Enerplus Announces Second Quarter 2021 Results; Increases Dividend by 15%
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' Second Quarter 2021 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, AB, Aug. 5, 2021 /CNW/ - Enerplus Corporation ("Enerplus" or the "Company") (TSX: ERF) (NYSE: ERF) today reported its second quarter 2021 operating and financial results and an increase to its dividend. Cash flow from operating activities for the second quarter was $136.9 million and adjusted funds flow was $184.3 million, compared to $90.6 million and $70.0 million, respectively, in the second quarter of 2020. Cash flow from operating activities and adjusted funds flow increased compared to the same period in 2020 due to higher production and commodity prices during the second quarter of 2021.
HIGHLIGHTS
- Successfully closed the strategic acquisition of assets in the Williston Basin from Hess Corporation on April 30, 2021
- Achieved record production in the second quarter of 115,351 BOE per day, 26% higher than the prior quarter
- Adjusted funds flow was $184.3 million in the second quarter, which exceeded capital spending of $129.9 million, generating free cash flow of $54.4 million
- Annual average 2021 production guidance revised to 112,000 to 115,000 BOE per day, including 69,500 to 71,500 barrels per day of liquids, reflecting higher mid-points, with no change in 2021 capital spending guidance
- Increasing return of capital to shareholders: quarterly dividend increased 15% to $0.038 per share; reinitiating share repurchase program
- Capital efficiencies continuing to improve: well costs in North Dakota are tracking US$5.7 million per well, a 25% reduction compared to 2019
- 2021 Bakken crude oil price differential guidance strengthened to US$2.35 per barrel below WTI (from US$3.25)
- Estimated 2021 free cash flow of over $450 million based on current forward strip commodity prices
- Net debt to adjusted funds flow ratio estimated to be at or below 1.0x by year-end 2021 based on current forward strip commodity prices
"Our second quarter results reflect the increasing scale of our business and continued strong operational momentum," said Ian C. Dundas, President and CEO. "We delivered record production, capital efficiency gains along with an increasing free cash flow profile. The 15% increase to our quarterly dividend—our second dividend increase this year—and resumption of our share repurchase program underscores our commitment to providing increasing capital returns to shareholders. While we are prioritizing debt reduction in the near term, we will continue to evaluate returning incremental free cash flow to shareholders and are well positioned to meaningfully enhance our shareholder returns upon achieving our $400 million debt reduction target."
SECOND QUARTER SUMMARY
Production in the second quarter of 2021 was 115,351 BOE per day, an increase of 32% compared to the same period a year ago, and 26% higher than the prior quarter. Crude oil and natural gas liquids production in the second quarter of 2021 was 71,693 barrels per day, an increase of 49% compared to the same period a year ago, and 46% higher than the prior quarter. The increased production compared to the same period in 2020 was due to the contribution from the Company's Williston Basin acquisitions in 2021 and lower production during the second quarter of 2020 due to reduced activity and temporarily curtailed volumes in response to the low crude oil prices.
Enerplus reported a second quarter 2021 net loss of $59.7 million, or $0.23 per share, compared to a net loss of $609.3 million, or $2.74 per share, in the same period in 2020 which included non-cash impairments. The net loss recognized in the second quarter of 2021 was primarily due to non-cash mark to market losses related to commodity derivative instruments. Adjusted net income for the second quarter of 2021 was $67.9 million, or $0.26 per share, compared to an adjusted net loss of $41.2 million, or $0.19 per share, during the same period in 2020. Adjusted net income was higher compared to the same period in 2020 due to higher commodity prices and increased production.
Enerplus' second quarter 2021 realized Bakken oil price differential was US$2.76 per barrel below WTI, compared to US$4.36 per barrel below WTI in the second quarter of 2020. Bakken crude oil differentials improved relative to the prior year period due to increased U.S. refinery demand and significant available pipeline capacity in the basin.
The Company's realized Marcellus natural gas price differential was US$0.89 per Mcf below NYMEX during the second quarter of 2021 compared to US$0.49 per Mcf below NYMEX in the second quarter of 2020. The weaker second quarter 2021 differential reflected significant unplanned regional pipeline maintenance.
In the second quarter of 2021, Enerplus' operating expenses were $8.43 per BOE, compared to $6.84 per BOE during the same period in 2020. Operating expenses in the second quarter of 2020 were impacted by price-related production curtailments and lower well servicing activity.
Second quarter transportation costs were $3.45 per BOE and cash general and administrative ("G&A") expenses were $1.04 per BOE.
Enerplus recorded a current tax expense of $4.2 million in the second quarter of 2021 related to U.S. federal taxes as a result of higher expected income in 2021.
