CALGARY, AB – Enerplus Corporation (“Enerplus” or the “Company”) (TSX: ERF) (NYSE: ERF) today reported its third quarter 2020 operating and financial results. Cash flow from operating activities for the third quarter was $137.0 million and adjusted funds flow was $83.1 million. Enerplus reported a third quarter net loss of $112.8 million, or $0.51 per share. The Company recognized a $256.8 million non-cash impairment on property, plant and equipment (“PP&E”) as a result of the continued market volatility and low commodity price environment. Excluding this impairment and certain other non-cash items, Enerplus’ third quarter 2020 adjusted net income was $17.7 million, or $0.08 per share.
HIGHLIGHTS
- Third quarter production was 91,022 BOE per day, including liquids of 52,539 barrels per day
- 2020 production guidance was increased to 90,000 to 91,000 BOE per day (from 88,000 to 90,000 BOE per day), including 50,500 to 51,000 barrels per day of liquids (from 49,000 to 50,000 barrels per day) following production outperformance in North Dakota
- Adjusted funds flow of $83.1 million exceeded capital spending in the third quarter, generating free cash flow of $47.8 million, with additional free cash flow forecast in the fourth quarter
- 2020 capital spending guidance was reduced to $295 million (from $300 million)
- Reduced operating, general & administrative and transportation cost guidance by a combined $0.45 per BOE
- Maintained low financial leverage; net debt to adjusted funds flow ratio was 1.0 times at quarter-end
- Significant operational flexibility with an inventory of 26 net operated drilled uncompleted wells expected at year-end
“We remain committed to preserving our strong financial position during this period of heightened market uncertainty,” said Ian C. Dundas, President and Chief Executive Officer of Enerplus. “Our third quarter results demonstrate this commitment through our focus on reducing costs, maintaining capital discipline and delivering strong operational performance. Looking ahead into 2021, the strength of our balance sheet and our advantaged operational flexibility will help us continue to navigate volatility while positioning the business to generate robust free cash flow in an improving oil price environment.”
THIRD QUARTER SUMMARY
Third quarter production was 91,022 BOE per day, an increase of 4% compared to the prior quarter and 15% lower compared to the same period a year ago. Crude oil and natural gas liquids production in the third quarter was 52,539 barrels per day, a 9% increase compared to the prior quarter and 13% lower compared to the same period a year ago. Previously curtailed production was fully restored in the third quarter driving the higher quarter-over-quarter volumes. The lower production compared to the same period in 2019 was due to the reduction in capital activity in 2020.
Enerplus reported adjusted funds flow for the third quarter of 2020 of $83.1 million compared to $175.3 million in the third quarter of 2019. The decrease was primarily due to a combination of lower commodity prices and production volumes.
The Company reported a net loss of $112.8 million in the third quarter of 2020 compared to net income of $65.2 million from the prior year period. The net loss was primarily due to non-cash PP&E impairments of $256.8 million in the third quarter of 2020 as a result of the continued market volatility and low commodity price environment. Excluding the impairment and certain other non-cash items, Enerplus’ third quarter 2020 adjusted net income was $17.7 million, or $0.08 per share, compared to adjusted net income of $62 million, or $0.27 per share in the third quarter of 2019.
Enerplus’ third quarter 2020 realized Bakken oil price differential was US$5.37 per barrel below WTI, compared to US$3.61 per barrel below WTI in the third quarter of 2019. Third quarter Bakken oil differentials were impacted by uncertainty related to the ongoing legal proceedings regarding the Dakota Access Pipeline.
The Company’s realized Marcellus natural gas price differential was US$0.72 per Mcf below NYMEX during the third quarter of 2020 compared to US$0.44 per Mcf below NYMEX in the prior year period. Weaker third quarter differentials were the result of regional storage being near capacity, combined with lower demand due to mild weather.
Enerplus’ operating expenses were $7.78 per BOE during the third quarter, compared to $7.06 per BOE during the same period in 2019. The higher year-over-year unit operating expenses were primarily due to lower production volumes and a higher liquids production weighting in the third quarter of 2020.
