Quarterly / Earnings Reports | Fourth Quarter (4Q) Update | Financial Results | Drilling Activity

Enerplus Gets Oilier in 2017 as North Dakota Output Jumps 70%

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   |    Friday,March 02,2018

[Summary: Enerplus reported its Q4 and full year 2017 results.

Highlights:

  • Delivered 28% crude oil production growth from the first quarter to the fourth quarter of 2017 - Fourth quarter 2017 production was 88,590 BOE per day, above the Company's fourth quarter guidance range of 86,000 to 88,000 BOE per day, and an increase of 12% from the third quarter of 2017.
  • North Dakota production increased by 70% from the first quarter to the fourth quarter of 2017
  • Replaced 189% of 2017 production through proved plus probable ("2P") reserves additions, revisions and economic factors at a finding and development ("F&D") cost of $9.68 per BOE. This included material reserves growth in North Dakota where the Company replaced 414% of 2017 production

Drilling Activity:

 

Three months ended
December 31, 2017

 

Twelve months ended
December 31, 2017

 

Operated

 

Non Operated

 

Operated

 

Non Operated

 

Gross

Net

 

Gross

Net

 

Gross

Net

 

Gross

Net

Williston Basin

7

5.2

 

6

2.1

 

36

28.5

 

8

2.5

Marcellus

-

-

 

28

3.4

 

-

-

 

70

7.2

Canadian Waterfloods

-

-

 

-

-

 

6

6.0

 

-

-

Other

-

-

 

-

-

 

1

1.0

 

-

-

Total

7

5.2

 

34

5.4

 

43

35.5

 

78

9.7

Williston Basin

Williston Basin production averaged 39,195 BOE per day (83% oil) during the fourth quarter of 2017, 27% higher than the third quarter. Fourth quarter Williston Basin production was comprised of 35,474 BOE per day in North Dakota and 3,721 BOE per day in Montana. Enerplus re-established meaningful growth in North Dakota during 2017 delivering a 70% production increase over the course of the year (from the first quarter to the fourth quarter of 2017).

Q4 Well Averages:

  • IP30: 1,443 BOEPD (76% oil)
  • Lateral Length: 7,540 feet

Enerplus continued to see strong outperformance from the four wells on its Snakes pad that were brought on-stream toward the end of the third quarter. On average, the Snakes wells have produced approximately 160,000 barrels of oil per well in 120 days on production, including the Smooth Green well which has produced over 240,000 barrels of oil in 120 days.]

 

 

 

 

 

 

 

ORIGINAL RELEASE:

Enerplus Corporation ("Enerplus" or the "Company") (TSX & NYSE: ERF) today reported fourth quarter 2017 net income of $15.3 million, or $0.06 per share, and fourth quarter adjusted funds flow of $199.6 million. Full year 2017 net income was $237.0 million, or $0.98 per share, and full year 2017 adjusted funds flow was $524.1 million.

HIGHLIGHTS:

  • Fourth quarter adjusted funds flow was $199.6 million, which includes $50.1 million related to a portion of the expected U.S. Alternative Minimum Tax ("AMT") refund. Excluding the AMT refund, adjusted funds flow was $149.5 million, a 65% increase quarter-over-quarter
  • Full year 2017 adjusted funds flow, excluding the AMT refund, increased by 55% compared to 2016
  • Fourth quarter netback before hedging improved by 44% to $21.45 per BOE compared to the previous quarter
  • Delivered 28% crude oil production growth from the first quarter to the fourth quarter of 2017
  • North Dakota production increased by 70% from the first quarter to the fourth quarter of 2017
  • Balance sheet remains among the strongest in the North American peer group, ending 2017 with a net debt to adjusted funds flow ratio of 0.6 times
  • Replaced 189% of 2017 production through proved plus probable ("2P") reserves additions, revisions and economic factors at a finding and development ("F&D") cost of $9.68 per BOE. This included material reserves growth in North Dakota where the Company replaced 414% of 2017 production

 

"In 2017 we accomplished what we set out to do, namely delivering profitable growth, maintaining our disciplined approach to capital allocation, and continuing our strong operating momentum," stated Ian C. Dundas, President and Chief Executive Officer. "We also continued to have success in focusing our business through divesting non-strategic assets which has further improved our cost structure and margin and reduced liabilities. As evidenced by our strong fourth quarter cash flow and netback, our company is well positioned to continue to generate robust cash flow per share growth and create long-term value for our shareholders."