Exploration and development capital spending was $129.9 million in the second quarter of 2021. The Company paid $11.0 million in dividends in the quarter.
Enerplus closed its strategic acquisition of certain assets in the Williston Basin from Hess Corporation on April 30, 2021, for total cash consideration of US$312 million, subject to customary purchase price adjustments.
At the end of the second quarter of 2021, the Company had total debt of $1,208.1 million and cash on hand of $75.3 million. Enerplus made principal repayments of US$81.6 million on its 2009 and 2012 senior notes during the quarter.
ASSET ACTIVITY
Williston Basin production averaged 72,390 BOE per day (73% crude oil) during the second quarter of 2021, an increase of 64% compared to the same period a year ago, and 53% higher than the prior quarter. During the second quarter the Company drilled four gross operated wells (100% working interest) and brought 23 gross operated wells on production (83% average working interest). Enerplus continued to drive capital efficiency improvements through faster drilling and completions cycle times and other efficiencies. Enerplus set a company record in the second quarter drilling a two-mile lateral section in 48 hours (lateral spud to total depth). Total well costs in North Dakota are now expected to average US$5.7 million per well in 2021, a reduction of 25% compared to 2019 levels and well below the 2021 target of US$6.1 million.
Marcellus production averaged 192 MMcf per day during the second quarter of 2021, a decrease of 3% compared to the same period in 2020, and 6% lower than the prior quarter.
Canadian waterflood production averaged 7,240 BOE per day (95% crude oil) during the second quarter of 2021, an increase of 14% compared to the same period in 2020, and 2% lower than the prior quarter.
FREE CASH FLOW PRIORITIES
Enerplus expects to allocate approximately 90% of its free cash flow, after dividends, to debt reduction. The Company is targeting a net debt to adjusted funds flow ratio at or below 1.0x assuming a $50 per barrel WTI oil price environment, representing a debt reduction target of approximately $400 million from second quarter 2021 levels. Enerplus estimates it will achieve its debt reduction target by mid-2022 based on current forward strip commodity prices. The remaining approximately 10% of free cash flow, after dividends, is expected to be allocated to incremental capital returns to shareholders, including potential dividend increases and share repurchases. The Company will continue to evaluate this free cash flow allocation as it makes progress on its debt reduction target with the expectation of increasing the allocation of free cash flow to shareholders once its debt target is achieved, assuming a supportive commodity price environment.
Given the Company's significant increase in cash flow generation following its strategic acquisitions in the first half of 2021, Enerplus believes the business can support a higher dividend while continuing to prioritize debt reduction. As a result, the Board of Directors has approved a 15% increase to the Company's quarterly dividend to $0.038 per share payable on September 15, 2021 to shareholders of record on August 31, 2021. This is Enerplus' second dividend increase year to date and represents a 27% increase, on an annualized basis, from the Company's dividend level at the start of the year.
Enerplus also received approval from its Board of Directors to commence a Normal Course Issuer Bid ("NCIB"), subject to approval by the Toronto Stock Exchange ("TSX"). The proposed renewal will be for 10% of the public float (within the meaning under the TSX rules).
FIVE-YEAR OUTLOOK UPDATE
Enerplus has updated year one (2021) of its five-year outlook to reflect year to date commodity prices and the forward strip for the remainder of the year. The years 2022 to 2025 continue to be based on US$50 to US$55 per barrel WTI flat oil price assumptions. Based on this, the Company has increased the estimated cumulative free cash flow over this period to approximately $1.5 to $2.0 billion.
2021 GUIDANCE UPDATE
Enerplus revised its 2021 average production guidance to 112,000 to 115,000 BOE per day, including liquids production of 69,500 to 71,500 barrels per day due to outperformance year to date. Capital spending guidance is unchanged.
Enerplus narrowed its 2021 Bakken crude oil price differential guidance to US$2.35 per barrel below WTI, compared to US$3.25 per barrel below WTI previously. The improved differential guidance is due to strong year to date pricing and additional firm capacity on the Dakota Access Pipeline ("DAPL") secured in connection with the pipeline's expansion. Enerplus now has approximately 10,000 barrels per day of firm transportation on DAPL.
As a result of ongoing pipeline maintenance in the Marcellus, Enerplus widened its 2021 Marcellus natural gas price differential to US$0.65 per Mcf below NYMEX, compared to US$0.55 per Mcf below NYMEX previously.
The Company expects to incur current income tax expense of US$5 million to US$7 million in 2021.
A summary of the Company's 2021 guidance is provided below.
