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FORM 6-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Report of Foreign Issuer pursuant to Rule 13-a-16 or 15d-16
of the Securities Exchange Act of 1934
FOR THE MONTH OF MAY, 2016
COMMISSION FILE NUMBER 1-15150
The Dome Tower
Suite 3000, 333 – 7th Avenue S.W.
Calgary, Alberta
Canada T2P 2Z1
(403) 298-2200
Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.
Form 20-F
o Form 40-F ý
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1)
Yes
o No ý
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7)
Yes
o No ý
Indicate by check mark whether, by furnishing the information contained in this Form, the registrant is also thereby furnishing the information to the Commission pursuant to
Rule 12g3-2(b) under the securities Exchange Act of 1934.
Yes
o No ý
EXHIBIT INDEX
EXHIBIT
99.1 — Management's Discussion and Analysis for the First Quarter ended March 31, 2016
EXHIBIT
99.2 — Unaudited Consolidated Financial Statements for the First Quarter ended March 31, 2016
EXHIBIT
99.3 — Certification of the Chief Executive Officer
EXHIBIT
99.4 — Certification of the Chief Financial Officer
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
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ENERPLUS CORPORATION |
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BY: |
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/s/ DAVID A. MCCOY
David A. McCoy
Vice President, General Counsel &
Corporate Secretary |
DATE: May 6, 2016
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EXHIBIT INDEX
SIGNATURE
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Exhibit 99.1
MD&A
MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A")
The following discussion and analysis of financial results is dated May 5, 2016 and is to be read in conjunction with:
- •
- the
unaudited interim consolidated financial statements of Enerplus Corporation ("Enerplus" or the "Company") as at and for the three months ended
March 31, 2016 and 2015 (the "Interim Financial Statements");
- •
- the
audited consolidated financial statements of Enerplus as at December 31, 2015 and 2014 and for the years ended December 31, 2015, 2014
and 2013 (the "Financial Statements"); and
- •
- our
MD&A for the year ended December 31, 2015 (the "Annual MD&A").
The
following MD&A contains forward-looking information and statements. We refer you to the end of the MD&A under "Forward-Looking Information and Statements" for further information. The following
MD&A also contains financial measures that do not have a standardized meaning as prescribed by accounting principles generally accepted in the United States of America ("U.S. GAAP"). See
"Non-GAAP Measures" below for further information.
BASIS OF PRESENTATION
The Interim Financial Statements and notes have been prepared in accordance with U.S. GAAP including the prior period comparatives. All amounts are
stated in Canadian dollars unless otherwise specified and all note references relate to the notes included in the Interim Financial Statements.
Where
applicable, natural gas has been converted to barrels of oil equivalent ("BOE") based on 6 Mcf:1 BOE and oil and natural gas liquids ("NGL") have been converted to
thousand cubic feet of gas equivalent ("Mcfe") based on 0.167 bbl:1 Mcfe. BOE and Mcfe measures are based on an energy equivalent conversion method primarily applicable at the
burner tip and do not represent a value equivalent at the wellhead. Given that the value ratio based on the current price of natural gas as compared to crude oil is significantly different from the
energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. Use of BOE and Mcfe in isolation may be misleading. All production volumes are
presented on a Company interest basis, being the Company's working interest share before deduction of any royalties paid to others, plus the Company's royalty interests unless otherwise stated.
Company interest is not a term defined in Canadian National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and
may not be comparable to information produced by other entities.
In
accordance with U.S. GAAP, oil and gas sales are presented net of royalties in our Interim Financial Statements. Under International Financial Reporting Standards, industry standard is to
present oil and gas sales before deduction of royalties and as such this MD&A presents production, oil and gas sales, and BOE measures on this basis to remain comparable with our peers.
NON-GAAP MEASURES
The Company utilizes the following terms for measurement within the MD&A that do not have a standardized meaning or definition as prescribed by U.S. GAAP
and therefore may not be comparable with the calculation of similar measures by other entities:
"Netback" is used by Enerplus and is useful to investors and securities analysts in evaluating operating performance of our crude oil and natural gas
assets. Netback is calculated as oil and natural gas sales less royalties, production taxes, cash operating expenses and transportation costs.
ENERPLUS 2016 Q1
REPORT 7
| Calculation of Netback |
|
Three months ended March 31,
|
|
|
| ($ millions) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
| Oil and natural gas sales |
|
$ |
170.5 |
|
|
|
$ |
244.1 |
|
|
| Less: |
|
|
|
|
|
|
|
|
|
|
| |
Royalties |
|
|
(27.8 |
) |
|
|
|
(39.1 |
) |
|
| |
Production taxes |
|
|
(7.4 |
) |
|
|
|
(10.8 |
) |
|
| |
Cash operating expenses(1) |
|
|
(72.3 |
) |
|
|
|
(86.8 |
) |
|
| |
Transportation costs |
|
|
(25.7 |
) |
|
|
|
(26.5 |
) |
|
|
|
|
| Netback before hedging |
|
$ |
37.3 |
|
|
|
$ |
80.9 |
|
|
| |
Cash gains/(losses) on derivative instruments |
|
|
39.6 |
|
|
|
|
86.8 |
|
|
|
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| Netback after hedging |
|
$ |
76.9 |
|
|
|
$ |
167.7 |
|
|
|
|
|
- (1)
- Operating
costs adjusted to exclude non-cash losses on fixed price electricity swaps of $0.3 million in the three months ended March 31, 2016 and $0.9 million in the three
months ended March 31, 2015.
"Funds Flow" is used by Enerplus and is useful to investors and securities analysts in analyzing operating
performance, leverage and liquidity. Funds flow is calculated as net cash from operating activities before asset retirement obligation expenditures and changes in non-cash operating working capital.
| Reconciliation of Cash Flow from Operating Activities to Funds Flow |
|
Three months ended March 31,
|
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| ($ millions) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
| Cash flow from operating activities |
|
$ |
69.7 |
|
|
|
$ |
131.1 |
|
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| Asset retirement obligation expenditures |
|
|
2.5 |
|
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|
3.9 |
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| Changes in non-cash operating working capital |
|
|
(30.5 |
) |
|
|
|
(25.8 |
) |
|
|
|
|
| Funds Flow |
|
$ |
41.7 |
|
|
|
$ |
109.2 |
|
|
|
|
|
"Debt to Funds Flow Ratio" is used by Enerplus and is useful to investors and securities analysts in analyzing
leverage and liquidity. The Debt to Funds Flow Ratio is calculated as total debt net of cash divided by a trailing twelve months of Funds Flow. This measure is not equivalent to Debt to Earnings
before Interest, Taxes, Depreciation and Amortization and other non-cash charges ("EBITDA") and is not a debt covenant.
"Adjusted Payout Ratio" is used by Enerplus and is useful to investors and securities analysts in analyzing operating performance, leverage and
liquidity. We calculate our Adjusted Payout Ratio as dividends plus capital and office expenditures divided by Funds Flow.
| Calculation of Adjusted Payout Ratio |
|
Three months ended March 31,
|
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| ($ millions) |
|
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2016 |
|
|
|
2015 |
|
|
|
|
| Dividends |
|
$ |
14.5 |
|
|
$ |
47.4 |
|
| Capital and office expenditures |
|
|
43.3 |
|
|
|
167.9 |
|
|
|
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| Sub-total |
|
$ |
57.8 |
|
|
$ |
215.3 |
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| Funds Flow |
|
$ |
41.7 |
|
|
$ |
109.2 |
|
|
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| Adjusted Payout Ratio (%) |
|
|
138% |
|
|
|
197% |
|
|
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|
In addition, the Company uses certain financial measures within the "Overview" and "Liquidity and Capital Resources" sections of this MD&A that do not have a
standardized meaning or definition as prescribed by U.S. GAAP and, therefore, may not be comparable with the calculation of similar measures by other entities. Such measures include "Senior
Debt to EBITDA", "Total Debt to EBITDA", "Total Debt to Capitalization", "maximum debt to consolidated present value of total proved reserves" and "EBITDA to Interest" and are used to determine the
Company's compliance with financial covenants under its bank credit facility and outstanding senior notes. Calculation of such terms is described under the "Liquidity and Capital Resources" section of
this MD&A.
8 ENERPLUS 2016 Q1
REPORT
OVERVIEW
Our strong operational performance during the first quarter, coupled with the success of our non-core asset divestment program, has allowed us to improve our
financial flexibility and balance sheet strength. We remain well positioned to meet our average annual production guidance, despite our additional second quarter asset divestment, and are revising our
operating expense, transportation cost and general and administrative ("G&A") expense guidance downwards by a combined total of $1.30/BOE to reflect cost savings to date.
Average
daily production for the first quarter totaled 97,860 BOE/day, exceeding our annual guidance range of 90,000 – 94,000 BOE/day due to
outperformance from our North Dakota wells and strong production results from our Canadian oil and natural gas properties. Compared to the fourth quarter of 2015, production decreased as a result of
divestments with associated production of approximately 3,700 BOE/day in the fourth quarter and 5,400 BOE/day during the first quarter. Despite the previously announced second quarter
sale of assets located in northwest Alberta with expected average 2016 production of 2,300 BOE/day, we are maintaining our average annual production guidance of
90,000 – 94,000 BOE/day and our liquids production guidance of 43,000 – 45,000 BOE/day.
Capital
spending is on track, with $43.3 million spent in the first quarter. We continue to expect spending of $200 million in 2016, with the majority of our investment directed to our
Fort Berthold properties.
Operating
expenses came in below guidance for the quarter, at $8.15/BOE compared to annual guidance of $9.50/BOE. Compared to the fourth quarter of 2015, operating cost savings were a result of
ongoing cost structure improvements. Based on cost savings to date, the additional divestment in the second quarter and the impact of a strengthening Canadian dollar on our U.S. dollar
denominated expenditures, we are reducing our 2016 guidance for operating expenses to $8.50/BOE.
G&A
expenses were also below guidance, totaling $2.07/BOE in the first quarter compared to annual guidance of $2.10/BOE, as a result of our staffing reductions and ongoing focus on cost control.
Accordingly, we are revising our G&A guidance downwards to $2.00/BOE.
We
continued to focus our portfolio during 2016, with first quarter asset divestment proceeds of $187.8 million, net of closing costs. Including the previously announced second quarter sale of
non-core Canadian assets, we expect total proceeds of approximately $283 million year to date and gains on dispositions of approximately $215 million. In addition, we expect these
divestments to reduce our asset retirement obligations by $22.7 million.
These
asset divestment proceeds, along with our largely undrawn bank credit facility, provided funding for the repurchase of US$172 million of our senior notes during the quarter, and a total
of US$267 million of senior notes to date. The senior note repurchases were completed at prices between 90% of par and par value resulting in an expected total gain of $19 million. At
March 31, 2016, total debt net of cash was $992.8 million, a decrease of $223.4 million compared to $1,216.2 million at December 31, 2015. Our Senior
Debt to EBITDA and Debt to Funds Flow ratios at March 31, 2016 were 1.6x and 2.3x, respectively; an improvement from 2.2x and 2.5x, respectively, at December 31, 2015.
We
reported a net loss of $173.7 million and Funds Flow of $41.7 million during the first quarter, compared to a net loss of $625.0 million and Funds Flow of $102.7 million
in the fourth quarter of 2015. Our first quarter earnings benefited from gains of $145.1 million on property divestments and $7.1 million on the repurchase of senior notes. These gains
were offset by a non-cash asset impairment charge of $46.2 million and a non-cash valuation allowance of $258.5 million on our deferred tax asset, both recorded under U.S. GAAP as
a result of the continued decline in twelve month trailing average commodity prices. Our commodity hedging program continued to provide protection, contributing total gains of
$13.5 million to earnings and cash gains of $39.6 million to Funds Flow. We continue to expect our hedging program to provide Funds Flow protection during 2016. Subsequent to the
quarter, we added downside protection on 6,000 bbls/day and 35,000 Mcf/day of our 2017 oil and natural gas production.
RESULTS OF OPERATIONS
Production
Production for the first quarter totaled 97,860 BOE/day, exceeding our average annual guidance range of
90,000 – 94,000 BOE/day. Compared to production in the fourth quarter of 2015 of 106,905 BOE/day, production was down 8% primarily due to asset
divestments, including the fourth quarter sales of non-core Canadian shallow gas properties and non-operated North Dakota properties with production of approximately 2,700 BOE/day and
1,000 BOE/day, respectively, and the first quarter 2016 sale of Canadian Deep Basin properties with production of approximately 5,400 BOE/day.
ENERPLUS 2016 Q1
REPORT 9
Production
in the first quarter of 2016 decreased 3% from production levels of 100,855 BOE/day in the same period of 2015. The decrease in production was due to the sale of non-core properties
in Canada throughout 2015 and the first quarter of 2016, which was offset by production growth of approximately 7,700 BOE/day in our Fort Berthold crude oil assets due to our ongoing
development program.
As
a result of the sale of certain non-core Canadian natural gas properties in the fourth quarter of 2015 and the sale of our Alberta Deep Basin assets during the first quarter of 2016, our crude oil
and natural gas liquids weighting increased to 46% in the first quarter of 2016
from 43% in the fourth quarter of 2015. Our crude oil and natural gas liquids production remains in line with our annual average guidance range of
43,000 – 45,000 BOE/day.
