was $21.97 per BOE in the first quarter of 2018. This represents a 2% increase from the prior quarter and a 22% increase from the same period in 2017.

Pricing Realizations and Cost Structure
Enerplus' realized Bakken crude oil price differential averaged US$3.27 per barrel below WTI in the first quarter, weaker than the previous quarter's differential of US$1.61 per barrel largely driven by the 13% increase in average benchmark WTI oil prices quarter-over-quarter. As a result of the recent strength in WTI oil prices and with the current 2018 forward strip at approximately US$65 per barrel, Enerplus is increasing its estimated 2018 average Bakken crude oil price differential to US$3.50 per barrel below WTI, from US$2.50 per barrel below WTI previously.

Enerplus' realized Marcellus natural gas price differential strengthened considerably to US$0.21 per Mcf below NYMEX in the first quarter, an improvement of US$0.60 per Mcf from the prior quarter. This pricing improvement was due to the continued build-out of regional pipeline takeaway capacity as well as the effect of a colder than normal winter, which resulted in price spikes in key consumption regions in the U.S.  Enerplus expects its Marcellus differential to increase during the remainder of 2018 as a portion of its sales portfolio is linked to New York markets that are typically weaker during the summer months. Enerplus continues to project an average 2018 differential of US$0.40 per Mcf below NYMEX.

First quarter operating, transportation, and cash general and administrative ("G&A") expenses were all largely in-line with the Company's annual 2018 guidance. First quarter operating expenses averaged $7.02 per BOE, transportation costs averaged $3.52 per BOE, and cash G&A expenses averaged $1.72 per BOE. Enerplus' 2018 guidance for these items remains unchanged.

Capital Expenditures and Balance Sheet Position
Exploration and development capital spending in the first quarter was $151.5 million associated with drilling 13.9 net wells and completing and bringing on production 8.9 net wells across the Company. Enerplus' 2018 capital spending guidance of $535 million to $585 million is unchanged.

Enerplus remains in a strong financial position. Total debt net of cash at March 31, 2018 was $292 million. Total debt was comprised of $688.4 million of senior notes outstanding. The Company was undrawn on its $800 million bank credit facility, and had a cash balance of $396.4 million. At March 31, 2018, Enerplus' net debt to adjusted funds flow ratio was 0.5 times.

AVERAGE DAILY PRODUCTION(1)


Three months ended March 31, 2018


Crude Oil

(Mbbl/d)

Natural
Gas Liquids

(Mbbl/d)

Natural gas

(MMcf/d)

Total
Production

(Mboe/d)

Williston Basin

27.7

2.8

19.8

33.8

Marcellus

0.0

0.0

208.4

34.7

Canadian Waterfloods

9.4

0.1

5.0

10.3

Other(2)

0.4

1.1

28.2

6.2

Total

37.4

4.1

261.3

85.1

(1)

Table may not add due to rounding.

(2)

Includes approximately 600 boe/d of production from Canadian natural gas properties sold in Q1 2018

 

SUMMARY OF WELLS BROUGHT ON-STREAM(1)


Three months ended March 31, 2018


Operated


Non-Operated


Gross

Net


Gross

Net

Williston Basin

8

5.2


0

0.0

Marcellus

0

0.0


11

1.5

Canadian Waterfloods

2

1.9


0

0.0

Other

0

0.0


1

0.3

Total

10

7.1


12

1.8

(1)     Table may not add due to rounding.

 

ASSET ACTIVITY

Williston Basin
Williston Basin production averaged 33,836 BOE per day (82% oil) during the first quarter of 2018, down 14% from the fourth quarter of 2017. This decrease was expected due to downtime related to offset completions and on-stream activity in North Dakota weighted to the back half of the first quarter. First quarter Williston Basin production was comprised of 30,372 BOE per day in North Dakota and 3,464 BOE per day in Montana. 

Enerplus brought on-stream eight gross operated wells (65% average working interest) across its acreage at Fort Berthold during the first quarter. The average completed lateral length was 9,000 feet per well and average peak 30-day production rates per well were 1,360 BOE per day (77% oil, on a three-stream basis).

The Company drilled nine gross operated wells (96% average working interest) in the first quarter.

In late April, the Company completed and brought on production four of six planned wells from its Cats pad (91% average working interest). The wells are currently flowing back at strong rates which are tracking the high end of the Company's expectations. The remaining two wells are expected to be on-stream in early May.

The Company continues to run two operated drilling rigs and one dedicated completions crew at its Fort Berthold operations.

Marcellus
Marcellus production averaged 208 MMcf per day during the first quarter, an increase from the previous quarter of 8% primarily due to stronger production driven by improved natural gas pricing.

Eleven gross non-operated wells (14% average working interest) were brought on-stream during the quarter. Nine wells had more than 30 days on production as of the date of this news release with an average completed lateral length of 6,340 feet per well and average peak 30-day production rates per well of 14 MMcf per day.