2021 Guidance
Capital spending |
$360 to $400 million |
Average annual production |
112,000 – 115,000 BOE/day (from 111,000 – 115,000 BOE/day) |
Average annual crude oil and natural gas liquids production |
69,500 – 71,500 bbls/day (from 68,500 – 71,500 bbls/day) |
Average royalty and production tax rate |
26% |
Operating expense |
$8.25/BOE |
Transportation expense |
$3.85/BOE |
Cash G&A expense |
$1.25/BOE |
Current Income Tax expense |
US$5 – $7 million |
2021 Full-Year Differential/Basis Outlook (1)
U.S. Bakken crude oil differential (compared to WTI crude oil)(2) |
US$(2.35)/bbl (from US$(3.25)/bbl) |
Marcellus natural gas sales price differential (compared to NYMEX natural gas) |
US$(0.65)/Mcf (from US$(0.55)/Mcf) |
(1) |
Excluding transportation costs. |
(2) |
Based on the continued operation of the Dakota Access Pipeline. |
Risk Management
Enerplus' commodity hedging positions are provided in the table below.
Enerplus' Financial Commodity Hedging Contracts (As at August 4, 2021)
WTI Crude Oil (1)(2) (US$/bbl) |
NYMEX Natural Gas (US$/Mcf) |
|||||||||||
Jul 1, 2021 – |
Jan 1, 2022 – |
Jan 1, 2023 – |
Nov 1, 2023 – |
Jul 1, 2021 – |
Nov 1, 2021 – |
|||||||
Dec 31, 2021 |
Dec 31, 2022 |
Oct 31, 2023 |
Dec 31, 2023 |
Oct 31, 2021 |
Mar 31, 2022 |
|||||||
Swaps |
||||||||||||
Volume (bbls/day) |
– |
– |
– |
– |
60,000 |
– |
||||||
Swaps |
– |
– |
– |
– |
$ 2.90 |
– |
||||||
Collars |
||||||||||||
Volume (bbls/day) |
23,000 |
17,000 |
– |
– |
40,000 |
40,000 |
||||||
Sold Puts |
$ 36.39 |
$ 40.00 |
– |
– |
$ 2.15 |
– |
||||||
Purchased Puts |
$ 46.39 |
$ 50.00 |
– |
– |
$ 2.75 |
$ 3.43 |
||||||
Sold Calls |
$ 56.70 |
$ 57.91 |
– |
– |
$ 3.25 |
$ 6.00 |
||||||
Hedges acquired from Bruin(3) |
||||||||||||
Swaps |
||||||||||||
Volume (bbls/day) |
8,465 |
3,828 |
250 |
– |
– |
– |
||||||
Swaps |
$ 42.52 |
$ 42.35 |
$ 42.10 |
– |
– |
– |
||||||
Collars |
||||||||||||
Volume (bbls/day) |
– |
– |
2,000 |
2,000 |
– |
– |
||||||
Purchased Puts |
– |
– |
$ 5.00 |
$ 5.00 |
– |
– |
||||||
Sold Calls |
– |
– |
$ 75.00 |
$ 75.00 |
– |
– |
||||||
(1) |
The total average deferred premium spent on outstanding hedges is US$0.84/bbl from July 1, 2021 - December 31, 2021 and US$1.22/bbl from January 1, 2022 - December 31, 2022. |
(2) |
Transactions with a common term have been aggregated and presented at weighted average prices and volumes. |
(3) |
Upon closing of the Bruin Acquisition, Bruin's outstanding hedges were recorded at a fair value liability of $96.5 million. At June 30, 2021, the fair value of the Bruin hedges was a liability of $100.0 million. For the three and six months ended June 30, 2021 we recorded a realized loss of $2.2 million and $1.7 million, respectively, on the settlement of the Bruin hedges. In Addition, we recognized an unrealized loss of $52.8 million and $35.4 million, respectively, for the change in the fair value of the Bruin hedges over the same periods. See Note 17 to the Q2 2021 Financial Statements for further detail. |
SECOND QUARTER PRODUCTION AND Operational summary tables
Average Daily Production(1)
Three months ended June 30, 2021 |
Six months ended June 30, 2021 |
||||||||||||
Williston |
Marcellus |
Canadian |
Other(2) |
Total |
Williston |
Marcellus |
Canadian |
Other(2) |
Total |
||||
Tight oil (bbl/d) |
52,896 |
- |
- |
1,900 |
54,797 |
43,743 |
- |
- |
1,347 |
45,090 |
|||
Light & medium oil (bbl/d) |