Average
daily production volumes for the three months ended March 31, 2016 and 2015 are outlined below:
| |
|
Three months ended March 31,
|
| Average Daily Production Volumes |
|
2016 |
|
|
2015 |
|
% Change |
|
|
|
|
| Crude oil (bbls/day) |
|
39,508 |
|
|
39,355 |
|
0% |
|
| Natural gas liquids (bbls/day) |
|
5,494 |
|
|
3,735 |
|
47% |
|
| Natural gas (Mcf/day) |
|
317,150 |
|
|
346,589 |
|
(8%) |
|
|
|
|
| Total daily sales (BOE/day) |
|
97,860 |
|
|
100,855 |
|
(3%) |
|
|
|
|
We are maintaining our annual average production guidance of 90,000 – 94,000 BOE/day and our liquids guidance of
43,000 – 45,000 BOE/day despite the previously announced second quarter sale of assets located in northwest Alberta with expected average 2016 production
of 2,300 BOE/day. This guidance does not contemplate any additional acquisitions or divestments.
Pricing
The prices received for our crude oil and natural gas production directly impact our earnings, Funds Flow and financial condition. The following table compares
quarterly average prices from the first quarter of 2016 to the first quarter of 2015:
| Pricing (average for the period) |
|
|
Q1 2016 |
|
|
|
|
Q4 2015 |
|
|
Q3 2015 |
|
|
Q2 2015 |
|
|
Q1 2015 |
|
|
|
|
|
| Benchmarks |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
WTI crude oil (US$/bbl) |
|
$ |
33.45 |
|
|
|
$ |
42.18 |
|
$ |
46.43 |
|
$ |
57.94 |
|
$ |
48.64 |
|
|
| |
AECO natural gas – monthly index (CDN$/Mcf) |
|
|
2.11 |
|
|
|
|
2.65 |
|
|
2.80 |
|
|
2.67 |
|
|
2.95 |
|
|
| |
AECO natural gas – daily index (CDN$/Mcf) |
|
|
1.83 |
|
|
|
|
2.47 |
|
|
2.90 |
|
|
2.64 |
|
|
2.75 |
|
|
| |
NYMEX natural gas – last day (US$/Mcf) |
|
|
2.09 |
|
|
|
|
2.27 |
|
|
2.77 |
|
|
2.64 |
|
|
2.98 |
|
|
| |
USD/CDN exchange rate |
|
|
1.37 |
|
|
|
|
1.34 |
|
|
1.31 |
|
|
1.23 |
|
|
1.24 |
|
|
Enerplus selling price(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Crude oil (CDN$/bbl) |
|
$ |
31.59 |
|
|
|
$ |
43.04 |
|
$ |
48.22 |
|
$ |
58.26 |
|
$ |
44.04 |
|
|
| |
Natural gas liquids (CDN$/bbl) |
|
|
11.34 |
|
|
|
|
16.61 |
|
|
13.51 |
|
|
20.88 |
|
|
22.48 |
|
|
| |
Natural gas (CDN$/Mcf) |
|
|
1.77 |
|
|
|
|
1.89 |
|
|
2.08 |
|
|
2.09 |
|
|
2.58 |
|
|
|
|
|
Average differentials |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
MSW Edmonton – WTI (US$/bbl) |
|
$ |
(3.69 |
) |
|
|
$ |
(2.44 |
) |
$ |
(3.42 |
) |
$ |
(3.06 |
) |
$ |
(6.80 |
) |
|
| |
WCS Hardisty – WTI (US$/bbl) |
|
|
(14.24 |
) |
|
|
|
(14.50 |
) |
|
(13.27 |
) |
|
(11.59 |
) |
|
(14.73 |
) |
|
| |
Transco Leidy monthly – NYMEX (US$/Mcf) |
|
|
(0.99 |
) |
|
|
|
(1.15 |
) |
|
(1.66 |
) |
|
(1.50 |
) |
|
(1.77 |
) |
|
| |
TGP Z4 300L monthly – NYMEX (US$/Mcf) |
|
|
(1.07 |
) |
|
|
|
(1.23 |
) |
|
(1.75 |
) |
|
(1.57 |
) |
|
(1.75 |
) |
|
| |
AECO monthly – NYMEX (US$/Mcf) |
|
|
(0.56 |
) |
|
|
|
(0.28 |
) |
|
(0.63 |
) |
|
(0.47 |
) |
|
(0.60 |
) |
|
Enerplus realized differentials(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Canada crude oil – WTI (US$/bbl) |
|
$ |
(14.14 |
) |
|
|
$ |
(13.63 |
) |
$ |
(11.82 |
) |
$ |
(12.50 |
) |
$ |
(15.22 |
) |
|
| |
Canada natural gas – NYMEX (US$/Mcf) |
|
|
(0.63 |
) |
|
|
|
(0.42 |
) |
|
(0.43 |
) |
|
(0.46 |
) |
|
(0.46 |
) |
|
| |
Bakken crude oil – WTI (US$/bbl) |
|
|
(8.38 |
) |
|
|
|
(7.93 |
) |
|
(8.52 |
) |
|
(9.30 |
) |
|
(11.65 |
) |
|
| |
Marcellus natural gas – NYMEX (US$/Mcf) |
|
|
(0.91 |
) |
|
|
|
(1.13 |
) |
|
(1.64 |
) |
|
(1.39 |
) |
|
(1.32 |
) |
|
|
|
|
- (1)
- Before
transportation costs, royalties and commodity derivative instruments.
10 ENERPLUS 2016 Q1
REPORT
CRUDE OIL AND NATURAL GAS LIQUIDS
Our realized crude oil price averaged $31.59/bbl in the first quarter, 27% lower than the previous quarter. WTI crude oil prices fell by 21% versus the previous
quarter as seasonal refinery outages combined with continued oversupply drove U.S. oil inventories to near-maximum levels. This supply imbalance pushed WTI prices to a low of US$26.05/bbl in
February before improving by the end of the quarter as refinery demand returned and there were growing indications of supply declines in North America and elsewhere. Modestly weaker crude oil
differentials in both Canada and the U.S. also contributed to the weakness in realized oil prices during the quarter.
Our
realized price for natural gas liquids fell by 32% to average $11.34/bbl in the first quarter. This was in line with benchmark prices for Canadian liquids, which fell by an average of 29% due to
weaker crude oil prices and the continued oversupply of propane in North America.
NATURAL
GAS
Our realized natural gas price averaged $1.77/Mcf in the first quarter, 6% lower than the fourth quarter of 2015. NYMEX prices fell by 8% and AECO monthly
prices fell by approximately 20% compared to the previous quarter. Both markets remained weak in response to continued high production with lower than normal seasonal demand that resulted in
significant storage surpluses across North America relative to the first quarter of 2015.
Our
overall realized natural gas price outperformed changes in NYMEX and AECO prices due to improving differentials in the Marcellus. Weaker NYMEX prices narrowed Marcellus benchmark differentials,
resulting in monthly Tennessee Gas Pipeline Zone 4 – 300 Leg and Transco Leidy prices averaging approximately US$1.03/Mcf below NYMEX. Our Marcellus
realized price differential averaged US$0.91/Mcf below NYMEX, a 19% improvement from the previous quarter. We continue to expect our realized Marcellus differentials in 2016 to improve relative to
recent years due to reduced industry spend and the continued build out of regional take-away capacity.
FOREIGN
EXCHANGE
The Canadian dollar was volatile throughout the first quarter, nearing a thirteen year low of 1.46 USD/CDN mid-January before rebounding following the
Bank of Canada's decision to keep interest rates unchanged. The foreign exchange rate averaged 1.37 USD/CDN during the quarter and was 1.30 USD/CDN at March 31, 2016. The
majority of our oil and natural gas sales are based on U.S. dollar denominated indices, and a weaker Canadian dollar relative to the U.S. dollar increases the amount of our realized
sales. Because we report in Canadian dollars, the fluctuations in the Canadian dollar also impact our U.S. dollar denominated costs, capital spending and the reported value of our
U.S. dollar denominated debt.
Price Risk Management
We have a price risk management program that considers our overall financial position, the economics of our capital program and potential acquisitions. Since
our 2015 annual report, we have added floor protection on a portion of our oil and natural gas production for 2017.
As
of May 2, 2016, we have hedged approximately 9,500 bbls/day of our expected net crude oil production for the remainder of 2016 through a combination of swaps and collars, which
represents approximately 31% of our 2016 forecasted net crude oil production, after royalties. For the second quarter of 2016 we have hedged approximately 12,700 bbls/day, which represents
approximately 41% of our 2016 forecasted net crude oil production, after royalties. For the second half of 2016 we have hedged 8,000 bbls/day, which represents approximately 26% of our 2016
forecasted net crude oil production, after royalties. We have also initiated our 2017 hedging program, with three way collars on 6,000 bbls/day. Price protection levels are shown in the table
below. When WTI prices settle below the sold put strike price in any given month, the three way collars provide protection of approximately US$14/bbl and US$12/bbl above WTI index prices in 2016 and
2017, respectively. Overall, we expect our crude oil related hedge contracts to protect a significant portion of our Funds Flow during 2016.
As
of May 2, 2016, we have downside protection on approximately 69,500 Mcf/day of our expected net natural gas production for the remainder of 2016 consisting of a combination of
NYMEX swaps and collars. This represents approximately 31% of our 2016 forecasted natural gas production, after royalties. We have also initiated a 2017 hedging program, with 35,000 Mcf/day
hedged to date using three way collars. Price protection levels are shown in the table below. When NYMEX prices settle below the sold put strike price in any given month, the three way collars provide
protection of approximately US$0.50/Mcf and US$0.67/Mcf above NYMEX index prices in 2016 and 2017, respectively.
ENERPLUS 2016 Q1
REPORT 11
The
following is a summary of our financial contracts in place at May 2, 2016, expressed as a percentage of our anticipated net 2016 and 2017 production volumes:
| |
|
WTI Crude Oil (US$/bbl)(1)
|
|
NYMEX Natural Gas (US$/Mcf)(1)
|
|
| |
|
|
Apr 1, 2016 –
Jun 30, 2016 |
|
|
Jul 1, 2016 –
Dec 31, 2016 |
|
|
Jan 1, 2017 –
Dec 31, 2017 |
|
|
Apr 1, 2016 –
Oct 31, 2016 |
|
|
Nov 1, 2016 –
Dec 31, 2016 |
|
|
Jan 1, 2017 –
Dec 31, 2017 |
|
|
| Sold Swaps |
|
$ |
64.28 |
|
|
– |
|
|
– |
|
$ |
2.53 |
|
$ |
2.48 |
|
|
– |
|
| % |
|
|
10% |
|
|
– |
|
|
– |
|
|
23% |
|
|
11% |
|
|
– |
|
Three Way Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Sold Puts |
|
$ |
50.13 |
|
$ |
49.78 |
|
$ |
35.67 |
|
$ |
2.50 |
|
$ |
2.50 |
|
$ |
2.00 |
|
| % |
|
|
26% |
|
|
26% |
|
|
20% |
|
|
11% |
|
|
11% |
|
|
16% |
|
| Purchased Puts |
|
$ |
64.38 |
|
$ |
63.98 |
|
$ |
48.18 |
|
$ |
3.00 |
|
$ |
3.00 |
|
$ |
2.67 |
|
| % |
|
|
26% |
|
|
26% |
|
|
20% |
|
|
11% |
|
|
11% |
|
|
16% |
|
| Sold Calls |
|
$ |
79.38 |
|
$ |
79.63 |
|
$ |
60.00 |
|
$ |
3.75 |
|
$ |
3.75 |
|
$ |
3.32 |
|
| % |
|
|
26% |
|
|
26% |
|
|
20% |
|
|
11% |
|
|
11% |
|
|
16% |
|
Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Sold Puts |
|
$ |
41.75 |
|
|
– |
|
|
– |
|
|
– |
|
|
– |
|
|
– |
|
| % |
|
|
5% |
|
|
– |
|
|
– |
|
|
– |
|
|
– |
|
|
– |
|
| Purchased Puts |
|
$ |
33.41 |
|
|
– |
|
|
– |
|
|
– |
|
|
– |
|
|
– |
|
| % |
|
|
5% |
|
|
– |
|
|
– |
|
|
– |
|
|
– |
|
|
– |
|
|
- (1)
- Based
on weighted average price (before premiums), assumed average annual production of 92,000 BOE/day for 2016 and 2017 less royalties and production taxes of 23.0% in aggregate.
ACCOUNTING FOR PRICE RISK MANAGEMENT
| Commodity Risk Management Gains/(Losses) |
|
Three months ended March 31,
|
| ($ millions) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
| Cash gains/(losses): |
|
|
|
|
|
|
|
|
|
|
| |
Crude oil |
|
$ |
36.6 |
|
|
|
$ |
70.6 |
|
|
| |
Natural gas |
|
|
3.0 |
|
|
|
|
16.2 |
|
|
|
|
|
| Total cash gains/(losses) |
|
$ |
39.6 |
|
|
|
$ |
86.8 |
|
|
Non-cash gains/(losses): |
|
|
|
|
|
|
|
|
|
|
| |
Change in fair value – crude oil |
|
$ |
(31.2 |
) |
|
|
$ |
(36.0 |
) |
|
| |
Change in fair value – natural gas |
|
|
5.1 |
|
|
|
|
(0.4 |
) |
|
|
|
|
| Total non-cash gains/(losses) |
|
$ |
(26.1 |
) |
|
|
$ |
(36.4 |
) |
|
|
|
|
| Total gains/(losses) |
|
$ |
13.5 |
|
|
|
$ |
50.4 |
|
|
|
|
|
| |
|
Three months ended March 31,
|
| (Per BOE) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
| Total cash gains/(losses) |
|
$ |
4.45 |
|
|
|
$ |
9.56 |
|
|
| Total non-cash gains/(losses) |
|
|
(2.94 |
) |
|
|
|
(4.01 |
) |
|
|
|
|
| Total gains/(losses) |
|
$ |
1.51 |
|
|
|
$ |
5.55 |
|
|
|
|
|
During the first quarter of 2016 we realized cash gains of $36.6 million on our crude oil contracts and $3.0 million on our natural gas contracts.