Exploration and development capital spending totaled $35.3 million in the third quarter. The Company paid $6.7 million in dividends in the quarter.
Enerplus remains in a strong financial position with significant liquidity. At the end of the third quarter the Company had total debt of $513.3 million, cash of $84.5 million and was undrawn on its US$600 million bank credit facility. The Company’s net debt to adjusted funds flow ratio was 1.0 times at quarter-end.
Asset Activity
Williston Basin production averaged 48,765 BOE per day (77% crude oil) during the third quarter of 2020, a decrease of 11% compared to the same period in 2019 due to lower capital activity, and 11% higher than the second quarter of 2020, as previously curtailed production was restored. The Company participated in drilling six gross non-operated wells (23% average working interest) and brought one gross non-operated well (40% working interest) on-stream during the third quarter.
Marcellus production averaged 184 MMcf per day during the third quarter of 2020, a decrease of 19% compared to the same period in 2019 and 7% lower than the prior quarter due to reduced capital activity during 2020. The Company participated in drilling 17 gross non-operated wells (9% average working interest) and brought 15 gross non-operated wells (3% average working interest) on production during the third quarter.
Canadian waterflood production averaged 7,726 BOE per day (95% crude oil) during the third quarter of 2020, 16% lower than the third quarter of 2019 due to reduced capital activity, and an increase of 22% compared to the second quarter of 2020, as previously curtailed production was restored. Enerplus brought ten net producer/injector wells at Giltedge onstream during the third quarter.
2020 UPDATED GUIDANCE
Enerplus is increasing its 2020 annual production guidance to 90,000 to 91,000 BOE per day (from 88,000 to 90,000 BOE per day), including 50,500 to 51,000 barrels per day of liquids (from 49,000 to 50,000 barrels per day). The increase is primarily due to the Company’s 2020 North Dakota well program outperforming expectations.
The Company is providing fourth quarter 2020 production guidance of 84,000 to 87,000 BOE per day, including 47,000 to 49,000 barrels per day of liquids.
Enerplus reduced its 2020 capital budget to $295 million, from $300 million, driven by strong operational execution in 2020. Capital activity in the fourth quarter primarily relates to four operated well completions in North Dakota along with non-operated drilling and completion activity in North Dakota and the Marcellus. The Company expects to exit 2020 with an inventory of 26 net operated drilled uncompleted wells.
The Company has had continued success reducing its cost structures in 2020. As a result, Enerplus is reducing its guidance for operating expenses to $8.00 per BOE (from $8.25 per BOE), cash general and administrative expenses to $1.35 per BOE (from $1.40 per BOE) and its transportation costs to $4.00 per BOE (from $4.15 per BOE).
Due to the weakness in Marcellus regional natural gas prices during September and October, Enerplus is revising its 2020 Marcellus natural gas price differential outlook to US$0.60 per Mcf below NYMEX, from US$0.45 per Mcf below NYMEX.
Enerplus’ guidance for its Bakken oil differential and royalty and production tax rate remain unchanged. The Company’s guidance is summarized below.
2020 Guidance |
|
Capital spending |
$295 million (from $300 million) |
Average annual production |
90,000 to 91,000 BOE/day (from 88,000 – 90,000 BOE/day) |
Average annual crude oil & natural gas liquids production |
50,500 to 51,000 bbls/day (from 49,000 – 50,000 bbls/day) |
Average fourth quarter production |
84,000 to 87,000 BOE/day |
Average fourth quarter crude oil & natural gas liquids production |
47,000 to 49,000 bbls/day |
Average royalty and production tax rate |
26% |
Operating expense |
$8.00/BOE (from $8.25/BOE) |
Transportation expense |
$4.00/BOE (from $4.15/BOE) |
Cash G&A expense |
$1.35/BOE (from $1.40/BOE) |
2020 Full-Year Differential/Basis Outlook (1) |
|
U.S. Bakken crude oil differential (compared to WTI crude oil)(2) |
US$(5.00)/bbl |
Marcellus natural gas sales price differential (compared to NYMEX natural gas) |
US$(0.60)/Mcf (from US$(0.45)/Mcf) |
(1) |
Excluding transportation costs. |
(2) |
Based on the continued operation of the Dakota Access Pipeline. |
2021 PRELIMINARY OUTLOOK
Based on the current commodity price environment, Enerplus expects to execute a maintenance capital budget in 2021, which would see the Company’s production remain largely flat to the midpoint of its fourth quarter 2020 guidance at approximately 86,000 BOE per day including 48,000 barrels per day of liquids. Capital spending associated with this outlook is expected to be approximately $300 million. This capital spending outlook includes an allocation to drilling and would support a similar maintenance capital and production profile in 2022.