- |
- |
2,912 |
86 |
2,998 |
- |
- |
2,970 |
65 |
3,035 |
|||
Heavy oil (bbl/d) |
- |
- |
3,983 |
25 |
4,008 |
- |
- |
4,045 |
17 |
4,063 |
|||
Total crude oil (bbl/d) |
52,896 |
- |
6,895 |
2,012 |
61,803 |
43,743 |
- |
7,015 |
1,429 |
52,188 |
|||
Natural gas liquids (bbl/d) |
9,257 |
- |
129 |
504 |
9,890 |
7,634 |
- |
76 |
535 |
8,245 |
|||
Shale gas (Mcf/d) |
61,418 |
191,602 |
- |
1,535 |
254,555 |
51,300 |
197,760 |
- |
1,337 |
250,396 |
|||
Conventional natural gas (Mcf/d) |
- |
- |
1,296 |
6,093 |
7,389 |
- |
- |
1,238 |
7,230 |
8,467 |
|||
Total natural gas (Mcf/d) |
61,418 |
191,602 |
1,296 |
7,628 |
261,945 |
51,300 |
197,760 |
1,238 |
8,566 |
258,863 |
|||
Total production (BOE/d) |
72,390 |
31,934 |
7,240 |
3,786 |
115,351 |
59,928 |
32,960 |
7,297 |
3,392 |
103,576 |
|||
(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 |
Six months ended |
||||||||||
Operated |
Non-Operated |
Operated |
Non-Operated |
||||||||
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
||||
Williston Basin |
4 |
4.0 |
- |
- |
4 |
4.0 |
- |
- |
|||
Marcellus |
- |
- |
14 |
0.6 |
- |
- |
28 |
0.8 |
|||
Canadian Waterfloods |
- |
- |
- |
- |
- |
- |
- |
- |
|||
Other(2) |
- |
- |
- |
- |
- |
- |
2 |
0.3 |
|||
Total |
4 |
4.0 |
14 |
0.6 |
4 |
4.0 |
30 |
1.1 |
|||
(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 |
Six months ended |
||||||||||
Operated |
Non-Operated |
Operated |
Non-Operated |
||||||||
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
||||
Williston Basin |
23 |
19.1 |
1 |
0.4 |
26 |
22.1 |
1 |
0.4 |
|||
Marcellus |
- |
- |
20 |
1.4 |
- |
- |
36 |
1.8 |
|||
Canadian Waterfloods |
- |
- |
- |
- |
- |
- |
- |
- |
|||
Other(2) |
- |
- |
- |
- |
3 |
2.6 |
2 |
0.3 |
|||
Total |
23 |
19.1 |
21 |
1.8 |
29 |
24.7 |
39 |
2.5 |
|||
(1) |
Table may not add due to rounding. |
(2) |
Comprises DJ Basin and non-core properties in Canada. |
Q2 2021 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) on Friday, August 6, 2021 to discuss these results. Details of the conference call are as follows:
Date: |
Friday, August 6, 2021 |
Time: |
9:00 AM MT (11:00 AM ET) |
Dial-In: |
587-880-2171 (Alberta) |
1-888-390-0546 (Toll Free) |
|
Conference ID: |
07577276 |
Audiocast: |
https://produceredition.webcasts.com/starthere.jsp?ei=1470850&tp_key=75a2e3927a |
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: |
577276 # |
SELECTED FINANCIAL RESULTS |
Three months ended |
Six months ended |
||||||||||
2021 |
2020 |
2021 |
2020 |
|||||||||
Financial (CDN$, thousands, except ratios) |
||||||||||||
Net Income/(Loss) |
$ |
(59,664) |
$ |
(609,323) |
$ |
(44,967) |
$ |
(606,447) |
||||
Adjusted Net Income/(Loss)(1) |
67,932 |
(41,185) |
124,183 |
(20,095) |
||||||||
Cash Flow from Operating Activities |
136,902 |
90,560 |
174,141 |
213,299 |
||||||||
Adjusted Funds Flow(1) |
184,320 |
69,997 |
312,435 |
183,224 |
||||||||
Dividends to Shareholders - Declared |
11,040 |
6,675 |
18,405 |
13,345 |
||||||||
Total Debt Net of Cash(1) |
1,132,841 |
518,094 |
1,132,841 |
518,094 |
||||||||
Capital Spending |
129,903 |
40,084 |
195,434 |
203,709 |
||||||||
Property and Land Acquisitions |
408,764 |
3,416 |
1,037,332 |
5,672 |
||||||||
Property Divestments |
(17) |
(63) |
4,978 |
5,515 |
||||||||
Net Debt to Adjusted Funds Flow Ratio(1)(2) |
2.3x |
1.0x |
2.3x |
1.0x |
||||||||
Financial per Weighted Average Shares Outstanding |