The Company participated in drilling 13 gross non-operated wells (20% average working interest) during the first quarter.

Canadian Waterfloods
Canadian waterflood production averaged 10,336 BOE per day (91% oil) during the first quarter, relatively flat to the previous quarter. Enerplus drilled and brought on-stream two wells in southeast Saskatchewan with average peak 30-day production rates per well of 235 barrels of oil per day, exceeding the Company's expectations. At Ante Creek, the construction of two injection pipelines was completed along with two producer-to-injector well conversions. The increased water injection at Ante Creek has helped stabilize decline with oil production remaining relatively flat compared to the fourth quarter. Ante Creek oil volumes are expected to gradually increase during the second half of 2018.

DJ Basin
Enerplus' first DJ Basin well (Maple 8-67-36-5C) has produced over 85,000 BOE (79% oil) in just over seven months on production. In April, the well averaged approximately 400 BOE per day (73% oil). The Company is continuing delineation activity to test the extent of commerciality across its acreage position with four gross (3.5 net) wells in 2018 testing both the Codell and Niobrara intervals.

2018 GUIDANCE

Enerplus' 2018 guidance is summarized below. The Company has included second quarter 2018 liquids production guidance and revised its estimated 2018 Bakken crude oil price differential to US$3.50 per barrel below WTI from US$2.50 per barrel below WTI previously. All other guidance targets are unchanged.




Guidance

Capital spending

$535 - $585 million

Q2 2018 crude oil and natural gas liquids production

48,000 to 50,000 bbls/day

Average annual production

86,000 to 91,000 BOE/day

Average annual crude oil and natural gas liquids production

46,000 to 50,000 bbls/day

Average royalty and production tax rate

25%

Operating expense

$7.00/BOE

Transportation expense

$3.60/BOE

Cash G&A expense

$1.65/BOE



2018 Full-Year Differential/Basis Outlook (1)


U.S. Bakken crude oil differential (compared to WTI crude oil):

US$(3.50)/bbl (from US$(2.50)/bbl)

Marcellus natural gas sales price differential (compared to NYMEX natural gas):

US$(0.40)/Mcf

(1)     Excluding transportation costs.

 

RISK MANAGEMENT

Enerplus continues to manage price risk through commodity hedging. Using swaps and collar structures, Enerplus has an average of 21,500 barrels per day of crude oil protected for the remainder of 2018 (approximately 67% of forecast crude oil production at the midpoint of guidance, net of royalties), 21,300 barrels per day protected in 2019, and 6,000 barrels per day of crude oil protected in 2020.

For natural gas, Enerplus has 37,800 Mcf per day protected for the remainder of 2018 (approximately 21% of forecast natural gas production at the midpoint of guidance, net of royalties) using collar structures.

Commodity Hedging Detail (As at May 2, 2018)





WTI Crude Oil
(US$/bbl) (1)

Nymex Natural Gas
(US$/Mcf)
(1)


Apr 1, –

Apr 30,
2018

May 1 –
Jun 30,
2018

Jul 1 –
Sep 30,
2018

Oct 1 –
Dec 31,
2018

Jan 1, –
Mar 31,
2019

Apr 1, – 
Dec 31,
2019

Jan 1, –
Dec 31,
2020

Apr 1, –

Oct 31,

2018

Nov 1, –

Dec 31,

2018











Swaps










Sold Swaps

$55.38

$57.20

$53.73

$53.73

$53.73

-

-

-

-

Volume (bbls/d or Mcf/d)

5,000

6,000

3,000

3,000

3,000

-

-

-

-











Three-Way Collars










Sold Puts

$42.92

$42.92

$42.71

$42.74

$44.05

$44.26

$46.67

-

-

Volume (bbls/d or Mcf/d)

15,000

15,000

18,000

20,000

16,000

22,000

6,000

-

-











Purchased Puts

$52.90

$52.90

$52.53

$52.48

$53.69

$54.17

$56.00

$2.75

$2.75

Volume (bbls/d or Mcf/d)

15,000

15,000

18,000

20,000

16,000

22,000

6,000

40,000

30,000











Sold Calls

$61.73

$61.73

$61.22

$61.10

$63.44

$64.83

$70.33

$3.38

$3.47

Volume (bbls/d or Mcf/d)

15,000

15,000

18,000

20,000

16,000

22,000

6,000

40,000

30,000

(1)   Based on weighted average price (before premiums)

 

BOARD OF DIRECTOR RETIREMENT

As previously announced, Mr. David Barr will be retiring from the Board at the Annual Meeting being held later today. Mr. Barr has been a valued member of the Board of Directors since his appointment in 2011. Enerplus would like to acknowledge and thank him for his contribution and dedicated service.