FOURTH QUARTER & FULL YEAR 2017 SUMMARY

Production
Fourth quarter 2017 production was 88,590 BOE per day, above the Company's fourth quarter guidance range of 86,000 to 88,000 BOE per day, and an increase of 12% from the third quarter of 2017. The Company's crude oil and natural gas liquids production averaged 46,822 barrels per day (91% oil) in the fourth quarter, also above its fourth quarter guidance range of 45,000 to 46,000 barrels per day, and an increase of 20% from the third quarter of 2017. The production outperformance in the fourth quarter was primarily driven by higher than forecasted North Dakota and Marcellus volumes, which together accounted for 76% of fourth quarter production.

Full year 2017 production averaged 84,711 BOE per day, including 40,793 barrels per day of crude oil and natural gas liquids (91% oil). Full year production was just above the Company's guidance of 84,000 BOE per day of total production and 40,500 barrels per day of crude oil and natural gas liquids.

Adjusted Funds Flow, Netback and Net Income
The continued improvement of Enerplus' pricing realizations in the Bakken and Marcellus, combined with the reductions to the Company's cost structure, have significantly strengthened the cash flow generating capability of the business. Fourth quarter 2017 adjusted funds flow was $199.6 million, which included $50.1 million related to a portion of the AMT refund receivable as a result of the enactment of U.S. tax reform legislation on December 22, 2017. Excluding the impact of the AMT refund, Enerplus' fourth quarter normalized adjusted funds flow was $149.5 million, 65% higher than the previous quarter. Full year 2017 adjusted funds flow was $524.1 million, or $474.0 million excluding the impact of the AMT refund, representing a 55% increase compared to 2016.

Enerplus' netback, before commodity hedging, was $21.45 per BOE in the fourth quarter of 2017. This represents a 44% increase from the prior quarter and a 47% increase from the same period in 2016. The significant improvement in operating netback was driven by improved pricing differentials in the Bakken and Marcellus, the Company's lower cost structure, and higher benchmark oil prices.

Fourth quarter net income was $15.3 million and included a $46.2 million non-cash deferred income tax expense from the remeasurement of the Company's U.S. deferred income tax assets for the U.S. federal income tax rate reduction from 35% to 21%. This expense is net of the reversal of the valuation allowance previously recorded on the Company's AMT credit carryovers. Full year 2017 net income was $237.0 million.

Pricing Realizations and Cost Structure
Enerplus' realized Bakken crude oil price differential averaged US$1.61 per barrel below WTI in the fourth quarter, an improvement from US$3.24 per barrel in the previous quarter. Spot Bakken prices strengthened considerably throughout 2017 due to the improved egress capacity from the Bakken. Enerplus' average Bakken crude oil price differential for the full year 2017 was US$3.72 per barrel below WTI, in-line with the Company's guidance of US$4.00 per barrel. The Company expects the strength in Bakken pricing to continue and is projecting a 2018 realized differential of US$2.50 per barrel below WTI.