||||||||||||
Net Income /(Loss) - Basic |
$ |
(0.23) |
$ |
(2.74) |
$ |
(0.18) |
$ |
(2.73) |
||||
Net Income/(Loss) - Diluted |
(0.23) |
(2.74) |
(0.18) |
(2.73) |
||||||||
Weighted Average Number of Shares Outstanding (000's) - Basic |
256,750 |
222,557 |
250,443 |
222,457 |
||||||||
Weighted Average Number of Shares Outstanding (000's) - Diluted |
256,750 |
222,557 |
250,443 |
222,457 |
||||||||
Selected Financial Results per BOE(3)(4) |
||||||||||||
Crude Oil & Natural Gas Sales(5) |
$ |
48.60 |
$ |
19.53 |
$ |
46.38 |
$ |
26.11 |
||||
Royalties and Production Taxes |
(12.58) |
(5.15) |
(11.74) |
(6.74) |
||||||||
Commodity Derivative Instruments |
(3.53) |
6.73 |
(3.02) |
5.12 |
||||||||
Operating Expenses |
(8.43) |
(6.84) |
(8.16) |
(7.90) |
||||||||
Transportation Costs |
(3.45) |
(4.28) |
(3.68) |
(4.11) |
||||||||
Cash General and Administrative Expenses |
(1.04) |
(1.14) |
(1.28) |
(1.26) |
||||||||
Cash Share-Based Compensation |
(0.22) |
(0.15) |
(0.27) |
0.09 |
||||||||
Interest, Foreign Exchange and Other Expenses |
(1.39) |
(1.69) |
(1.34) |
(1.29) |
||||||||
Current Income Tax Recovery/(Expenses) |
(0.40) |
1.81 |
(0.22) |
0.85 |
||||||||
Adjusted Funds Flow(1) |
$ |
17.56 |
$ |
8.82 |
$ |
16.67 |
$ |
10.87 |
||||
Three months ended |
Six months ended |
||||||||||||
SELECTED OPERATING RESULTS |
|||||||||||||
2021 |
2020 |
2021 |
2020 |
||||||||||
Average Daily Production(4) |
|||||||||||||
Crude Oil (bbls/day) |
61,803 |
43,168 |
52,187 |
46,106 |
|||||||||
Natural Gas Liquids (bbls/day) |
9,890 |
4,929 |
8,245 |
5,137 |
|||||||||
Natural Gas (Mcf/day) |
261,945 |
235,579 |
258,863 |
249,246 |
|||||||||
Total (BOE/day) |
115,351 |
87,360 |
103,576 |
92,784 |
|||||||||
% Crude Oil and Natural Gas Liquids |
62% |
55% |
58% |
55% |
|||||||||
Average Selling Price (4)(5) |
|||||||||||||
Crude Oil (per bbl) |
$ |
76.67 |
$ |
30.55 |
$ |
72.90 |
$ |
41.59 |
|||||
Natural Gas Liquids (per bbl) |
22.72 |
(0.96) |
28.06 |
6.16 |
|||||||||
Natural Gas (per Mcf) |
2.45 |
1.63 |
2.96 |
1.87 |
|||||||||
Net Wells Drilled |
5 |
3 |
5 |
37 |
|||||||||
(1) |
These are non–GAAP measures that do not have any standardized meaning under the Company's GAAP and, therefore, may not be directly comparable to similar measures presented by other entities. See "Non–GAAP Measures" section in the news release. |
(2) |
Ratio does not include trailing adjusted funds flow from the recent Williston Basin acquisitions. |
(3) |
Non-cash amounts have been excluded. |
(4) |
Based on Company interest production volumes. See "Presentation of Production Information" below. |
(5) |
Before transportation costs, royalties, and commodity derivative instruments. |
Condensed Consolidated Balance Sheets
(CDN$ thousands) unaudited |
June 30, 2021 |
December 31, 2020 |
|||||
Assets |
|||||||
Current Assets |
|||||||
Cash and cash equivalents |
$ |
75,278 |
$ |
114,455 |
|||
Accounts receivable |
252,316 |
106,376 |
|||||
Derivative financial assets |
— |
3,550 |
|||||
Other current assets |
7,505 |
7,137 |
|||||
335,099 |
231,518 |
||||||
Property, plant and equipment: |
|||||||
Crude oil and natural gas properties (full cost method) |
1,680,329 |
575,559 |
|||||
Other capital assets, net |
18,912 |
19,524 |
|||||
Property, plant and equipment |
1,699,241 |
595,083 |
|||||
Right-of-use assets |
36,951 |
32,853 |
|||||
Deferred income tax asset |