In comparison, during the first quarter of 2015 we realized cash gains of $70.6 million on our crude oil contracts and $16.2 million on our natural gas contracts. The cash gains in 2016
and 2015 were due to contracts which provided floor protection above market prices.
As
the forward markets for crude oil and natural gas fluctuate and new contracts are executed and existing contracts are realized, changes in fair value are reflected as either a non-cash charge or
gain to earnings. At the end of the first quarter of 2016, the fair value of our crude oil and natural gas contracts represented net gain positions of $36.1 million and $9.2 million,
respectively. The change in the fair value of our crude oil and natural gas contracts during the first quarter of 2016 represented losses of $31.2 million and gains of $5.1 million,
respectively.
12 ENERPLUS 2016 Q1
REPORT
Revenues
| |
|
Three months ended March 31,
|
| ($ millions) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
| Oil and natural gas sales |
|
$ |
170.5 |
|
|
|
$ |
244.1 |
|
|
| Royalties |
|
|
(27.8 |
) |
|
|
|
(39.1 |
) |
|
|
|
|
| Oil and natural gas sales, net of royalties |
|
$ |
142.7 |
|
|
|
$ |
205.0 |
|
|
|
|
|
Oil and natural gas revenues were $170.5 million in the first quarter of 2016, a decrease of 30% or $73.6 million compared to the same period in
2015. The decrease in revenue was a result of the decline in oil and natural gas prices over the period, along with a decrease in natural gas production due to asset divestments.
Royalties and Production Taxes
| |
|
Three months ended March 31,
|
| ($ millions, except per BOE amounts) |
|
|
2016 |
|
|
|
2015 |
|
|
|
|
| Royalties |
|
$ |
27.8 |
|
|
$ |
39.1 |
|
| Per BOE |
|
$ |
3.12 |
|
|
$ |
4.31 |
|
Production taxes |
|
$ |
7.4 |
|
|
$ |
10.8 |
|
| Per BOE |
|
$ |
0.83 |
|
|
$ |
1.19 |
|
|
|
|
| Royalties and production taxes |
|
$ |
35.2 |
|
|
$ |
49.9 |
|
| Per BOE |
|
$ |
3.95 |
|
|
$ |
5.50 |
|
Royalties and production taxes
(% of oil and natural gas sales, before transportation) |
|
|
21% |
|
|
|
20% |
|
|
|
|
Royalties are paid to government entities, land owners and mineral rights owners. Production taxes include state production taxes, Pennsylvania impact fees,
freehold mineral taxes and Saskatchewan resource surcharges. A large percentage of our production is from U.S. properties where royalty rates are generally not as sensitive to commodity price
levels. During the first quarter of 2016 royalties and production taxes decreased to $35.2 million from $49.9 million in the same quarter of 2015, primarily due to lower realized prices
and lower production volumes. Royalties and production taxes averaged 21% of oil and natural gas sales before transportation costs in 2016 compared to 20% for the same period in 2015 due to increased
production from U.S. properties.
We
continue to expect an average royalty and production tax rate of 23% in 2016. At this time, we do not expect the recently announced Alberta modernized royalty framework to have a significant impact
on our Canadian royalties when it becomes effective in 2017; however, we continue to actively monitor the changes being proposed.
Operating Expenses
| |
|
Three months ended March 31,
|
| ($ millions, except per BOE amounts) |
|
|
2016 |
|
|
|
2015 |
|
|
|
|
| Operating expenses |
|
$ |
72.6 |
|
|
$ |
87.7 |
|
| Per BOE |
|
$ |
8.15 |
|
|
$ |
9.66 |
|
|
|
|
Operating expenses for the first quarter of 2016 totaled $72.6 million compared to $87.7 million for the same period in 2015. On a per BOE basis,
operating expenses were $8.15/BOE, beating our annual guidance of $9.50/BOE and a 16% reduction from the same period in 2015. The decrease compared to the first quarter of 2015 was a result of
successful cost saving initiatives, less repairs and maintenance due to favourable winter conditions and the divestment of Canadian properties with higher operating costs throughout 2015.
Based
on our cost savings to date, a stronger Canadian dollar and the recently announced divestment of our higher cost northwest Alberta assets, we are reducing our 2016 guidance for operating
expenses to $8.50/BOE from $9.50/BOE.
ENERPLUS 2016 Q1
REPORT 13
Transportation Costs
| |
|
Three months ended March 31,
|
| ($ millions, except per BOE amounts) |
|
|
2016 |
|
|
|
2015 |
|
|
|
|
| Transportation costs |
|
$ |
25.7 |
|
|
$ |
26.5 |
|
| Per BOE |
|
$ |
2.89 |
|
|
$ |
2.92 |
|
|
|
|
For the three months ended March 31, 2016, transportation costs were $25.7 million or $2.89/BOE compared to $26.5 million or
$2.92/BOE for the same period in 2015.
As
a result of the impact of a stronger Canadian dollar on our U.S. dollar denominated transportation costs, we are revising our annual 2016 transportation cost guidance to $3.10/BOE
from $3.30/BOE.
Netbacks
The crude oil and natural gas classifications below contain properties according to their dominant production category. These properties may include associated
crude oil, natural gas or natural gas liquids volumes which have been converted to the equivalent BOE/day or Mcfe/day and as such, the revenue per BOE or per Mcfe may not correspond with the average
selling price under the "Pricing" section of this MD&A.
| |
|
Three months ended March 31, 2016
|
| Netbacks by Property Type |
|
|
Crude Oil |
|
|
Natural Gas |
|
|
Total |
|
|
|
| Average Daily Production |
|
|
48,280 BOE/day |
|
|
297,480 Mcfe/day |
|
|
97,860 BOE/day |
|
|
|
| |
Netback(1) $ per BOE or Mcfe |
|
|
(per BOE |
) |
|
(per Mcfe |
) |
|
(per BOE |
) |
|
|
| |
Oil and natural gas sales |
|
$ |
27.54 |
|
$ |
1.83 |
|
$ |
19.14 |
|
|
| |
Royalties and production taxes |
|
|
(6.43 |
) |
|
(0.26 |
) |
|
(3.95 |
) |
|
| |
Cash operating expenses |
|
|
(10.17 |
) |
|
(1.02 |
) |
|
(8.12 |
) |
|
| |
Transportation costs |
|
|
(1.87 |
) |
|
(0.65 |
) |
|
(2.89 |
) |
|
|
| |
Netback before hedging |
|
$ |
9.07 |
|
$ |
(0.10 |
) |
$ |
4.18 |
|
|
|
| |
Cash gains/(losses) |
|
|
8.32 |
|
|
0.11 |
|
|
4.45 |
|
|
|
| |
Netback after hedging |
|
$ |
17.39 |
|
$ |
0.01 |
|
$ |
8.63 |
|
|
|
| |
Netback before hedging ($ millions) |
|
$ |
39.9 |
|
$ |
(2.6 |
) |
$ |
37.3 |
|
|
|
| |
Netback after hedging ($ millions) |
|
$ |
76.5 |
|
$ |
0.4 |
|
$ |
76.9 |
|
|
|
| |
|
Three months ended March 31, 2015
|
| Netbacks by Property Type |
|
|
Crude Oil |
|
|
Natural Gas |
|
|
Total |
|
|
|
| Average Daily Production |
|
|
44,758 BOE/day |
|
|
336,582 Mcfe/day |
|
|
100,855 BOE/day |
|
|
|
| |
Netback(1) $ per BOE or Mcfe |
|
|
(per BOE |
) |
|
(per Mcfe |
) |
|
(per BOE |
) |
|
|
| |
Oil and natural gas sales |
|
$ |
38.99 |
|
$ |
2.87 |
|
$ |
26.89 |
|
|
| |
Royalties and production taxes |
|
|
(9.71 |
) |
|
(0.36 |
) |
|
(5.50 |
) |
|
| |
Cash operating expenses |
|
|
(13.45 |
) |
|
(1.08 |
) |
|
(9.56 |
) |
|
| |
Transportation costs |
|
|
(1.98 |
) |
|
(0.60 |
) |
|
(2.92 |
) |
|
|
| |
Netback before hedging |
|
$ |
13.85 |
|
$ |
0.83 |
|
$ |
8.91 |
|
|
|
| |
Cash gains/(losses) |
|
|
17.52 |
|
|
0.54 |
|
|
9.56 |
|
|
|
| |
Netback after hedging |
|
$ |
31.37 |
|
$ |
1.37 |
|
$ |
18.47 |
|
|
|
| |
Netback before hedging ($ millions) |
|
$ |
55.8 |
|
$ |
25.1 |
|
$ |
80.9 |
|
|
|
| |
Netback after hedging ($ millions) |
|
$ |
126.4 |
|
$ |
41.3 |
|
$ |
167.7 |
|
|
|
- (1)
- See
"Non-GAAP Measures" in this MD&A.
14 ENERPLUS 2016 Q1
REPORT
Crude oil and natural gas netbacks per BOE decreased during the first quarter of 2016 compared to the same period in 2015 as a result of a significant decline
in commodity prices. Realized cash hedging gains helped to offset the impact of lower prices.
General and Administrative Expenses
Total G&A expenses include cash G&A expenses as well as share-based compensation ("SBC") charges related to our long-term incentive plans ("LTI plans")
and our stock option plan (see Note 14 to the Interim Financial Statements for further details).
| |
|
Three months ended March 31,
|
| ($ millions) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
| Cash: |
|
|
|
|
|
|
|
|
|
|
| |
G&A expense |
|
$ |
18.4 |
|
|
|
$ |
21.4 |
|
|
| |
Share-based compensation |
|
|
0.7 |
|
|
|
|
7.3 |
|
|
Non-Cash: |
|
|
|
|
|
|
|
|
|
|
| |
Share-based compensation |
|
|
3.4 |
|
|
|
|
5.0 |
|
|
| |
Equity swap gain |
|
|
(0.1 |
) |
|
|
|
(1.6 |
) |
|
|
|
|
| Total G&A expenses |
|
$ |
22.4 |
|
|
|
$ |
32.1 |
|
|
|
|
|
| |
|
Three months ended March 31,
|
| (Per BOE) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
| Cash: |
|
|
|
|
|
|
|
|
|
|
| |
G&A expense |
|
$ |
2.07 |
|
|
|
$ |
2.36 |
|
|
| |
Share-based compensation |
|
|
0.08 |
|
|
|
|
0.80 |
|
|
Non-Cash: |
|
|
|
|
|
|
|
|
|
|
| |
Share-based compensation |
|
|
0.39 |
|
|
|
|
0.55 |
|
|
| |
Equity swap gain |
|
|
(0.02 |
) |
|
|
|
(0.18 |
) |
|
|
|
|
| Total G&A expenses |
|
$ |
2.52 |
|
|
|
$ |
3.53 |
|
|
|
|
|
Cash G&A expenses during the first quarter of 2016 were $18.4 million ($2.07/BOE), beating guidance of $2.10/BOE and lower than $21.4 million
($2.36/BOE) in the first quarter of 2015. The decrease in cash G&A was primarily due to the reduction in staff levels of approximately 20% throughout 2015, offset by additional one-time severance
payments during the first quarter of 2016 as we continued to adjust staffing levels in response to a challenging commodity price environment.
Cash
SBC expense was $0.7 million ($0.08/BOE) in the first quarter of 2016 compared to $7.3 million ($0.80/BOE) during same period in 2015 as we settled the final grants of our
cash-settled Restricted Share Unit ("RSU") plans. The Director Share Unit ("DSU") plan is our only remaining cash-settled LTI plan.
We
recorded non-cash SBC of $3.4 million ($0.39/BOE) in the first quarter of 2016 compared to $5.0 million ($0.55/BOE) during the same period in 2015. The decrease in non-cash SBC over
the same period in 2015 was due to reduced staff levels and a decrease in our 2016 treasury-settled SBC grant as a result of current economic conditions.
We
previously hedged a portion of the outstanding cash settled grants under our LTI plans. As a result of the increase in our share price since year end, we recorded a non-cash mark-to-market gain of
$0.1 million on these hedges during the first quarter of 2016. As of March 31, 2016, we had 470,000 units hedged at a weighted average price of $16.89/share.
Based
on staff reductions and our continued focus on cost control, we are reducing our 2016 guidance for cash G&A expenses to $2.00/BOE from $2.10/BOE.
ENERPLUS 2016 Q1
REPORT 15
Interest Expense
| |
|
Three months ended March 31,
|
| ($ millions) |
|
|
2016 |
|
|
|
2015 |
|
|
|
|
| Interest on senior notes and bank facility |
|
$ |
14.5 |
|
|
$ |
16.8 |
|
| Non-cash interest expense |
|
|
0.2 |
|
|
|
0.2 |
|
|
|
|
| Total interest expense |
|
$ |
14.7 |
|
|
$ |
17.0 |
|
|
|
|
We recorded total interest expense of $14.7 million during the first quarter of 2016 compared to $17.0 million for the same period in 2015. The
decrease in interest expense corresponds to a decrease in the aggregate principal amount of our outstanding senior notes with higher fixed rates following our repurchase of US$172.0 million of
senior notes during the first quarter. The repurchase of the senior notes was funded by both asset divestment proceeds and lower interest rate bank debt. Subsequent to the quarter, we repurchased an
additional US$95 million of senior notes. In total, we have repurchased US$267 million of senior notes to date at prices ranging from 90% to par value. As a result of these optional
prepayments, we expect to save approximately US$13 million in interest expense on an annualized basis.