Enerplus' realized Marcellus natural gas sales price differential narrowed to US$0.81 per Mcf below NYMEX in the fourth quarter, compared to US$1.02 per Mcf in the previous quarter. Although Marcellus pricing was weak during October, it strengthened considerably in November and December in response to seasonal heating demand and additional industry pipeline capacity coming into service. Enerplus' average Marcellus natural gas price differential for the full year 2017 was US$0.76 per Mcf below NYMEX, in-line with the Company's guidance of US$0.80 per Mcf. Enerplus believes that the continued build-out of takeaway capacity is structurally improving pricing dynamics in the Marcellus region, and with an expected 2.1 Bcf per day of incremental takeaway projects in 2018 impacting northeast Pennsylvania, the Company anticipates the strength in regional pricing will continue. Enerplus has constructed its Marcellus marketing portfolio with a view to balancing risk mitigation through firm sales and transport commitments, with retaining exposure to in-basin pricing. As a result, Enerplus is positioned to realize the benefit of improving in-basin pricing with only modest transportation commitments. Enerplus expects its 2018 realized Marcellus differential will average US$0.40 per Mcf below NYMEX, which excludes the Company's Marcellus firm transportation cost of US$0.18 per Mcf in 2018.

Enerplus continued to drive reductions to its cost structure in 2017 through divesting higher-cost assets and maintaining its focus on cost control and execution. Fourth quarter 2017 operating, transportation, and cash general and administrative ("G&A") expenses per BOE were all lower compared to the prior quarter.

  • Operating expenses in the fourth quarter were $6.39 per BOE, 5% lower compared to the prior quarter. Full year 2017 operating expenses were $6.37 per BOE, 12% lower compared to 2016.

  • Transportation costs in the fourth quarter were $3.20 per BOE, 11% lower compared to the prior quarter. Full year 2017 transportation costs were $3.60 per BOE, 15% higher compared to 2016 primarily due to the increased weighting of U.S. production with higher associated transport costs.

  • Cash G&A expenses in the fourth quarter were $1.55 per BOE, 4% lower compared to the prior quarter. Full year 2017 cash G&A expenses were $1.63 per BOE, 7% lower compared to 2016.

 

Capital Expenditures and Balance Sheet Position
Capital spending was $116.8 million in the fourth quarter of 2017, bringing full year 2017 capital spending to $458.0 million, in-line with the Company's $450 million 2017 budget.

Enerplus further strengthened its financial position during 2017, reducing net debt by 13% year-over-year. Total debt net of cash at December 31, 2017 was $325.8 million. Total debt was comprised of $672.3 million in senior notes outstanding. The Company was undrawn on its $800 million bank credit facility and had a cash balance of $346.5 million. At December 31, 2017, Enerplus' net debt to adjusted funds flow ratio was 0.6 times.

Divestment Activity and Asset Retirement Obligation
During the fourth quarter of 2017 and first quarter of 2018, Enerplus closed a portion of the previously announced divestments of non-core properties in Alberta. These divestments had associated production of approximately 1,000 BOE per day. Enerplus continues to explore options to divest additional Canadian natural gas assets.

Throughout 2017, Enerplus divested approximately 7,700 BOE per day (66% natural gas) of production in aggregate from predominantly lower-margin properties in Canada. These divestments have helped reduce Enerplus' asset retirement obligation ("ARO") by 35% year-over-year. The present value of the Company's ARO was $117.7 million at December 31, 2017, compared to $181.7 million at December 31, 2016.

AVERAGE DAILY PRODUCTION(1)

 

Three months ended
December 31, 2017

 

Twelve months ended
December 31, 2017

 

Oil & NGL

(Mbbl/d)

Natural gas

(MMcf/d)

Total Production

(Mboe/d)

 

Oil & NGL

(Mbbl/d)

Natural gas

(MMcf/d)

Total Production

(Mboe/d)

Williston Basin

35.8

20.1

39.2

 

28.7

19.2

31.9

Marcellus

-

193.2

32.2

 

-

198.0

33.0

Canadian Waterfloods(2)

9.6

6.6

10.7

 

10.9

12.2

12.9

Other(2)

1.4

30.7

6.5

 

1.2

34.0

6.9

Total

46.8

250.6

88.6

 

40.8

263.5

84.7

(1)

Table may not add due to rounding.