600,257 |
607,001 |
|||||
Total Assets |
$ |
2,671,548 |
$ |
1,466,455 |
|||
Liabilities |
|||||||
Current liabilities |
|||||||
Accounts payable |
$ |
379,255 |
$ |
251,822 |
|||
Dividends payable |
— |
2,225 |
|||||
Current portion of long-term debt |
98,688 |
103,836 |
|||||
Derivative financial liabilities |
225,696 |
19,261 |
|||||
Current portion of lease liabilities |
12,940 |
13,391 |
|||||
716,579 |
390,535 |
||||||
Derivative financial liabilities |
64,536 |
— |
|||||
Long-term debt |
1,109,431 |
386,586 |
|||||
Asset retirement obligation |
160,201 |
130,208 |
|||||
Lease liabilities |
27,668 |
23,446 |
|||||
1,361,836 |
540,240 |
||||||
Total Liabilities |
2,078,415 |
930,775 |
|||||
Shareholders' Equity |
|||||||
Share capital – authorized unlimited common shares, no par value Issued and outstanding: June 30, 2021 – 257 million shares December 31, 2020 – 223 million shares |
3,236,117 |
3,096,969 |
|||||
Paid-in capital |
36,269 |
50,604 |
|||||
Accumulated deficit |
(2,995,389) |
(2,932,017) |
|||||
Accumulated other comprehensive income/(loss) |
316,136 |
320,124 |
|||||
593,133 |
535,680 |
||||||
Total Liabilities & Shareholders' Equity |
$ |
2,671,548 |
$ |
1,466,455 |
|||
Condensed Consolidated Statements of Income/(Loss) and Comprehensive Income/(Loss)
Three months ended |
Six months ended |
||||||||||||
June 30, |
June 30, |
||||||||||||
(CDN$ thousands, except per share amounts) unaudited |
2021 |
2020 |
2021 |
2020 |
|||||||||
Revenues |
|||||||||||||
Crude oil and natural gas sales, net of royalties |
$ |
408,622 |
$ |
122,069 |
$ |
697,423 |
$ |
350,196 |
|||||
Commodity derivative instruments gain/(loss) |
(197,967) |
(10,895) |
(267,810) |
120,446 |
|||||||||
210,655 |
111,174 |
429,613 |
470,642 |
||||||||||
Expenses |
|||||||||||||
Operating |
88,459 |
54,353 |
152,981 |
133,373 |
|||||||||
Transportation |
36,188 |
34,006 |
69,011 |
69,335 |
|||||||||
Production taxes |
30,502 |
7,687 |
47,954 |
23,131 |
|||||||||
General and administrative |
12,474 |
13,494 |
28,746 |
32,679 |
|||||||||
Depletion, depreciation and accretion |
93,908 |
79,885 |
140,368 |
175,077 |
|||||||||
Asset impairment |
— |
426,810 |
4,300 |
426,810 |
|||||||||
Goodwill impairment |
— |
202,767 |
— |
202,767 |
|||||||||
Interest |
9,527 |
7,051 |
16,350 |
15,962 |
|||||||||
Foreign exchange (gain)/loss |
6,864 |
1,493 |
6,986 |
(4,144) |
|||||||||
Transaction costs and other expense/(income) |
(718) |
6,301 |
3,806 |
6,072 |
|||||||||
277,204 |
833,847 |
470,502 |
1,081,062 |
||||||||||
Income/(Loss) before taxes |
(66,549) |
(722,673) |
(40,889) |
(610,420) |
|||||||||
Current income tax expense/(recovery) |
4,175 |
(14,422) |
4,175 |
(14,395) |
|||||||||
Deferred income tax expense/(recovery) |
(11,060) |
(98,928) |
(97) |
10,422 |
|||||||||
Net Income/(Loss) |
$ |
(59,664) |
$ |
(609,323) |
$ |
(44,967) |
$ |
(606,447) |
|||||
Other Comprehensive Income/(Loss) |
|||||||||||||
Unrealized gain/(loss) on foreign currency translation |
(14,345) |
(57,284) |
(27,212) |
74,490 |
|||||||||
Foreign exchange gain/(loss) on net investment hedge with U.S. |
14,702 |
19,466 |
23,224 |
(30,596) |
|||||||||
Total Comprehensive Income/(Loss) |
$ |
(59,307) |
$ |
(647,141) |
$ |
(48,955) |
$ |
(562,553) |
|||||
Net income/(Loss) per share |
|||||||||||||
Basic |
$ |
(0.23) |
$ |
(2.74) |
$ |
(0.18) |
$ |
(2.73) |
|||||