At
March 31, 2016, approximately 85% of our debt was based on fixed interest rates and 15% on floating interest rates, with a weighted average interest rate of 4.8% and a borrowing rate
of 2.5%, respectively.
Foreign Exchange
| |
|
Three months ended March 31,
|
| ($ millions) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
| Realized loss/(gain) |
|
$ |
1.8 |
|
|
|
$ |
(35.6 |
) |
|
| Unrealized loss/(gain) |
|
|
(56.2 |
) |
|
|
|
139.8 |
|
|
|
|
|
| Total foreign exchange loss/(gain) |
|
$ |
(54.4 |
) |
|
|
$ |
104.2 |
|
|
|
|
|
| USD/CDN exchange rate |
|
|
1.37 |
|
|
|
|
1.24 |
|
|
|
|
|
We recorded a net foreign exchange gain of $54.4 million during the first quarter of 2016 compared to a loss of $104.2 million for the same period
in 2015. Realized losses of $1.8 million recorded during the first quarter of 2016 related to day-to-day transactions recorded in foreign currencies. During the first quarter of 2015, we
realized a foreign exchange gain of $35.6 million primarily as a result of a $39.9 million gain on the unwind of certain foreign exchange swaps.
Unrealized
foreign exchange gains and losses are recorded on the translation of our U.S. dollar denominated debt and working capital at each period end. At March 31, 2016, the
Canadian dollar strengthened relative to the U.S. dollar compared to December 31, 2015, resulting in unrealized gains of $56.2 million. See Note 12 to the
Interim Financial Statements for further details.
Capital Investment
| |
|
Three months ended March 31,
|
| ($ millions) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
| Capital spending |
|
$ |
43.3 |
|
|
|
$ |
167.0 |
|
|
| Office capital |
|
|
– |
|
|
|
|
0.9 |
|
|
|
|
|
| Sub-total |
|
|
43.3 |
|
|
|
|
167.9 |
|
|
|
|
|
| Property and land acquisitions |
|
$ |
3.6 |
|
|
|
$ |
(0.2 |
) |
|
| Property divestments |
|
|
(187.8 |
) |
|
|
|
(3.7 |
) |
|
|
|
|
| Sub-total |
|
|
(184.2 |
) |
|
|
|
(3.9 |
) |
|
|
|
|
| Total |
|
$ |
(140.9 |
) |
|
|
$ |
164.0 |
|
|
|
|
|
16 ENERPLUS 2016 Q1
REPORT
Capital spending for the first quarter of 2016 totaled $43.3 million compared to $167.0 million during the same period in 2015. Despite our
reduced capital spending we continued to invest modestly in our core areas, with spending of $19.8 million on our Fort Berthold crude oil properties, $19.1 million on our Canadian crude
properties and $3.5 million on our Marcellus assets.
During
the first quarter of 2016, we completed several property divestments for combined proceeds of $187.8 million, net of closing costs, including the sale of certain Canadian Deep Basin
properties located in Alberta with production of approximately 5,400 BOE/day. During the first quarter of 2015, property divestments totaled $3.7 million and consisted of minor non-core
undeveloped lands.
Subsequent
to the quarter, we entered into an agreement to sell certain non-core properties located in northwest Alberta, including our Pouce Coupe assets, for proceeds of approximately
$95.5 million, subject to closing costs, and with estimated 2016 production of approximately 2,300 BOE/day. We expect the sale to close during the second quarter. Including this
divestment, we expect year to date divestment proceeds of approximately $283.3 million.
We
continue to expect annual capital spending of $200 million.
Gain on Asset Sales and Note Repurchases
We recorded a gain of $145.1 million on the sale of certain oil and natural gas properties during the first quarter of 2016. We expect to record an
additional gain of approximately $70 million on the previously announced second quarter sale of non-core properties in northwest Alberta, bringing our year to date gain on asset divestments to
approximately $215 million. Under full cost accounting rules, divestitures of oil and natural gas properties are generally accounted for as adjustments to the full cost pool with no recognition
of a gain or loss. However, if not recognizing a gain or loss on the transaction would significantly alter the relationship between a cost centre's capitalized costs and proved reserves, then a gain
or loss must be recognized. Gains and losses are evaluated on a case by case basis for each asset sale, and future sales may or may not result in such treatment.
During
the first quarter of 2016, we recorded a gain of $7.1 million on the repurchase of US$172 million of outstanding senior notes at a discount to par value. Subsequent to the
quarter, we repurchased an additional US$95 million of senior notes at a price of 90% of par value, which we expect to result in a gain of approximately $12 million during the
second quarter.
Depletion, Depreciation and Accretion ("DD&A")
| |
|
Three months ended March 31,
|
| ($ millions, except per BOE amounts) |
|
|
2016 |
|
|
|
2015 |
|
|
|
|
| DD&A expense |
|
$ |
91.2 |
|
|
$ |
132.4 |
|
| Per BOE |
|
$ |
10.24 |
|
|
$ |
14.58 |
|
|
|
|
DD&A of property, plant and equipment ("PP&E") is recognized using the unit-of-production method based on proved reserves. For the three months ended
March 31, 2016, DD&A was $91.2 million compared to $132.4 million for the same period in 2015. The decrease is primarily due to the cumulative effect of impairments
recorded during 2015.
Impairment
Under U.S. GAAP, the full cost ceiling test is performed on a country-by-country basis using estimated after-tax future net cash flows discounted at
10 percent from proved reserves using SEC constant prices ("Standardized Measure"). SEC prices are calculated as the unweighted average of the trailing twelve first-day-of-the-month commodity
prices. The Standardized Measure is not related to Enerplus' investment criteria and is not a fair value based measurement, but rather a prescribed accounting calculation. Under U.S. GAAP
impairments are not reversed in future periods.
The
trailing twelve month average crude oil and natural gas prices decreased significantly during 2015 and into the first quarter of 2016 resulting in non-cash impairments. For the three months ended
March 31, 2016, we recorded an impairment of $46.2 million in the U.S. cost centre compared to $267.6 in the same period of 2015. No impairment was recorded to the Canadian
cost centre in the first quarter of 2016 or 2015.
ENERPLUS 2016 Q1
REPORT 17
Many factors influence the allowed ceiling value versus our net capitalized cost base, making it difficult to predict with reasonable certainty the value of impairment losses from future ceiling
tests. For the remainder of this year, the primary factors include future first-day-of-the-month commodity prices, reserves revisions, our capital expenditure levels and timing, acquisition and
divestment activity, as well as production levels, which affect DD&A expense. We expect the twelve month trailing prices to decline further during 2016, impacting the ceiling value and resulting in
further non-cash impairments. See Note 5 to the Interim Financial Statements for trailing twelve month prices.
Asset Retirement Obligation
In connection with our operations we incur abandonment and reclamation costs related to assets such as surface leases, wells, facilities and pipelines. Total
asset retirement obligations included on our balance sheet are based on our net ownership interest and management's estimate of costs to abandon and reclaim and the timing of the costs to be incurred
in future periods. We have estimated the net present value of our asset retirement obligation to be $197.2 million at March 31, 2016, compared to $206.4 million at
December 31, 2015. During the first quarter of 2016, asset retirement obligation settlements were $2.5 million and asset retirement obligations removed due to divestments were
$10.0 million compared to $3.9 million and nil, respectively, for the same period in 2015. As a result of divestments year to date, including the previously announced second quarter sale
of certain non-core assets in northwest Alberta, we expect to reduce our asset retirement obligation by $22.7 million or 12%. See Note 8 to the Interim Financial Statements for
further details.
Income Taxes
| |
|
Three months ended March 31,
|
| ($ millions) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
| Current tax expense/(recovery) |
|
$ |
(0.2 |
) |
|
|
$ |
0.1 |
|
|
| Deferred tax expense/(recovery) |
|
|
256.5 |
|
|
|
|
(138.4 |
) |
|
|
|
|
| Total tax expense/(recovery) |
|
$ |
256.3 |
|
|
|
$ |
(138.3 |
) |
|
|
|
|
We recorded a total tax expense of $256.3 million during the first quarter of 2016 compared to a $138.3 million total tax recovery for the same
period in 2015. The current quarter expense includes an additional valuation allowance of $258.5 million recorded against our deferred income tax asset. The recovery in the first quarter of
2015 is due to a non-cash asset impairment expense recorded in the U.S. cost centre. We assess the recoverability of our deferred income tax assets each period to determine whether it is more
likely than not that all or a portion of our deferred income tax assets will be realized. Our assessment is primarily based on a projection of undiscounted future taxable income using historical
trailing twelve months benchmark prices. After recording the valuation allowance, our overall net deferred income tax asset was $237.1 million at March 31, 2016
(December 31, 2015 – $516.1 million).
LIQUIDITY AND CAPITAL RESOURCES
There are numerous factors that influence how we assess our liquidity and leverage including commodity price cycles, capital spending levels, acquisition and
divestment plans, hedging and dividend levels. We also assess our leverage relative to our most restrictive debt covenant under our bank credit facility and senior notes, which is a senior debt to
EBITDA threshold of 3.5x for a period of up to six months, after which it drops to 3.0x. At March 31, 2016, our senior debt to EBITDA ratio was 1.6x and our Debt to Funds Flow Ratio was
2.3x. Although it is not included in our debt covenants, the Debt to Funds Flow Ratio is often used by investors and analysts to evaluate our liquidity.
We
have continued to be diligent in managing and preserving our financial position in 2016. Our non-core asset divestment program continued to provide significant liquidity, with proceeds of
$187.8 million during the first quarter and total proceeds of approximately $283 million to date, including the previously announced second quarter sale of non-core Canadian assets.
These proceeds, along with our largely undrawn bank credit facility, were used to fund the repurchase of US$172 million of our senior notes during the quarter, and a total of
US$267 million of senior notes to date. The repurchases were completed at prices ranging from 90% to par value, resulting in a total gain of $19 million. These gains, combined with year
to date gains on asset sales of approximately $215 million, are expected to meaningfully improve our 2016 EBITDA. Furthermore, as a result of replacing fixed term, higher interest rate senior
notes with lower interest rate bank debt and using divestment proceeds to repay outstanding debt, we expect to save approximately US$13 million in interest expense on an annualized basis.
Utilizing a
18 ENERPLUS 2016 Q1
REPORT
portion
of our bank credit facility in place of the senior notes provides additional flexibility within our capital structure to reduce our leverage further as cash becomes available.
At
March 31, 2016, total debt net of cash was $992.8 million, comprised of $149.6 million of bank indebtedness and $844.5 million of senior notes less
$1.3 million in cash, compared to $1,216.2 million at December 31, 2015, comprised of $86.5 million of bank indebtedness and $1,137.1 million of senior notes
less $7.5 million in cash. At March 31, 2016, we were approximately 19% drawn on our $800 million bank credit facility.
In
addition to our non-core asset divestment program and debt management strategy, we continued to maintain our financial flexibility through an ongoing focus on cost efficiencies, disciplined capital
spending and our previously announced reduction in monthly dividends to $0.01 per share, effective with our April 2016 payment. Our Adjusted Payout Ratio, which is calculated as cash dividends
plus capital and office expenditures divided by Funds Flow, was 138% in the first quarter of 2016, compared to 197% for the same period in 2015. After adjusting for net acquisition and divestment
proceeds, we had a funding surplus of $168.1 million, which we used to reduce our outstanding debt.
Our
working capital deficiency, excluding cash and current deferred assets and liabilities, decreased to $85.2 million at March 31, 2016 from $104.0 million at
December 31, 2015. We expect to finance our working capital deficit and our ongoing working capital requirements through Funds Flow and our bank credit facility. Furthermore, we have
sufficient liquidity to meet our financial commitments, as disclosed under "Commitments" in the Annual MD&A.
At
March 31, 2016, we were in compliance with all covenants under our bank credit facility and outstanding senior notes. Based on our current guidance, we expect to manage our business
within these financial ratios; however, current oil and gas prices have created a significant level of uncertainty which may challenge the assumptions and estimates used in Management's forecast. If
we exceed any of the covenants, we may be required to repay, refinance or renegotiate the terms of the debt. If we reach or exceed these covenant thresholds, there are a number of steps that may be
taken to improve them, including asset divestments, a reduction to capital spending and equity issuances.
Our
bank credit facility and senior note purchase agreements have been filed as material documents on our SEDAR profile at www.sedar.com.
The
following table lists our financial covenants as at March 31, 2016:
| Covenant Description |
|
|
|
|
March 31, 2016 |
|
|
|
|
| Bank Credit Facility: |
|
Maximum Ratio |
|
|
|
|
| Senior Debt to EBITDA |
|
3.5 x |
|
|
1.6 x |
|
| Total Debt to EBITDA |
|
4.0 x |
|
|
1.6 x |
|
| Total Debt to Capitalization |
|
50% |
|
|
36% |
|
Senior Notes: |
|
Maximum Ratio |
|
|
|
|
| Senior Debt to EBITDA(1) |
|
3.0 x – 3.5 x |
|
|
1.6 x |
|
| Maximum debt to consolidated present value of total proved reserves(2) |
|
60% |
|
|
43% |
|
|
|
Minimum Ratio |
|
|
|
|
| EBITDA to Interest |
|
4.0 x |
|
|
9.6 x |
|
|
|
|
Definitions
"Senior Debt" is calculated as the sum of drawn amounts on our bank credit facility, outstanding letters of credit and the principal amount of
senior notes.