Enerplus expects this plan to generate free cash flow to fund the dividend at approximately US$40 per barrel WTI and US$3.00 per Mcf NYMEX, while offering more significant free cash flow potential in an improving commodity price environment.
The Company will release its 2021 capital budget and operating plan later in 2020 or in early 2021.
RISK MANAGEMENT
As of November 5, 2020, Enerplus had an average of 21,000 barrels per day of crude oil hedged through financial derivative contracts for the remainder of 2020 and 10,000 barrels per day for the first half of 2021.
For natural gas, Enerplus had 40,000 Mcf per day hedged at a fixed price of US$2.96 per Mcf for the summer of 2021.
WTI Crude Oil (US$/bbl)(1)(2) |
NYMEX Natural Gas (US$/Mcf) |
||
Oct 1, 2020 – |
Jan 1, 2021 – |
||
Dec 31, 2020 |
Jun 30, 2021 |
Apr 1, 2021 – Oct 31, 2021 |
|
Put Spreads |
|||
Volume (bbls/d) |
16,000 |
— |
— |
Sold Puts |
$ 46.88 |
— |
— |
Purchased Puts |
$ 57.50 |
— |
— |
Three Way Collars |
|||
Volume (bbls/d) |
5,000 |
10,000 |
— |
Sold Puts |
$ 48.00 |
$ 32.00 |
— |
Purchased Puts |
$ 56.25 |
$ 40.80 |
— |
Sold Calls |
$ 65.00 |
$ 51.43 |
— |
Swaps |
|||
Volume (bbls/d or Mcf/d) |
— |
— |
40,000 |
Sold Swaps |
— |
— |
$2.96 |
(1) |
All of the sold puts on the put spreads are settled annually at the end of 2020 rather than monthly. |
(2) |
The total average deferred premium spent on these hedges is US$2.04/bbl from Oct 1, 2020 to December 31, 2020 and US$0.42/bbl from January 1, 2021 to June 30, 2021. |
THIRD QUARTER PRODUCTION AND OPERATIONAL SUMMARY TABLES
Average Daily Production(1)
Three months ended |
Nine months ended |
||||||||
Crude Oil (Mbbl/d) |
Natural |
Natural gas (MMcf/d) |
Total (Mboe/d) |
Crude Oil (Mbbl/d) |
Natural Gas |
Natural (MMcf/d) |
Total (Mboe/d) |
||
Williston Basin |
37.5 |
5.8 |
33.0 |
48.8 |
37.7 |
4.9 |
29.7 |
47.5 |
|
Marcellus |
– |
– |
184.3 |
30.7 |
– |
– |
198.9 |
33.2 |
|
Canadian Waterfloods |
7.3 |
– |
2.0 |
7.7 |
7.0 |
0.1 |
2.0 |
7.4 |
|
Other(2) |
1.2 |
0.7 |
11.6 |
3.8 |
1.4 |
0.7 |
12.5 |
4.2 |
|
Total |
46.1 |
6.5 |
230.9 |
91.0 |
46.1 |
5.6 |
243.1 |
92.2 |
(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 |
Nine months ended |
||||||||||
Operated |
Non-Operated |
Operated |
Non-Operated |
||||||||
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
||||
Williston Basin |
– |
– |
6 |
1.4 |
19 |
18.8 |
10 |
2.7 |
|||
Marcellus |
– |
– |
17 |
1.5 |
– |
– |
47 |
3.2 |
|||
Canadian Waterfloods |
– |
– |
– |
– |
10 |
10.0 |
– |
– |
|||
Other(2) |
– |
– |
– |
– |
5 |
4.4 |
16 |
0.9 |
|||
Total |
– |
– |
23 |
2.9 |
34 |
33.2 |
73 |
6.8 |
(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 |
Nine months ended |
||||||||||
Operated |
Non-Operated |
Operated |
Non-Operated |
||||||||