Diluted |
$ |
(0.23) |
$ |
(2.74) |
$ |
(0.18) |
$ |
(2.73) |
|||||
Condensed Consolidated Statements of Cash Flows
Three months ended |
Six months ended |
||||||||||||
June 30, |
June 30, |
||||||||||||
(CDN$ thousands) unaudited |
2021 |
2020 |
2021 |
2020 |
|||||||||
Operating Activities |
|||||||||||||
Net income/(loss) |
$ |
(59,664) |
$ |
(609,323) |
$ |
(44,967) |
$ |
(606,447) |
|||||
Non-cash items add/(deduct): |
|||||||||||||
Depletion, depreciation and accretion |
93,908 |
79,885 |
140,368 |
175,077 |
|||||||||
Asset impairment |
— |
426,810 |
4,300 |
426,810 |
|||||||||
Goodwill impairment |
— |
202,767 |
— |
202,767 |
|||||||||
Changes in fair value of derivative instruments |
160,130 |
63,929 |
209,972 |
(32,499) |
|||||||||
Deferred income tax expense/(recovery) |
(11,060) |
(98,928) |
(97) |
10,422 |
|||||||||
Foreign exchange (gain)/loss on debt and working capital |
5,539 |
1,038 |
5,858 |
(1,377) |
|||||||||
Share-based compensation and general and administrative |
(23) |
3,428 |
990 |
11,183 |
|||||||||
Other expenses/(income) |
(2,353) |
— |
(2,353) |
— |
|||||||||
Amortization of debt issuance costs |
312 |
— |
385 |
— |
|||||||||
Translation of U.S. dollar cash held in Canada |
(2,469) |
391 |
(2,021) |
(2,712) |
|||||||||
Asset retirement obligation settlements |
(1,359) |
(333) |
(8,439) |
(11,127) |
|||||||||
Changes in non-cash operating working capital |
(46,059) |
20,896 |
(129,855) |
41,202 |
|||||||||
Cash flow from/(used in) operating activities |
136,902 |
90,560 |
174,141 |
213,299 |
|||||||||
Financing Activities |
|||||||||||||
Bank term loan |
— |
— |
501,286 |
— |
|||||||||
Bank credit facility |
333,616 |
1,364 |
333,616 |
1,364 |
|||||||||
Repayment of senior notes |
(99,348) |
(114,010) |
(99,348) |
(114,010) |
|||||||||
Proceeds from the issuance of shares |
— |
— |
125,746 |
— |
|||||||||
Purchase of common shares under Normal Course Issuer Bid |
— |
— |
— |
(2,536) |
|||||||||
Share-based compensation – cash settled (tax withholding) |
— |
— |
(4,491) |
(7,232) |
|||||||||
Dividends |
(13,608) |
(6,676) |
(20,627) |
(13,337) |
|||||||||
Cash flow from/(used in) financing activities |
220,660 |
(119,322) |
836,182 |
(135,751) |
|||||||||
Investing Activities |
|||||||||||||
Capital and office expenditures |
(92,422) |
(104,111) |
(144,184) |
(233,453) |
|||||||||
Bruin acquisition |
(2,537) |
— |
(531,134) |
— |
|||||||||
Dunn County acquisition |
(374,613) |
— |
(374,613) |
— |
|||||||||
Property and land acquisitions |
(1,619) |
(3,416) |
(5,026) |
(5,672) |
|||||||||
Property divestments |
(17) |
(63) |
4,978 |
5,515 |
|||||||||
Cash flow from/(used in) investing activities |
(471,208) |
(107,590) |
(1,049,979) |
(233,610) |
|||||||||
Effect of exchange rate changes on cash & cash equivalents |
(92) |
453 |
479 |
10,590 |
|||||||||
Change in cash and cash equivalents |
(113,738) |
(135,899) |
(39,177) |
(145,472) |
|||||||||
Cash and cash equivalents, beginning of period |
189,016 |
142,076 |
114,455 |
151,649 |
|||||||||
Cash and cash equivalents, end of period |
$ |
75,278 |
$ |
6,177 |
$ |
75,278 |
$ |
6,177 |
|||||
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), "MBOE" (one thousand barrels of oil equivalent), and "MMBOE" (one million 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. BOE, MBOE and MMBOE 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.