"EBITDA" is calculated as net income less interest, taxes, depletion, depreciation, amortization, accretion and non-cash
gains and losses. EBITDA is calculated on a trailing twelve month basis and is adjusted for material acquisitions and divestments. EBITDA for the three months and the trailing twelve months ended
March 31, 2016 were $208.1 million and $613.7 million, respectively.
"Total Debt" is calculated as the sum of Senior Debt plus subordinated debt. Enerplus currently does not have any
subordinated debt.
"Capitalization" is calculated as the sum of total debt and shareholder's equity plus a $1.1 billion adjustment
related to our adoption of U.S. GAAP.
Footnotes
- (1)
- Senior Debt to EBITDA maximum ratio for the senior notes may increase to 3.5x for a period of 6 months, after which the ratio decreases
to 3.0x.
- (2)
- Maximum
debt to consolidated present value of total proved reserves is calculated annually on December 31 based on before tax reserves at forecast prices discounted
at 10%.
Dividends
| |
|
Three months ended March 31,
|
| ($ millions, except per share amounts) |
|
|
2016 |
|
|
|
2015 |
|
|
|
|
| Dividends to shareholders |
|
$ |
14.5 |
|
|
$ |
47.4 |
|
| Per weighted average share (Basic) |
|
$ |
0.07 |
|
|
$ |
0.23 |
|
|
|
|
ENERPLUS 2016 Q1
REPORT 19
We reported a total of $14.5 million or $0.07 per share in dividends to our shareholders in the first quarter of 2016 compared to $47.4 million or
$0.23 per share in the first quarter of 2015.
Effective
with the April 2016 payment, we reduced the monthly dividend by 67% from $0.03 per share to $0.01 per share to provide additional financial flexibility and to balance Funds Flow with
capital and dividends. The dividend is an important part of our strategy to create shareholder value and we will continue to monitor commodity prices and economic conditions and are prepared to make
adjustments as necessary.
Shareholders' Capital
| |
|
Three months ended March 31,
|
| |
|
|
2016 |
|
|
|
2015 |
|
|
|
|
| Share capital ($ millions) |
|
$ |
3,142.9 |
|
|
$ |
3,125.9 |
|
Common shares outstanding (thousands) |
|
|
207,133 |
|
|
|
206,179 |
|
| Weighted average shares outstanding – basic (thousands) |
|
|
206,716 |
|
|
|
205,845 |
|
| Weighted average shares outstanding – diluted (thousands) |
|
|
206,716 |
|
|
|
205,845 |
|
|
|
|
During the first quarter of 2016 a total 594,000 shares and $9.4 million of additional equity was issued pursuant to the treasury-settled RSU
plan. In comparison, during the first quarter of 2015 a total of 447,000 shares and $5.7 million of additional equity was issued pursuant to the stock option plan and the treasury
settled RSU plan. For further details see Note 14 to the Interim Financial Statements.
At
March 31, 2016 and May 5, 2016 we had 207,133,000 shares outstanding (2015 – 206,179,000).
SELECTED QUARTERLY CANADIAN AND U.S. FINANCIAL RESULTS
| |
|
Three months ended March 31, 2016
|
|
Three months ended March 31, 2015
|
| ($ millions, except per unit amounts) |
|
|
Canada |
|
|
U.S. |
|
|
Total |
|
|
|
|
Canada |
|
|
U.S. |
|
|
Total |
|
|
|
|
|
| Average Daily Production Volumes(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Crude oil (bbls/day) |
|
|
14,186 |
|
|
25,322 |
|
|
39,508 |
|
|
|
|
16,973 |
|
|
22,382 |
|
|
39,355 |
|
|
| |
Natural gas liquids (bbls/day) |
|
|
1,804 |
|
|
3,690 |
|
|
5,494 |
|
|
|
|
2,359 |
|
|
1,376 |
|
|
3,735 |
|
|
| |
Natural gas (Mcf/day) |
|
|
99,539 |
|
|
217,611 |
|
|
317,150 |
|
|
|
|
135,419 |
|
|
211,170 |
|
|
346,589 |
|
|
| |
|
|
|
|
| |
Total average daily production (BOE/day) |
|
|
32,580 |
|
|
65,280 |
|
|
97,860 |
|
|
|
|
41,902 |
|
|
58,953 |
|
|
100,855 |
|
|
| |
|
|
|
|
| Pricing(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Crude oil (per bbl) |
|
$ |
26.55 |
|
$ |
34.42 |
|
$ |
31.59 |
|
|
|
$ |
41.47 |
|
$ |
45.99 |
|
$ |
44.04 |
|
|
| |
Natural gas liquids (per bbl) |
|
|
24.98 |
|
|
4.68 |
|
|
11.34 |
|
|
|
|
29.14 |
|
|
11.06 |
|
|
22.48 |
|
|
| |
Natural gas (per Mcf) |
|
|
2.01 |
|
|
1.66 |
|
|
1.77 |
|
|
|
|
3.13 |
|
|
2.22 |
|
|
2.58 |
|
|
Capital Expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Capital spending |
|
$ |
19.1 |
|
$ |
24.2 |
|
$ |
43.3 |
|
|
|
$ |
76.9 |
|
$ |
90.1 |
|
$ |
167.0 |
|
|
| |
Acquisitions |
|
|
1.0 |
|
|
2.6 |
|
|
3.6 |
|
|
|
|
1.2 |
|
|
(1.4 |
) |
|
(0.2 |
) |
|
| |
Divestments |
|
|
(188.3 |
) |
|
0.5 |
|
|
(187.8 |
) |
|
|
|
(1.0 |
) |
|
(2.7 |
) |
|
(3.7 |
) |
|
Netback(3) Before Hedging |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Oil and natural gas sales |
|
$ |
56.7 |
|
$ |
113.8 |
|
$ |
170.5 |
|
|
|
$ |
107.9 |
|
$ |
136.2 |
|
$ |
244.1 |
|
|
| |
Royalties |
|
|
(5.4 |
) |
|
(22.4 |
) |
|
(27.8 |
) |
|
|
|
(12.4 |
) |
|
(26.7 |
) |
|
(39.1 |
) |
|
| |
Production taxes |
|
|
(0.8 |
) |
|
(6.6 |
) |
|
(7.4 |
) |
|
|
|
(1.8 |
) |
|
(9.0 |
) |
|
(10.8 |
) |
|
| |
Cash operating expenses |
|
|
(43.5 |
) |
|
(28.8 |
) |
|
(72.3 |
) |
|
|
|
(57.0 |
) |
|
(29.8 |
) |
|
(86.8 |
) |
|
| |
Transportation costs |
|
|
(3.6 |
) |
|
(22.1 |
) |
|
(25.7 |
) |
|
|
|
(6.2 |
) |
|
(20.3 |
) |
|
(26.5 |
) |
|
| |
|
|
|
|
| |
Netback before hedging |
|
$ |
3.4 |
|
$ |
33.9 |
|
$ |
37.3 |
|
|
|
$ |
30.5 |
|
$ |
50.4 |
|
$ |
80.9 |
|
|
| |
|
|
|
|
Other Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Commodity derivative instruments loss/(gain) |
|
$ |
(13.5 |
) |
$ |
– |
|
$ |
(13.5 |
) |
|
|
$ |
(50.4 |
) |
$ |
– |
|
$ |
(50.4 |
) |
|
| |
General and administrative expense(4) |
|
|
18.3 |
|
|
4.1 |
|
|
22.4 |
|
|
|
|
23.5 |
|
|
8.6 |
|
|
32.1 |
|
|
| |
Current income tax expense/(recovery) |
|
|
(0.3 |
) |
|
0.1 |
|
|
(0.2 |
) |
|
|
|
– |
|
|
0.1 |
|
|
0.1 |
|
|
|
|
|
- (1)
- Company
interest volumes.
- (2)
- Before
transportation costs, royalties and the effects of commodity derivative instruments.
- (3)
- See
"Non-GAAP Measures" section in this MD&A.
- (4)
- Includes
share-based compensation.
20 ENERPLUS 2016 Q1
REPORT
QUARTERLY FINANCIAL INFORMATION
| |
|
|
Oil and
Natural Gas
Sales, Net of |
|
|
Net |
|
Net Income/(Loss) Per Share
|
|
|
| ($ millions, except per share amounts) |
|
|
Royalties |
|
|
Income/(Loss) |
|
|
Basic |
|
|
Diluted |
|
|
|
| 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| First Quarter |
|
$ |
142.7 |
|
$ |
(173.7 |
) |
$ |
(0.84 |
) |
$ |
(0.84 |
) |
|
|
| 2015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Fourth Quarter |
|
$ |
199.4 |
|
$ |
(625.0 |
) |
$ |
(3.03 |
) |
$ |
(3.03 |
) |
|
| Third Quarter |
|
|
228.3 |
|
|
(292.7 |
) |
|
(1.42 |
) |
|
(1.42 |
) |
|
| Second Quarter |
|
|
251.7 |
|
|
(312.5 |
) |
|
(1.52 |
) |
|
(1.52 |
) |
|
| First Quarter |
|
|
205.0 |
|
|
(293.2 |
) |
|
(1.42 |
) |
|
(1.42 |
) |
|
|
|
|
|
|
|
|
|
|
| Total 2015 |
|
$ |
884.4 |
|
$ |
(1,523.4 |
) |
$ |
(7.39 |
) |
$ |
(7.39 |
) |
|
|
| 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Fourth Quarter |
|
$ |
325.3 |
|
$ |
151.7 |
|
$ |
0.74 |
|
$ |
0.73 |
|
|
| Third Quarter |
|
|
378.3 |
|
|
67.4 |
|
|
0.33 |
|
|
0.32 |
|
|
| Second Quarter |
|
|
414.9 |
|
|
40.0 |
|
|
0.20 |
|
|
0.19 |
|
|
| First Quarter |
|
|
407.7 |
|
|
40.0 |
|
|
0.20 |
|
|
0.19 |
|
|
|
|
|
|
|
|
|
|
|
| Total 2014 |
|
$ |
1,526.2 |
|
$ |
299.1 |
|
$ |
1.46 |
|
$ |
1.44 |
|
|
|
Oil and gas sales, net of royalties, decreased in the first quarter of 2016 due to lower realized commodity prices and a decrease in natural gas production
compared to the fourth quarter of 2015. Oil and gas sales, net of royalties, increased during the first and second quarters of 2014 until realized commodity prices began to decline significantly in
the third quarter. During 2015, the impact of weak commodity prices was somewhat offset by increasing production. Net losses reported in 2016 and 2015 were primarily due to asset impairments related
to the decrease in the trailing twelve month average commodity prices, along with reduced revenues.
2016 UPDATED GUIDANCE
As a result of our continued focus on cost savings, the strengthening Canadian dollar and the divestment of higher operating cost properties, we have reduced
our operating expense, transportation cost and cash G&A expense guidance by a total of $1.30/BOE, combined. All other guidance has been maintained and is summarized below. This guidance includes the
previously announced second quarter sale of non-core assets located in northwest Alberta, but does not include any further unannounced acquisitions or divestments.
| Summary of 2016 Expectations |
|
Target |
|
|
| Capital spending |
|
$200 million |
|
| Average annual production |
|
90,000 – 94,000 BOE/day |
|
| Crude oil and natural gas liquids volumes |
|
43,000 – 45,000 bbls/day |
|
| Average royalty and production tax rate (% of gross sales, before transportation) |
|
23% |
|
| Operating expenses |
|
$8.50/BOE (from $9.50/BOE) |
|
| Transportation costs |
|
$3.10/BOE (from $3.30/BOE) |
|
| Cash G&A expenses |
|
$2.00/BOE (from $2.10/BOE) |
|
|
INTERNAL CONTROLS AND PROCEDURES
Our Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of our disclosure controls and procedures and internal control over
financial reporting as defined in Rule 13a – 15 under the U.S. Securities Exchange Act of 1934 and as defined in Canada under National
Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings. Based on that evaluation, the
Chief Executive Officer and Chief Financial Officer of Enerplus Corporation have concluded that, as at March 31, 2016, our disclosure controls and procedures and internal control over
financial reporting were effective. There were no changes in our internal control over financial reporting during the period beginning on January 1, 2016 and ended
March 31, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ADDITIONAL INFORMATION
Additional information relating to Enerplus, including our current Annual Information Form, is available under our profile on the SEDAR website at
www.sedar.com, on the EDGAR website at www.sec.gov and at www.enerplus.com.
ENERPLUS 2016 Q1
REPORT 21
FORWARD-LOOKING INFORMATION AND STATEMENTS
This MD&A 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", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans",
"intends", "budget", "strategy" and similar expressions are intended to identify forward-looking information. In particular, but without limiting the foregoing, this MD&A contains forward-looking
information pertaining to the following: expected 2016 average production volumes 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 differentials and our commodity
risk management programs in 2016 and in the future; 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 2016 and its impact on our production level and land holdings;
potential future asset and goodwill impairments, as well as the relevant factors that may affect such impairments; the amount of our future abandonment and reclamation costs and asset retirement
obligations; future environmental expenses; our future royalty and production and U.S. cash taxes; deferred income taxes, our tax pools and the time at which we may pay Canadian cash taxes;
future debt and working capital levels and debt-to-funds-flow ratio and adjusted payout ratio, financial capacity, liquidity and capital resources to fund capital spending and working capital
requirements; expectations regarding our ability to comply with debt covenants under our bank credit facility and outstanding senior notes, and to negotiate relief if required; our future acquisitions
and dispositions, expected timing thereof, production and reductions in asset retirement obligations associated therewith and use of proceeds therefrom; expected gains for accounting purposes in
respect to our repurchase of senior notes and our asset divestments; anticipated amount of interest expense savings in respect to our repurchase of senior notes; and the amount of future cash
dividends that we may pay to our shareholders.