(2)

Includes volumes from Canadian properties that were divested in 2017.

 

SUMMARY OF WELLS BROUGHT ON-STREAM(1)

 

Three months ended
December 31, 2017

 

Twelve months ended
December 31, 2017

 

Operated

 

Non Operated

 

Operated

 

Non Operated

 

Gross

Net

 

Gross

Net

 

Gross

Net

 

Gross

Net

Williston Basin

7

5.2

 

6

2.1

 

36

28.5

 

8

2.5

Marcellus

-

-

 

28

3.4

 

-

-

 

70

7.2

Canadian Waterfloods

-

-

 

-

-

 

6

6.0

 

-

-

Other

-

-

 

-

-

 

1

1.0

 

-

-

Total

7

5.2

 

34

5.4

 

43

35.5

 

78

9.7

(1)

Table may not add due to rounding.

 

2017 RESERVES SUMMARY

  • Replaced 189% of 2017 production, adding 58.0 MMBOE (61% oil) of 2P reserves from development activities (including revisions and economic factors).

  • Material reserves growth was realized in North Dakota and the Marcellus. The Company replaced 414% of 2017 North Dakota production, adding 42.2 MMBOE of 2P reserves and 132% of 2017 Marcellus production, adding 95.4 Bcf of 2P reserves (including revisions and economic factors).

  • F&D costs were $13.17 per BOE for proved developed producing reserves, $11.32 per BOE for proved reserves, and $9.68 per BOE for 2P reserves, including future development costs ("FDC").

  • Three-year average F&D costs were $9.66 per BOE for proved developed producing reserves, $9.16 per BOE for proved reserves, and $7.86 per BOE for 2P reserves, including FDC.

  • Finding, development and acquisition ("FD&A) costs were $12.48 per BOE for proved reserves and $10.98 per BOE for 2P reserves, including FDC. 2017 divestments were generally comprised of lower-margin Canadian properties. No reserves were acquired in 2017.

  • Three-year average FD&A costs were $3.41 per BOE for proved reserves and $1.05 per BOE for 2P reserves, including FDC.

  • Total 2P reserves, net of divestments, were 397.4 MMBOE at year-end 2017, representing a 4% increase from year-end 2016. Excluding divestments, 2P reserves increased by 7% in 2017.

  • 2P reserves were comprised of 48% crude oil, 5% natural gas liquids, and 47% natural gas at year-end 2017.

  • Total proved reserves account for 70% of 2P reserves. Proved developed producing reserves represent 67% of total proved reserves and 47% of 2P reserves.

  • Enerplus' 2P reserves life index increased to 12.6 years at year-end 2017, from 12.3 years at year-end 2016.

 

ASSET ACTIVITY

Williston Basin
Williston Basin production averaged 39,195 BOE per day (83% oil) during the fourth quarter of 2017, 27% higher than the third quarter. Fourth quarter Williston Basin production was comprised of 35,474 BOE per day in North Dakota and 3,721 BOE per day in Montana. Enerplus re-established meaningful growth in North Dakota during 2017 delivering a 70% production increase over the course of the year (from the first quarter to the fourth quarter of 2017).

In the fourth quarter, Enerplus brought on-stream seven gross operated wells (74% average working interest) across its acreage at Fort Berthold with an average completed lateral length of 7,540 feet per well and average peak 30-day production rates per well of 1,443 BOE per day (76% oil, on a three-stream basis). This average rate includes production from two wells that were producing at restricted rates.

Enerplus continued to see strong outperformance from the four wells on its Snakes pad that were brought on-stream toward the end of the third quarter. On average, the Snakes wells have produced approximately 160,000 barrels of oil per well in 120 days on production, including the Smooth Green well which has produced over 240,000 barrels of oil in 120 days.

The Company drilled six gross operated wells (77% average working interest) in the fourth quarter.