FORWARD-LOOKING INFORMATION AND STATEMENTS
This news release contains certain forward-looking information and forward-looking statements within the meaning of applicable securities laws ("forward-looking information"). The use of any of the words "expect", "anticipate", "continue", "estimate", "guidance", "believes" and "plans" 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 benefits of the Hess asset and Bruin acquisition; expected impact of the Hess asset and Bruin acquisitions on Enerplus' operations and financial results, including expected free cash flow in 2021 and beyond and year-end net debt to adjusted funds flow ratio; anticipated impact of the Hess asset and Bruin acquisitions on Enerplus' future costs and expenses; the renewal of Enerplus' NCIB and terms thereof; expected capital spending levels in 2021 and the future and the impact thereof on our production levels and land holdings; expected production volumes and updated 2021 and future production guidance; expected operating strategy in 2021; the effect of Enerplus' participation in the DAPL expansion on increased crude oil transportation; 2021 average production volumes, timing thereof and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged and the expected effectiveness of such hedges in protecting our adjusted funds flow in 2021 and the future; the results from our drilling program and the timing of related production and ultimate well recoveries; oil and natural gas prices and differentials, our commodity risk management program in 2021 and expected hedging gains; expectations regarding our realized oil and natural gas prices; expected operating, transportation, cash G&A and financing costs; expected reduction in well costs; future royalty rates on our production and future production taxes; net debt to adjusted funds-flow ratio, financial capacity and liquidity and capital resources to fund capital spending, dividends and working capital requirements; expectations regarding our ability to comply with debt covenants under our bank credit facility, term loan and outstanding senior notes; and expectations regarding payment of increased dividends.
The forward-looking information contained in this news release reflects several material factors, expectations and assumptions including, without limitation: that we will conduct our operations and achieve results of operations as anticipated, including considering the Hess asset and Bruin acquisition; that our development plans will achieve the expected results; that a lack of adequate infrastructure and/or low commodity price environment will not result in curtailment of production and/or reduced realized prices beyond our current expectations; current and estimated commodity prices, differentials and cost assumptions; the continued ability to operate DAPL; that our development plans will achieve the expected results; the general continuance of current or, where applicable, assumed industry conditions, including expectations regarding the duration and overall impact of COVID-19; 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; our ability to comply with our debt covenants; the availability of third party services; the extent of our liabilities; the rates used to calculate the amount of our future abandonment and reclamation costs and asset retirement obligations; the availability of technology and processes to achieve environmental targets. In addition, Enerplus' 2021 outlook contained in this news release is based on the following rest of year prices: US$69/bbl WTI, US$3.92/Mcf NYMEX, and a USD/CDN exchange rate of 1.26. Furthermore, in addition, years 2022 to 2025 of Enerplus' five-year outlook contained in this news release is based on the following: a WTI price of between US$50.00/bbl and US$55.00/bbl, a NYMEX price of US$2.75/Mcf and a USD/CDN exchange rate of 1.27. We believe 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 instability, or further deterioration, in global economic and market environment, including from COVID-19; continued low commodity price environment or further volatility in commodity prices; changes in realized prices of Enerplus' products from those currently anticipated; changes in the demand for or supply of our products; failure to realize the anticipated benefits of the Hess asset and Bruin acquisitions; unanticipated operating results, results from our capital spending activities or production declines; legal proceedings in connection with DAPL; 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; changes in law or government programs or policies in Canada or the United States; and certain other risks detailed from time to time in our public disclosure documents (including, without limitation, those risks and contingencies described under "Risk Factors and Risk Management" in Enerplus' 2020 MD&A and in our other public filings).
The purpose of our estimated free cash flow disclosure is to 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 press release speaks only as of the date of this press release, and we do not assume any obligation to publicly update or revise such forward-looking information to reflect new events or circumstances, except as may be required pursuant to applicable laws.
NON-GAAP MEASURES
In this news release, Enerplus uses the terms "adjusted funds flow", "adjusted net income", "free cash flow" "total debt net of cash" and "net debt to adjusted funds flow ratio" 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. "Adjusted net income" is calculated as net income adjusted for unrealized derivative instrument gain/loss, asset impairment, goodwill impairment, gain on divestment of assets, unrealized foreign exchange gain/loss, and the tax effect of these items. "Free cash flow" is calculated as adjusted funds flow minus capital spending. "Total debt net of cash" is calculated as senior notes plus term loan plus outstanding bank credit facility balance, minus cash and cash equivalents". "Net debt to adjusted funds flow" is calculated as total debt net of cash, including restricted cash, divided by adjusted funds flow.
Enerplus believes that, in addition to cash flow from operating activities, net earnings and other measures prescribed by U.S. GAAP, the terms "adjusted funds flow", "adjusted net income", "free cash flow", "total debt net of cash" 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' 2020 MD&A.
Electronic copies of Enerplus Corporation's Second Quarter 2021 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].
SOURCE Enerplus Corporation
Investor Contacts: Drew Mair, 403-298-1707; Krista Norlin, 403-298-4304
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