The forward-looking information contained in this MD&A reflects several material factors, expectations and assumptions including, without limitation: that we will conduct our
operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; that lack of adequate infrastructure will not result in curtailment of
production and/or reduced realized prices; current commodity price, differentials 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 our reserve and contingent resource volumes; the continued availability of adequate debt and/or equity
financing and funds flow to fund our capital, operating and working capital requirements, and dividend payments as needed; the continued availability and sufficiency of our funds flow and availability
under our bank credit facility to fund our working capital deficiency; our ability to negotiate debt covenant relief under our bank credit facility and outstanding senior notes if required; the
availability of third party services; and the extent of our liabilities. In addition, our 2016 guidance contained in this MD&A is based on the following: a WTI price of US$42.38/bbl, a NYMEX price of
US$2.28/Mcf, an AECO price of $1.72/GJ and a USD/CDN exchange rate of 1.29. 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 MD&A 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
low commodity prices environment or further decline of commodity prices; changes in realized prices of Enerplus' products; changes in the demand for or supply of our products; unanticipated operating
results, results from our capital spending activities or production declines; 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; 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 the annual MD&A
and in our other public filings).
The forward-looking information contained in this MD&A speaks only as of the date of this MD&A, 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.
22 ENERPLUS 2016 Q1
REPORT
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Exhibit 99.2
STATEMENTS
Condensed Consolidated Balance Sheets
| (CDN$ thousands) unaudited |
|
Note |
|
|
|
March 31, 2016 |
|
|
|
|
December 31, 2015 |
|
|
|
|
|
| Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Current assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Cash |
|
|
|
|
$ |
1,281 |
|
|
|
$ |
7,498 |
|
|
| |
Accounts receivable |
|
3 |
|
|
|
107,840 |
|
|
|
|
132,156 |
|
|
| |
Deferred financial assets |
|
15 |
|
|
|
45,276 |
|
|
|
|
71,438 |
|
|
| |
Other current assets |
|
|
|
|
|
6,441 |
|
|
|
|
9,953 |
|
|
|
|
|
| |
|
|
|
|
|
160,838 |
|
|
|
|
221,045 |
|
|
|
|
|
| Property, plant and equipment: |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Oil and natural gas properties (full cost method) |
|
4 |
|
|
|
985,065 |
|
|
|
|
1,166,587 |
|
|
| |
Other capital assets, net |
|
4 |
|
|
|
17,083 |
|
|
|
|
19,686 |
|
|
|
|
|
| |
Property, plant and equipment |
|
|
|
|
|
1,002,148 |
|
|
|
|
1,186,273 |
|
|
|
|
|
| Goodwill |
|
|
|
|
|
644,852 |
|
|
|
|
657,831 |
|
|
| Deferred income tax asset |
|
13 |
|
|
|
237,076 |
|
|
|
|
516,085 |
|
|
|
|
|
| Total Assets |
|
|
|
|
$ |
2,044,914 |
|
|
|
$ |
2,581,234 |
|
|
|
|
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Current liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Accounts payable |
|
6 |
|
|
$ |
197,372 |
|
|
|
$ |
239,950 |
|
|
| |
Dividends payable |
|
|
|
|
|
2,071 |
|
|
|
|
6,196 |
|
|
| |
Deferred financial liabilities |
|
15 |
|
|
|
5,648 |
|
|
|
|
4,100 |
|
|
|
|
|
| |
|
|
|
|
|
205,091 |
|
|
|
|
250,246 |
|
|
|
|
|
| Deferred financial liabilities |
|
15 |
|
|
|
1,818 |
|
|
|
|
3,193 |
|
|
| Long-term debt |
|
7 |
|
|
|
994,118 |
|
|
|
|
1,223,682 |
|
|
| Asset retirement obligation |
|
8 |
|
|
|
197,202 |
|
|
|
|
206,359 |
|
|
|
|
|
| |
|
|
|
|
|
1,193,138 |
|
|
|
|
1,433,234 |
|
|
|
|
|
| Total Liabilities |
|
|
|
|
|
1,398,229 |
|
|
|
|
1,683,480 |
|
|
|
|
|
Shareholders' Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Share capital – authorized unlimited common shares, no par value
Issued and outstanding: March 31, 2016 – 207.1 million shares
December 31, 2015 – 206.5 million shares |
|
14 |
|
|
|
3,142,931 |
|
|
|
|
3,133,524 |
|
|
| |
Paid-in capital |
|
|
|
|
|
50,198 |
|
|
|
|
56,176 |
|
|
| |
Accumulated deficit |
|
|
|
|
|
(2,882,748 |
) |
|
|
|
(2,694,618 |
) |
|
| |
Accumulated other comprehensive income/(loss) |
|
|
|
|
|
336,304 |
|
|
|
|
402,672 |
|
|
|
|
|
| |
|
|
|
|
|
646,685 |
|
|
|
|
897,754 |
|
|
|
|
|
| Total Liabilities & Equity |
|
|
|
|
$ |
2,044,914 |
|
|
|
$ |
2,581,234 |
|
|
|
|
|
Contingencies |
|
16 |
|
|
|
|
|
|
|
|
|
|
|
| Subsequent events |
|
18 |
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes to the Condensed Consolidated Financial Statements are an integral part of these statements.
ENERPLUS 2016 Q1
REPORT 23
Condensed Consolidated Statements of Income/(Loss) and
Comprehensive Income/(Loss)
| Three months ended March 31 (CDN$ thousands) unaudited |
|
Note |
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
| Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Oil and natural gas sales, net of royalties |
|
9 |
|
|
$ |
142,661 |
|
|
|
$ |
204,960 |
|
|
| Commodity derivative instruments gain/(loss) |
|
15 |
|
|
|
13,464 |
|
|
|
|
50,398 |
|
|
|
|
|
| |
|
|
|
|
|
156,125 |
|
|
|
|
255,358 |
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Operating |
|
|
|
|
|
72,590 |
|
|
|
|
87,727 |
|
|
| Transportation |
|
|
|
|
|
25,718 |
|
|
|
|
26,483 |
|
|
| Production taxes |
|
|
|
|
|
7,436 |
|
|
|
|
10,813 |
|
|
| General and administrative |
|
10 |
|
|
|
22,453 |
|
|
|
|
32,080 |
|
|
| Depletion, depreciation and accretion |
|
|
|
|
|
91,161 |
|
|
|
|
132,350 |
|
|
| Asset impairment |
|
5 |
|
|
|
46,177 |
|
|
|
|
267,611 |
|
|
| Interest |
|
11 |
|
|
|
14,716 |
|
|
|
|
17,033 |
|
|
| Foreign exchange (gain)/loss |
|
12 |
|
|
|
(54,408 |
) |
|
|
|
104,202 |
|
|
| Gain on divestment of assets |
|
4 |
|
|
|
(145,100 |
) |
|
|
|
– |
|
|
| Gain on prepayment of senior notes |
|
7 |
|
|
|
(7,118 |
) |
|
|
|
– |
|
|
| Other expense/(income) |
|
|
|
|
|
(160 |
) |
|
|
|
8,612 |
|
|
|
|
|
| |
|
|
|
|
|
73,465 |
|
|
|
|
686,911 |
|
|
|
|
|
| Income/(Loss) before taxes |
|
|
|
|
|
82,660 |
|
|
|
|
(431,553 |
) |
|
| Current income tax expense/(recovery) |
|
13 |
|
|
|
(159 |
) |
|
|
|
63 |
|
|
| Deferred income tax expense/(recovery) |
|
13 |
|
|
|
256,485 |
|
|
|
|
(138,410 |
) |
|
|
|
|
| Net Income/(Loss) |
|
|
|
|
$ |
(173,666 |
) |
|
|
$ |
(293,206 |
) |
|
|
|
|
Other Comprehensive Income/(Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Change in cumulative translation adjustment |
|
|
|
|
|
(66,368 |
) |
|
|
|
176,759 |
|
|
|
|
|
| Other Comprehensive Income/(Loss) |
|
|
|
|
|
(66,368 |
) |
|
|
|
176,759 |
|
|
|
|
|
| Total Comprehensive Income/(Loss) |
|
|
|
|
$ |
(240,034 |
) |
|
|
$ |
(116,447 |
) |
|
|
|
|
Net Income/(Loss) per Share |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Basic |
|
14 |
|
|
$ |
(0.84 |
) |
|
|
$ |
(1.42 |
) |
|
| Diluted |
|
14 |
|
|
$ |
(0.84 |
) |
|
|
$ |
(1.42 |
) |
|
|
|
|
The accompanying notes to the Condensed Consolidated Financial Statements are an integral part of these statements.
24 ENERPLUS 2016 Q1
REPORT
Condensed Consolidated Statements of Changes in Shareholders' Equity
| Three months ended March 31 (CDN$ thousands) unaudited |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
| Share Capital |
|
|
|
|
|
|
|
|
|
|
| Balance, beginning of year |
|
$ |
3,133,524 |
|
|
|
$ |
3,120,002 |
|
|
| Stock Option Plan – cash |
|
|
– |
|
|
|
|
2,571 |
|
|
| Share-based compensation – settled |
|
|
9,407 |
|
|
|
|
3,095 |
|
|
| Stock Option Plan – exercised |
|
|
– |
|
|
|
|
227 |
|
|
|
|
|
| Balance, end of period |
|
$ |
3,142,931 |
|
|
|
$ |
3,125,895 |
|
|
|
|
|
Paid-in Capital |
|
|
|
|
|
|
|
|
|
|
| Balance, beginning of year |
|
$ |
56,176 |
|
|
|
$ |
46,906 |
|
|
| Share-based compensation – settled |
|
|
(9,407 |
) |
|
|
|
(3,095 |
) |
|
| Stock Option Plan – exercised |
|
|
– |
|
|
|
|
(227 |
) |
|
| Share-based compensation – non-cash |
|
|
3,429 |
|
|
|
|
4,970 |
|
|
|
|
|
| Balance, end of period |
|
$ |
50,198 |
|
|
|
$ |
48,554 |
|
|
|
|
|
Accumulated Deficit |
|
|
|
|
|
|
|
|
|
|
| Balance, beginning of year |
|
$ |
(2,694,618 |
) |
|
|
$ |
(1,039,260 |
) |
|
| Net income/(loss) |
|
|
(173,666 |
) |
|
|
|
(293,206 |
) |
|
| Dividends |
|
|
(14,464 |
) |
|
|
|
(47,359 |
) |
|
|
|
|
| Balance, end of period |
|
$ |
(2,882,748 |
) |
|
|
$ |
(1,379,825 |
) |
|
|
|
|
Accumulated Other Comprehensive Income/(Loss) |
|
|
|
|
|
|
|
|
|
|
| Balance, beginning of year |
|
$ |
402,672 |
|
|
|
$ |
95,478 |
|
|
| Change in cumulative translation adjustment |
|
|
(66,368 |
) |
|
|
|
176,759 |
|
|
|
|
|
| Balance, end of period |
|
$ |
336,304 |
|
|
|
$ |
272,237 |
|
|
|
|
|
| Total Shareholders' Equity |
|
$ |
646,685 |
|
|
|
$ |
2,066,861 |
|
|
|
|
|
The accompanying notes to the Condensed Consolidated Financial Statements are an integral part of these statements.