Enerplus expects a decline in production from North Dakota in the first quarter of 2018, relative to the fourth quarter of 2017, followed by sequential quarterly production growth for the remainder of the year. The expected decline in the first quarter is due to a completions schedule that results in on-stream activity weighted to the back half of the first quarter in part to mitigate the impact of severe weather during December and January.

Enerplus expects to spend approximately 75% of its 2018 capital budget in North Dakota running two-operated drilling rigs and one dedicated completions crew in 2018. North Dakota production in 2018 is projected to grow by over 30% year-over-year.

Marcellus
Marcellus production averaged 193 MMcf per day during the fourth quarter, a 2% increase from the previous quarter. Fourth quarter production was impacted by approximately 35 MMcf per day of price related production curtailments during October. Enerplus returned to producing at higher rates in November and December in response to strengthening regional natural gas prices. Full year 2017 production from the Marcellus averaged 198 MMcf per day.

Twenty-eight gross non-operated wells (12% average working interest) were brought on-stream during the quarter, of which 22 currently have over 30-days on production. These 22 wells have an average completed lateral length of 5,800 feet per well and average peak 30-day production rates per well of 13.1 MMcf per day.

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

Enerplus expects to spend approximately 10% of its 2018 capital budget in the Marcellus which is projected to keep production levels broadly flat relative to 2017.

Canadian Waterfloods
Canadian waterflood production averaged 10,671 BOE per day (88% oil) during the fourth quarter, a decrease of 8% from the previous quarter primarily due to the planned shut-in of certain production wells at Ante Creek in preparation for conversion to water injection wells, and weather related downtime at Medicine Hat.

Enerplus expects to spend approximately 10% of its 2018 capital budget across its Canadian waterflood portfolio.

DJ Basin
Through leasing and farm-in activity, Enerplus has established a land position of approximately 35,000 net acres in the DJ Basin, located in northwest Weld County, Colorado, for a modest entry price. Enerplus has drilled and completed one well (Maple 8-67-36-25C) to date. The pilot-hole was drilled to a total vertical depth of 7,480 feet and a 388 foot section was cored spanning the entire Niobrara-Codell interval. Core data indicated significant oil saturations throughout the entire interval. Subsequent to coring, Enerplus drilled a 9,272 foot horizontal well in the Codell formation and completed the well using a high-proppant and high-fluid intensity slick water completion. The well has produced 46,920 barrels of oil in 156 days on production and had a peak consecutive 90 day production rate of 434 BOE per day (78% oil). Due to the high fluid intensity completion and flowback management, the oil cut and oil rate inclined for most of the well's initial production period. The well was shut in for several weeks during the first quarter of 2018 for surface facility modifications and was only recently brought back on production. Prior to this the well was producing at a relatively stable rate of approximately 400 BOE per day (78% oil) after over five months on production and is tracking cumulative production of 100,000 BOE in its first 12 months.

The well is producing light oil with a gravity of approximately 39 degrees API which has allowed for oil sales at the lease at a differential below WTI of US$2.25 per barrel. Enerplus will continue to monitor the results of the Maple well and plans to continue delineation activity to test the extent of commerciality across its acreage position. Enerplus is planning to drill up to three wells in the DJ Basin in 2018.

2018 GUIDANCE

Enerplus' previously announced and unchanged 2018 guidance is provided below.

   

Capital spending

$535 585 million

Average annual production

86,000 91,000 BOE/d

Average annual crude oil and natural gas liquids production

46,000 50,000 bbl/d

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 Differential/Basis Outlook(1)

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

US$(2.50)/bbl

Marcellus basis (compared to NYMEX natural gas)

US$(0.40)/Mcf

(1)

Excluding transportation costs

 


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        Debt
        Well Economics - Payout
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        Well Economics
        Rates of Return/ IRR
        F&D Costs / RRC
        Capital Expenditures
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Midstream
        Projects - Pipeline & Facilities
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        Leasehold-ShaleExperts
        Resources Potential
        Production Rates
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