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
||||
Williston Basin |
– |
– |
1 |
0.4 |
18 |
15.8 |
8 |
2.2 |
|||
Marcellus |
– |
– |
15 |
0.4 |
– |
– |
35 |
1.0 |
|||
Canadian Waterfloods |
10 |
10.0 |
– |
– |
10 |
10.0 |
– |
– |
|||
Other(2) |
– |
– |
– |
– |
2 |
1.8 |
1 |
0.0 |
|||
Total |
10 |
10.0 |
16 |
0.8 |
30 |
27.6 |
44 |
3.2 |
(1) |
Table may not add due to rounding. |
(2) |
Comprises DJ Basin and non-core properties in Canada. |
Q3 2020 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 6, 2020 |
Time: |
9:00 AM MT (11:00 AM ET) |
Dial-In: |
587-880-2171 (Alberta) |
1-888-390-0546 (Toll Free) |
|
Conference ID: |
44159509 |
Audiocast: |
https://produceredition.webcasts.com/starthere.jsp?ei=1382966&tp_key=bd5166311d |
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: |
159509 # |
SELECTED FINANCIAL RESULTS |
Three months ended |
Nine months ended |
||||||||||
2020 |
2019 |
2020 |
2019 |
|||||||||
Financial (CDN$, thousands, except ratios) |
||||||||||||
Net Income/(Loss) |
$ |
(112,753) |
$ |
65,181 |
$ |
(719,200) |
$ |
169,423 |
||||
Adjusted Net Income/(Loss)(1) |
17,705 |
61,969 |
(2,391) |
208,793 |
||||||||
Cash Flow from Operating Activities |
136,987 |
159,806 |
350,286 |
505,748 |
||||||||
Adjusted Funds Flow(1) |
83,065 |
175,277 |
266,289 |
530,070 |
||||||||
Dividends to Shareholders – Declared |
6,676 |
6,836 |
20,021 |
21,032 |
||||||||
Total Debt Net of Cash(1) |
428,768 |
521,379 |
428,768 |
521,379 |
||||||||
Capital Spending |
35,345 |
151,520 |
239,054 |
519,521 |
||||||||
Property and Land Acquisitions |
2,388 |
13,344 |
8,060 |
18,280 |
||||||||
Property Divestments |
583 |
(168) |
6,098 |
9,899 |
||||||||
Net Debt to Adjusted Funds Flow Ratio(1) |
1.0x |
0.7x |
1.0x |
0.7x |
||||||||
Financial per Weighted Average Shares Outstanding |
||||||||||||
Net Income /(Loss) – Basic |
$ |
(0.51) |
$ |
0.28 |
$ |
(3.23) |
$ |
0.72 |
||||
Net Income/(Loss) – Diluted |
(0.51) |
0.28 |
(3.23) |
0.71 |
||||||||
Weighted Average Number of Shares Outstanding (000’s) – Basic |
222,548 |
228,908 |
222,487 |
234,403 |
||||||||
Weighted Average Number of Shares Outstanding (000’s) – Diluted |
222,548 |
231,529 |
222,487 |
237,399 |
||||||||
Selected Financial Results per BOE(2)(3) |
||||||||||||
Oil & Natural Gas Sales(4) |
$ |
28.65 |
$ |
40.75 |
$ |
26.95 |
$ |
43.02 |
||||
Royalties and Production Taxes |
(7.36) |
(10.80) |
(6.94) |
(10.86) |
||||||||
Commodity Derivative Instruments |
2.36 |
0.53 |
4.21 |
0.54 |
||||||||
Operating Expenses |
(7.78) |
(7.06) |
(7.86) |
(7.83) |
||||||||
Transportation Costs |
(3.85) |
(3.96) |
(4.02) |
(3.97) |
||||||||
Cash General and Administrative Expenses |
(1.40) |
(1.19) |
(1.33) |
(1.32) |
||||||||
Cash Share-Based Compensation |
0.09 |
— |