ENERPLUS 2016 Q1
REPORT 25
Condensed Consolidated Statements of Cash Flows
| Three months ended March 31 (CDN$ thousands) unaudited |
|
Note |
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
| Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net income/(loss) |
|
|
|
|
$ |
(173,666 |
) |
|
|
$ |
(293,206 |
) |
|
| Non-cash items add/(deduct): |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Depletion, depreciation and accretion |
|
|
|
|
|
91,161 |
|
|
|
|
132,350 |
|
|
| |
Asset impairment |
|
5 |
|
|
|
46,177 |
|
|
|
|
267,611 |
|
|
| |
Changes in fair value of derivative instruments |
|
15 |
|
|
|
26,335 |
|
|
|
|
87,499 |
|
|
| |
Deferred income tax expense/(recovery) |
|
13 |
|
|
|
256,485 |
|
|
|
|
(138,410 |
) |
|
| |
Foreign exchange (gain)/loss on debt and working capital |
|
12 |
|
|
|
(56,158 |
) |
|
|
|
88,014 |
|
|
| |
Share-based compensation |
|
14 |
|
|
|
3,429 |
|
|
|
|
4,970 |
|
|
| |
Amortization of debt issue costs |
|
|
|
|
|
182 |
|
|
|
|
240 |
|
|
| Gain on divestment of assets |
|
|
|
|
|
(145,100 |
) |
|
|
|
– |
|
|
| Gain on prepayment of senior notes |
|
|
|
|
|
(7,118 |
) |
|
|
|
– |
|
|
| Derivative settlement of foreign exchange swaps |
|
|
|
|
|
– |
|
|
|
|
(39,904 |
) |
|
| Asset retirement obligation expenditures |
|
8 |
|
|
|
(2,454 |
) |
|
|
|
(3,890 |
) |
|
| Changes in non-cash operating working capital |
|
17 |
|
|
|
30,474 |
|
|
|
|
25,822 |
|
|
|
|
|
| Cash flow from operating activities |
|
|
|
|
|
69,747 |
|
|
|
|
131,096 |
|
|
|
|
|
Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Proceeds from the issuance of shares |
|
14 |
|
|
|
– |
|
|
|
|
2,571 |
|
|
| Cash dividends |
|
14 |
|
|
|
(14,464 |
) |
|
|
|
(47,359 |
) |
|
| Increase/(decrease) in bank credit facility |
|
|
|
|
|
70,849 |
|
|
|
|
45,820 |
|
|
| Proceeds/(repayment) of senior notes |
|
7 |
|
|
|
(226,029 |
) |
|
|
|
– |
|
|
| Derivative settlement of foreign exchange swaps |
|
|
|
|
|
– |
|
|
|
|
39,904 |
|
|
| Changes in non-cash financing working capital |
|
|
|
|
|
(4,125 |
) |
|
|
|
(8,207 |
) |
|
|
|
|
| Cash flow from/(used in) financing activities |
|
|
|
|
|
(173,769 |
) |
|
|
|
32,729 |
|
|
|
|
|
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Capital expenditures and office expenditures |
|
|
|
|
|
(43,292 |
) |
|
|
|
(167,888 |
) |
|
| Property and land acquisitions |
|
|
|
|
|
(3,554 |
) |
|
|
|
236 |
|
|
| Property divestments |
|
|
|
|
|
187,768 |
|
|
|
|
3,712 |
|
|
| Changes in non-cash investing working capital |
|
|
|
|
|
(42,125 |
) |
|
|
|
931 |
|
|
|
|
|
| Cash flow from/(used in) investing activities |
|
|
|
|
|
98,797 |
|
|
|
|
(163,009 |
) |
|
|
|
|
| Effect of exchange rate changes on cash |
|
|
|
|
|
(992 |
) |
|
|
|
(249 |
) |
|
|
|
|
| Change in cash |
|
|
|
|
|
(6,217 |
) |
|
|
|
567 |
|
|
| Cash, beginning of period |
|
|
|
|
|
7,498 |
|
|
|
|
2,036 |
|
|
|
|
|
| Cash, end of period |
|
|
|
|
$ |
1,281 |
|
|
|
$ |
2,603 |
|
|
|
|
|
The accompanying notes to the Condensed Consolidated Financial Statements are an integral part of these statements.
26 ENERPLUS 2016 Q1
REPORT
NOTES
Notes to Condensed Consolidated Financial Statements
(unaudited)
1) REPORTING ENTITY
These interim Condensed Consolidated Financial Statements ("interim Consolidated Financial Statements") and notes present the financial position and results of
Enerplus Corporation ("The Company" or "Enerplus") including its Canadian and U.S. subsidiaries. Enerplus is a North American crude oil and natural gas exploration and development
company. Enerplus is publicly traded on the Toronto and New York stock exchanges under the ticker symbol ERF. Enerplus' head office is located in Calgary, Alberta, Canada. The interim
Consolidated Financial Statements were authorized for issue by the Board of Directors on May 5, 2016.
2) BASIS OF PREPARATION
Enerplus' interim Consolidated Financial Statements present its results of operations and financial position under accounting principles generally accepted in
the United States of America ("U.S. GAAP") for the three months ended March 31, 2016, and the 2015 comparative periods. Certain information and notes normally included with
the annual audited Consolidated Financial Statements have been condensed or have been disclosed on an annual basis only. Accordingly, these interim Consolidated Financial Statements should be read in
conjunction with Enerplus' audited Consolidated Financial Statements as of December 31, 2015. There are no differences in the use of estimates or
judgments between these interim Consolidated Financial Statements and the audited Consolidated Financial Statements and notes thereto for the year ended December 31, 2015.
These
unaudited interim Consolidated Financial Statements reflect, in the opinion of Management, all normal and recurring adjustments necessary to present fairly the financial position and results of
the Company as at and for the periods presented.
3) ACCOUNTS RECEIVABLE
| ($ thousands) |
|
|
March 31, 2016 |
|
|
|
|
December 31, 2015 |
|
|
|
|
|
| Accrued receivables |
|
$ |
72,321 |
|
|
|
$ |
91,378 |
|
|
| Accounts receivable – trade |
|
|
19,937 |
|
|
|
|
22,615 |
|
|
| Current income tax receivable |
|
|
18,786 |
|
|
|
|
21,410 |
|
|
| Allowance for doubtful accounts |
|
|
(3,204 |
) |
|
|
|
(3,247 |
) |
|
|
|
|
| Total accounts receivable |
|
$ |
107,840 |
|
|
|
$ |
132,156 |
|
|
|
|
|
4) PROPERTY, PLANT AND EQUIPMENT ("PP&E")
As at March 31, 2016
($ thousands) |
|
|
Cost |
|
|
Accumulated
Depletion,
Depreciation, and
Impairment |
|
|
Net Book Value |
|
|
| Oil and natural gas properties |
|
$ |
13,168,213 |
|
$ |
12,183,148 |
|
$ |
985,065 |
|
| Other capital assets |
|
|
104,020 |
|
|
86,937 |
|
|
17,083 |
|
|
| Total PP&E |
|
$ |
13,272,233 |
|
$ |
12,270,085 |
|
$ |
1,002,148 |
|
|
As at December 31, 2015
($ thousands) |
|
|
Cost |
|
|
Accumulated
Depletion,
Depreciation, and
Impairment |
|
|
Net Book Value |
|
|
| Oil and natural gas properties |
|
$ |
13,541,670 |
|
$ |
12,375,083 |
|
$ |
1,166,587 |
|
| Other capital assets |
|
|
105,124 |
|
|
85,438 |
|
|
19,686 |
|
|
| Total PP&E |
|
$ |
13,646,794 |
|
$ |
12,460,521 |
|
$ |
1,186,273 |
|
|
ENERPLUS 2016 Q1
REPORT 27
During the three months ended March 31, 2016, Enerplus disposed of certain Canadian properties for proceeds of $181.8 million, which
resulted in a gain on disposition of $145.1 million (2015 – nil).
Under
full cost accounting rules, divestitures of oil and gas properties are generally accounted for as adjustments to capitalized costs, with no recognition of a gain or loss. However, if not
recognizing a gain or loss on the transaction would have otherwise significantly altered the relationship between a cost center's capitalized costs and proved reserves, then a gain or loss must
be recognized.
5) ASSET IMPAIRMENT
| |
|
Three months ended March 31,
|
| ($ thousands) |
|
|
2016 |
|
|
|
2015 |
|
|
|
|
| Oil and natural gas properties: |
|
|
|
|
|
|
|
|
| |
Canada cost centre |
|
$ |
– |
|
|
$ |
– |
|
| |
U.S. cost centre |
|
|
46,177 |
|
|
|
267,611 |
|
|
|
|
| Impairment expense |
|
$ |
46,177 |
|
|
$ |
267,611 |
|
|
|
|
For the three months ended March 31, 2016 non-cash impairment of $46.2 million was recorded in the United States cost centre due to
lower 12-month average trailing crude oil prices (2015 – $267.6 million). No impairments were recorded to the Canada cost centre for the periods ended
March 31, 2016 and 2015.
The
following table outlines the 12-month average trailing benchmark prices and exchange rates used in Enerplus' ceiling tests from March 31, 2015 through March 31, 2016:
| Period |
|
|
WTI Crude Oil
US$/bbl |
|
Exchange Rate
US/CDN |
|
|
Edm Light
Crude
CDN$/bbl |
|
|
U.S. Henry Hub
Gas
US$/Mcf |
|
|
AECO Natural
Gas Spot
CDN$/Mcf |
|
|
| Q1 2016 |
|
$ |
46.26 |
|
1.32 |
|
$ |
56.97 |
|
$ |
2.41 |
|
$ |
2.47 |
|
| Q4 2015 |
|
|
50.28 |
|
1.27 |
|
|
59.38 |
|
|
2.58 |
|
|
2.69 |
|
| Q3 2015 |
|
|
59.21 |
|
1.22 |
|
|
66.51 |
|
|
3.08 |
|
|
3.00 |
|
| Q2 2015 |
|
|
71.75 |
|
1.16 |
|
|
75.83 |
|
|
3.42 |
|
|
3.33 |
|
| Q1 2015 |
|
|
82.73 |
|
1.14 |
|
|
84.61 |
|
|
3.88 |
|
|
3.86 |
|
|
6) ACCOUNTS PAYABLE
| ($ thousands) |
|
|
March 31, 2016 |
|
|
|
December 31, 2015 |
|
|
|
|
| Accrued payables |
|
$ |
119,653 |
|
|
$ |
167,253 |
|
| Accounts payable – trade |
|
|
77,719 |
|
|
|
72,697 |
|
|
|
|
| Total accounts payable |
|
$ |
197,372 |
|
|
$ |
239,950 |
|
|
|
|
7) DEBT
| ($ thousands) |
|
|
March 31, 2016 |
|
|
|
December 31, 2015 |
|
|
|
|
| Current |
|
$ |
– |
|
|
$ |
– |
|
|
|
|
| |
|
|
– |
|
|
|
– |
|
|
|
|
| Long-term: |
|
|
|
|
|
|
|
|
| |
Bank credit facility |
|
$ |
149,599 |
|
|
$ |
86,543 |
|
| |
Senior notes |
|
|
844,519 |
|
|
|
1,137,139 |
|
|
|
|
| |
|
|
994,118 |
|
|
|
1,223,682 |
|
|
|
|
| Total debt |
|
$ |
994,118 |
|
|
$ |
1,223,682 |
|
|
|
|
28 ENERPLUS 2016 Q1
REPORT
For the period ended March 31, 2016 Enerplus repurchased US$172 million in outstanding senior notes at a discount, resulting in a gain of
$7.1 million, for a total payment of $226.0 million. Subsequent to March 31, 2016, an additional US$95 million in senior notes were repurchased at a discount and it
is expected that an additional gain of $12 million will be recorded.
8) ASSET RETIREMENT OBLIGATION
Enerplus has estimated the present value of its asset retirement obligation to be $197.2 million at March 31, 2016 compared to
$206.4 million at December 31, 2015, based on a total undiscounted liability of $506.0 million and $556.4 million, respectively. The asset retirement obligation was
calculated using a weighted credit-adjusted risk-free rate of 5.92% (December 31, 2015 – 5.91%).
| ($ thousands) |
|
|
Three months ended
March 31, 2016 |
|
|
|
|
Year ended
December 31, 2015 |
|
|
|
|
|
| Balance, beginning of year |
|
$ |
206,359 |
|
|
|
$ |
288,692 |
|
|
| Change in estimate |
|
|
169 |
|
|
|
|
(35,386 |
) |
|
| Property acquisition and development activity |
|
|
153 |
|
|
|
|
761 |
|
|
| Divestments |
|
|
(9,974 |
) |
|
|
|
(48,748 |
) |
|
| Settlements |
|
|
(2,454 |
) |
|
|
|
(14,935 |
) |
|
| Accretion expense |
|
|
2,949 |
|
|
|
|
15,975 |
|
|
|
|
|
| Balance, end of period |
|
$ |
197,202 |
|
|
|
$ |
206,359 |
|
|
|
|
|
9) OIL AND NATURAL GAS SALES
| |
|
Three months ended March 31,
|
| ($ thousands) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
| Oil and natural gas sales |
|
$ |
170,423 |
|
|
|
$ |
244,077 |
|
|
| Royalties(1) |
|
|
(27,762 |
) |
|
|
|
(39,117 |
) |
|
|
|
|
| Oil and natural gas sales, net of royalties |
|
$ |
142,661 |
|
|
|
$ |
204,960 |
|
|
|
|
|
- (1)
- Royalties
above do not include production taxes which are re ported separately on the Consolidated Statements of Income/(Loss).