Q1 2018 CONFERENCE CALL DETAILS

A conference call hosted by Ian C. Dundas, President and CEO will be held at 7:30 AM MT (9:30 AM ET) today to discuss these results. Details of the conference call are as follows:

Date:

Thursday, May 3, 2018

Time:

7:30 AM MT (9:30 AM ET)

Dial-In:

647-427-7450


1-888-231-8191 (toll free)

Audiocast:   

https://event.on24.com/wcc/r/1651698/8A98B2F74E8F567D4C28F7EFF7E44424

 

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:

Dial-In:

416-849-0833


1-855-859-2056 (toll free)

Passcode:

8267908

 

SELECTED FINANCIAL AND OPERATING RESULTS








Three months ended
March 31, 


2018


2017

Financial (000's)






Net Income/(Loss)

$

29,637


$

76,293

Adjusted Funds Flow(4)


155,162



119,920

Dividends to Shareholders - Declared


7,320



7,242

Debt Outstanding – net of Cash and Restricted Cash


291,978



350,401

Capital Spending


151,472



120,351

Property and Land Acquisitions


12,272



2,536

Property Divestments


6,970



(899)

Net Debt to Adjusted Funds Flow Ratio(4)


0.5x



0.9x







Financial per Weighted Average Shares Outstanding






Net Income - Basic

$

0.12


$

0.32

Net Income - Diluted


0.12



0.31

Weighted Average Number of Shares Outstanding (000's)


243,874



241,285







Selected Financial Results per BOE(1)(2)






Oil & Natural Gas Sales(3)

$

42.91


$

36.33

Royalties and Production Taxes


(10.41)



(7.89)

Commodity Derivative Instruments


1.33



0.86

Cash Operating Expenses


(7.02)



(6.57)

Transportation Costs


(3.52)



(3.88)

General and Administrative Expenses


(1.72)



(1.87)

Cash Share-Based Compensation


(0.25)



(0.02)

Interest, Foreign Exchange and Other Expenses


(1.05)



(1.26)

Current Income Tax Recovery/(Expense)


(0.01)



(0.01)

Adjusted Funds Flow(4)

$

20.26


$

15.69

 


Three months ended
March 31, 


2018


2017

Average Daily Production(2)






Crude Oil (bbls/day)


37,443



33,178

Natural Gas Liquids (bbls/day)


4,085



3,158

Natural Gas (Mcf/day)


261,310



291,607

Total (BOE/day)


85,080



84,937







% Crude Oil and Natural Gas Liquids


49%



43%







Average Selling Price (2)(3)






Crude Oil (per bbl)

$

69.67


$

57.53

Natural Gas Liquids (per bbl)


28.13



37.76

Natural Gas (per Mcf)


3.50



3.63







Net Wells Drilled


14



15

(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
March 31, 

Average Benchmark Pricing

2018


2017

WTI crude oil (US$/bbl)

$

62.87


$

51.92

AECO natural gas– monthly index (CDN$/Mcf)


1.85



2.94

AECO natural gas – daily index (CDN$/Mcf)


2.08



2.69

NYMEX natural gas – last day (US$/Mcf)


3.00



3.32

USD/CDN average exchange rate


1.26



1.32







Share Trading Summary

CDN(1) - ERF


U.S.(2) - ERF

For the three months ended March 31, 2018

(CDN$)


(US$)

High

$

15.90


$

12.26

Low

$

12.18


$

9.66

Close

$

14.49


$

11.26

(1)  TSX and other Canadian trading data combined.






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












2018 Dividends per Share

CDN$


US$(1)

First Quarter Total

$

0.03


$

0.02

(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. In order 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.  

Readers are cautioned that the average initial production rates contained in this news release are not necessarily indicative of long-term performance or of ultimate recovery.

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", "should", "believe", "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  average production volumes in 2018 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 funds flow; the results from our drilling program and the timing of related production; oil and natural gas prices and estimated differentials and our commodity risk management programs in 2018 and beyond; expectations regarding our realized oil and natural gas prices; future royalty rates on our production and future production taxes; anticipated cash and non-cash G&A, share-based compensation and financing expenses; operating and transportation costs; capital spending levels in 2018 and its impact on our production level and land holdings; our future royalty and production and cash taxes; future debt and working capital levels and debt to funds flow ratios.

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, our 2018 guidance contained in this news release is based on rest of year prices of: WTI US$65.00/bbl, NYMEX US$3.00/Mcf, and a USD/CDN exchange rate of 1.27. 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 continued volatility, 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; Enerplus' inability to comply with covenants under its bank credit facility and senior notes; 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 Annual Information Form, management's discussion and analysis for the year-ended December 31, 2017, and Form 40-F at December 31, 2017).

The forward-looking information contained in this press release speak only as of the date of this press 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" and "net debt to adjusted funds flow ratio" 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. "Net debt to adjusted funds flow ratio" is calculated as total debt net of cash and restricted cash, divided by a trailing 12 months of adjusted funds flow. Calculation of these terms is described in Enerplus' 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" 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 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' First Quarter 2018 MD&A.

Electronic copies of Enerplus Corporation's First Quarter 2018 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

For further information: 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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