0.09 |
(0.02) |
||||||||
Interest, Foreign Exchange and Other Expenses |
(0.82) |
(0.49) |
(1.14) |
(0.65) |
||||||||
Current Income Tax Recovery |
0.02 |
— |
0.57 |
0.72 |
||||||||
Adjusted Funds Flow(1) |
$ |
9.91 |
$ |
17.78 |
$ |
10.53 |
$ |
19.63 |
||||
SELECTED OPERATING RESULTS |
Three months ended |
Nine months ended |
||||||||||
2020 |
2019 |
2020 |
2019 |
|||||||||
Average Daily Production(3) |
||||||||||||
Crude Oil (bbls/day) |
46,082 |
55,023 |
46,098 |
48,141 |
||||||||
Natural Gas Liquids (bbls/day) |
6,457 |
5,098 |
5,581 |
4,736 |
||||||||
Natural Gas (Mcf/day) |
230,895 |
282,360 |
243,083 |
276,063 |
||||||||
Total (BOE/day) |
91,022 |
107,181 |
92,193 |
98,888 |
||||||||
% Crude Oil and Natural Gas Liquids |
58% |
56% |
56% |
53% |
||||||||
Average Selling Price (3)(4) |
||||||||||||
Crude Oil (per bbl) |
$ |
46.43 |
$ |
67.76 |
$ |
43.21 |
$ |
69.64 |
||||
Natural Gas Liquids (per bbl) |
10.60 |
5.97 |
7.88 |
13.97 |
||||||||
Natural Gas (per Mcf) |
1.72 |
2.13 |
1.82 |
3.00 |
||||||||
Net Wells Drilled |
3 |
17 |
40 |
47 |
(1) |
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. |
(2) |
Non-cash amounts have been excluded. |
(3) |
Based on Company interest production volumes. See “Presentation of Production Information” below. |
(4) |
Before transportation costs, royalties, and the effects of commodity derivative instruments. |
Three months ended |
Nine months ended |
|||||||||||
Average Benchmark Pricing |
2020 |
2019 |
2020 |
2019 |
||||||||
WTI crude oil (US$/bbl) |
$ |
40.93 |
$ |
56.45 |
$ |
38.32 |
$ |
57.06 |
||||
Brent (ICE) crude oil (US$/bbl) |
43.37 |
62.00 |
42.53 |
64.74 |
||||||||
NYMEX natural gas – last day (US$/Mcf) |
1.98 |
2.23 |
1.88 |
2.67 |
||||||||
USD/CDN average exchange rate |
1.33 |
1.32 |
1.35 |
1.33 |
Share Trading Summary |
CDN(1) – ERF |
U.S.(2) – ERF |
||||
For the three months ended September 30, 2020 |
(CDN$) |
(US$) |
||||
High |
$ |
4.25 |
$ |
3.19 |
||
Low |
$ |
2.31 |
$ |
1.72 |
||
Close |
$ |
2.44 |
$ |
1.86 |
(1) |
TSX and other Canadian trading data combined. |
(2) |
NYSE and other U.S. trading data combined. |
2020 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 |
$ |
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 disclosure requirements and industry practice, oil and gas sales and production volumes are presented on a gross basis before deduction of royalties. All production volumes and oil and gas sales presented herein are reported on a “company interest” basis, before deduction of Crown and other royalties, plus Enerplus’ royalty interest. All references to “liquids” in this news release include light and medium crude oil, heavy oil and tight oil (all together referred to as “crude oil”) and natural gas liquids on a combined basis.