10) GENERAL AND ADMINISTRATIVE EXPENSE
| |
|
Three months ended March 31,
|
| ($ thousands) |
|
|
2016 |
|
|
|
2015 |
|
|
|
|
| General and administrative expense |
|
$ |
18,426 |
|
|
$ |
21,435 |
|
| Share-based compensation expense |
|
|
4,027 |
|
|
|
10,645 |
|
|
|
|
| General and administrative expense |
|
$ |
22,453 |
|
|
$ |
32,080 |
|
|
|
|
11) INTEREST EXPENSE
| |
|
Three months ended March 31,
|
| ($ thousands) |
|
|
2016 |
|
|
|
2015 |
|
|
|
|
| Realized: |
|
|
|
|
|
|
|
|
| |
Interest on bank debt and senior notes |
|
$ |
14,534 |
|
|
$ |
16,793 |
|
| Unrealized: |
|
|
|
|
|
|
|
|
| |
Amortization of debt issue costs |
|
|
182 |
|
|
|
240 |
|
|
|
|
| Interest expense |
|
$ |
14,716 |
|
|
$ |
17,033 |
|
|
|
|
ENERPLUS 2016 Q1
REPORT 29
12) FOREIGN EXCHANGE
| |
|
Three months ended March 31,
|
| ($ thousands) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
| Realized: |
|
|
|
|
|
|
|
|
|
|
| |
Foreign exchange (gain)/loss |
|
$ |
1,750 |
|
|
|
$ |
(35,574 |
) |
|
| Unrealized: |
|
|
|
|
|
|
|
|
|
|
| |
Translation of U.S. dollar debt and working capital (gain)/loss |
|
|
(56,158 |
) |
|
|
|
88,014 |
|
|
| |
Foreign exchange derivatives (gain)/loss |
|
|
– |
|
|
|
|
51,762 |
|
|
|
|
|
| Foreign exchange (gain)/loss |
|
$ |
(54,408 |
) |
|
|
$ |
104,202 |
|
|
|
|
|
13) INCOME TAXES
Enerplus' provision for income tax is a follows:
| |
|
Three months ended March 31,
|
| ($ thousands) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
| Current tax expense/(recovery) |
|
|
|
|
|
|
|
|
|
|
| |
Canada |
|
$ |
(303 |
) |
|
|
$ |
– |
|
|
| |
United States |
|
|
144 |
|
|
|
|
63 |
|
|
|
|
|
| Current tax expense/(recovery) |
|
|
(159 |
) |
|
|
|
63 |
|
|
|
|
|
| Deferred Tax expense/(recovery) |
|
|
|
|
|
|
|
|
|
|
| |
Canada |
|
$ |
12,846 |
|
|
|
$ |
(9,263 |
) |
|
| |
United States |
|
|
243,639 |
|
|
|
|
(129,147 |
) |
|
|
|
|
| Deferred tax expense/(recovery) |
|
|
256,485 |
|
|
|
|
(138,410 |
) |
|
|
|
|
| Income tax expense/(recovery) |
|
$ |
256,326 |
|
|
|
$ |
(138,347 |
) |
|
|
|
|
The difference between the expected income taxes based on the statutory income tax rate and the effective income taxes for the current and prior period is
impacted by the following: expected annual earnings, recognition of valuation allowance, foreign rate differentials for foreign operations, statutory and other rate differentials, the reversal or
recognition of previously recognized or unrecognized deferred tax assets, non-taxable portions of capital gains and losses, and non-deductible share-based compensation. Enerplus recorded an additional
valuation allowance of $258.5 million in the quarter. For the year ended December 31, 2015, a total valuation allowance of $443.7 million was recognized, with most of it
being recorded in the fourth quarter.
30 ENERPLUS 2016 Q1
REPORT
14) SHAREHOLDERS' EQUITY
a) Share Capital
| |
|
Three months ended March 31, |
|
Year ended December 31, |
| |
|
|
|
|
| |
|
2016 |
|
2015 |
|
|
|
Authorized unlimited number of common shares Issued:
(thousands) |
|
Shares |
|
|
Amount |
|
|
Shares |
|
|
Amount |
|
|
|
|
| Balance, beginning of year |
|
206,539 |
|
$ |
3,133,524 |
|
|
205,732 |
|
$ |
3,120,002 |
|
| Issued for cash: |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Stock Option Plan |
|
– |
|
|
– |
|
|
234 |
|
|
3,205 |
|
| Non-cash: |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Share-based compensation – settled |
|
594 |
|
|
9,407 |
|
|
573 |
|
|
10,050 |
|
| |
Stock Option Plan – exercised |
|
– |
|
|
– |
|
|
– |
|
|
267 |
|
|
|
|
| Balance, end of period |
|
207,133 |
|
$ |
3,142,931 |
|
|
206,539 |
|
$ |
3,133,524 |
|
|
|
|
Dividends declared to shareholders for the three months ended March 31, 2016 were $14.5 million
(2015 – $47.4 million).
b) Share-based compensation
The following table summarizes Enerplus' share-based compensation expense, which is included in General and Administrative expense on the Consolidated
Statements of Income/(Loss):
| |
|
Three months ended March 31,
|
| ($ thousands) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
| Cash: |
|
|
|
|
|
|
|
|
|
|
| |
Long-term incentive plans expense |
|
$ |
733 |
|
|
|
$ |
7,274 |
|
|
| Non-Cash: |
|
|
|
|
|
|
|
|
|
|
| |
Long-term incentive plans expense |
|
|
3,429 |
|
|
|
|
4,970 |
|
|
| |
Equity swap (gain)/loss |
|
|
(135 |
) |
|
|
|
(1,599 |
) |
|
|
|
|
| Share-based compensation expense |
|
$ |
4,027 |
|
|
|
$ |
10,645 |
|
|
|
|
|
(i) Long-term Incentive ("LTI") Plans
In 2014, the Performance Share Unit ("PSU") and Restricted Share Unit ("RSU") plans were amended such that grants under the plans are settled through the
issuance of treasury shares. The amendment was effective beginning with the grant in March of 2014. The final cash-settled PSU and RSU grants were settled in December, 2015 and
March, 2016, respectively.
The
following table summarizes the PSU, RSU and Director Share Unit ("DSU") activity for the three months ended March 31, 2016:
For the three months ended
March 31, 2016 |
|
Cash-settled LTI plans
|
|
Equity-settled LTI Plans
|
|
|
|
|
| (thousands of units) |
|
RSU |
|
DSU |
|
PSU |
|
RSU |
|
Total |
|
|
|
| Balance, beginning of year |
|
92 |
|
166 |
|
1,222 |
|
1,627 |
|
3,107 |
|
|
| Granted |
|
– |
|
134 |
|
1,406 |
|
1,971 |
|
3,511 |
|
|
| Vested |
|
(89 |
) |
– |
|
– |
|
(594 |
) |
(683 |
) |
|
| Forfeited |
|
(3 |
) |
– |
|
(86 |
) |
(79 |
) |
(168 |
) |
|
|
| Balance, end of period |
|
– |
|
300 |
|
2,542 |
|
2,925 |
|
5,767 |
|
|
|
Cash-settled LTI Plans
For three months ended March 31, 2016 the Company recorded cash share-based compensation expense of $0.7 million
(2015 – $7.3 million). For the three months ended March 31, 2016, the Company made cash payments of $2.7 million related to its
cash-settled plans (2015 – $5.6 million).
ENERPLUS 2016 Q1
REPORT 31
Enerplus
continues to grant DSUs through cash-settled awards. As of March 31, 2016, a liability of $1.8 million (2015 – $3.1 million)
has been recorded to Accounts Payable on the Consolidated Balance Sheets.
Equity-settled LTI Plans
For the three months ended March 31, 2016 the Company recorded non-cash share-based compensation expense of $3.4 million
(2015 – $5.0 million).
The
following table summarizes the cumulative share-based compensation expense recognized to-date which is recorded to Paid-in Capital on the Consolidated Balance Sheets. Unrecognized amounts will be
recorded to non-cash share-based compensation expense over the remaining vesting terms.
| At March 31, 2016 ($ thousands, except for years) |
|
|
PSU(1) |
|
|
RSU |
|
|
Total |
|
|
| Cumulative recognized share-based compensation expense |
|
$ |
5,378 |
|
$ |
9,852 |
|
$ |
15,230 |
|
| Unrecognized share-based compensation expense |
|
|
8,851 |
|
|
12,200 |
|
|
21,051 |
|
|
| Fair value |
|
$ |
14,229 |
|
$ |
22,052 |
|
$ |
36,281 |
|
|
| Weighted-average remaining contractual term (years) |
|
|
2.3 |
|
|
1.6 |
|
|
|
|
|
- (1)
- Includes
estimated performance multipliers.
(ii) Stock Option Plan
The Company did not grant any stock options for the three months ended March 31, 2016. At March 31, 2016 all stock options are fully
vested and any related non-cash share-based compensation expense has been fully recognized.
The
following table summarizes the stock option plan activity for the period ended March 31, 2016:
| Period ended March 31, 2016 |
|
Number of
Options
(thousands) |
|
|
Weighted
Average
Exercise Price |
|
|
| Options outstanding, beginning of year |
|
7,580 |
|
$ |
18.49 |
|
| |
Forfeited |
|
(632 |
) |
|
19.00 |
|
|
| Options outstanding, end of period |
|
6,948 |
|
$ |
18.45 |
|
|
| Options exercisable, end of period |
|
6,948 |
|
$ |
18.45 |
|
|
At March 31, 2016, 6,948,000 options were exercisable at a weighted average reduced exercise price of $18.45 with a weighted average
remaining contractual term of 3.3 years, giving an aggregate intrinsic value of nil (2015 – nil). The intrinsic value of options exercised for the period
ended March 31, 2016 was nil (2015 – $0.1 million).
c) Basic and Diluted Net Income/(Loss) Per Share
Net income/(loss) per share has been determined as follows:
| |
|
Three months ended March 31,
|
| (thousands, except per share amounts) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
| Net income/(loss) |
|
$ |
(173,666 |
) |
|
|
$ |
(293,206 |
) |
|
| Weighted average shares outstanding – Basic |
|
|
206,716 |
|
|
|
|
205,845 |
|
|
| Dilutive impact of share-based compensation(1) |
|
|
– |
|
|
|
|
– |
|
|
|
|
|
| Weighted average shares outstanding – Diluted |
|
|
206,716 |
|
|
|
|
205,845 |
|
|
|
|
|
| Net income/(loss) per share |
|
|
|
|
|
|
|
|
|
|
| |
Basic |
|
$ |
(0.84 |
) |
|
|
$ |
(1.42 |
) |
|
| |
Diluted(1) |
|
$ |
(0.84 |
) |
|
|
$ |
(1.42 |
) |
|
|
|
|
- (1)
- For
the three months ended March 31, 2016 and 2015 the impact of share-based compensation was anti-dilutive as a conversion to shares would not increase the loss per share.
32 ENERPLUS 2016 Q1
REPORT
15) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
a) Fair Value Measurements
At March 31, 2016, the carrying value of cash, accounts receivable, accounts payable, dividends payable and bank credit facilities approximated
their fair value due to the short-term maturity of the instruments.
At
March 31, 2016 senior notes included in long-term debt had a carrying value of $844.5 million and a fair value of $911.4 million
(December 31, 2015 – $1,137.2 million and $1,220.8 million, respectively).
There
were no transfers between fair value hierarchy levels during the period.
b) Derivative Financial Instruments
The deferred financial assets and liabilities on the Consolidated Balance Sheets result from recording derivative financial instruments at fair value.
The
following table summarizes the change in fair value for the three months ended March 31, 2016 and 2015:
| Gain/(Loss) ($ thousands) |
|
|
March 31, 2016 |
|
|
|
|
March 31, 2015 |
|
|
|
Income Statement Presentation |
|
|
|
|
|
|
| Foreign Exchange Derivatives |
|
$ |
– |
|
|
|
$ |
(51,762 |
) |
|
|
Foreign exchange |
|
| Electricity Swaps |
|
|
(308 |
) |
|
|
|
(927 |
) |
|
|
Operating expense |
|
| Equity Swaps |
|
|
135 |
|
|
|
|
1,599 |
|
|
|
General and administrative expense |
|
Commodity Derivative Instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Oil |
|
|
(31,276 |
) |
|
|
|
(35,959 |
) |
|
|
Commodity derivative |
|
| |
Gas |
|
|
5,114 |
|
|
|
|
(450 |
) |
|
|
instruments |
|
|
|
|
|
|
| Total Unrealized Gain/(Loss) |
|
$ |
(26,335 |
) |
|
|
$ |
(87,499 |
) |
|
|
|
|
|
|
|
|
|
The following table summarizes the income statement effects of Enerplus' commodity derivative instruments:
| |
|
Three months ended March 31,
|
| ($ thousands) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
| Change in fair value gain/(loss) |
|
$ |
(26,162 |
) |
|
|
$ |
(36,409 |
) |
|
| Net realized cash gain/(loss) |
|
|
39,626 |
|
|
|
|
86,807 |
|
|
|
|
|
| Commodity derivative instruments gain/(loss) |
|
$ |
13,464 |
|
|
|
$ |
50,398 |
|
|
|
|
|
The following table summarizes the fair values at the respective period ends:
| |
|
March 31, 2016
|
|
December 31, 2015
|
| |
|
Assets
|
|
Liabilities
|
|
Assets
|
|
Liabilities
|
| ($ thousands) |
|
|
Current |
|
|
Current |
|
|
Long-term |
|
|
|
Current |
|
|
Current |
|
|
Long-term |
|
|
|
|
| Electricity Swaps |
|
$ |
– |
|
$ |
2,084 |
|
$ |
– |
|
|
$ |
– |
|
$ |
1,776 |
|
$ |
– |
|
| Equity Swaps |
|
|
– |
|
|
3,564 |
|
|
1,818 |
|
|
|
– |
|
|
2,324 |
|
|
3,193 |
|
| Commodity Derivative Instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Oil |
|
|
36,121 |
|
|
– |
|
|
– |
|
|
|
67,397 |
|
|
– |
|
|
– |
|
| |
Gas |
|
|
9,155 |
|
|
– |
|
|
– |
|
|
|
4,041 |
|
|
– |
|
|
– |
|
|
|
|
| Total |
|
$ |
45,276 |
|
$ |
5,648 |
|
$ |
1,818 |
|
|
$ |
71,438 |
|
$ |
4,100 |
|
$ |
3,193 |
|
|
|
|
c) Risk Management
In the normal course of operations, Enerplus is exposed to various market risks, including commodity prices, foreign exchange, interest rates and equity prices,
credit risk and liquidity risk.
ENERPLUS 2016 Q1
REPORT 33
(i) Market Risk
Market risk is comprised of commodity price, foreign exchange, interest rate and equity price risk.
Commodity Price Risk:
Enerplus manages a portion of commodity price risk through a combination of financial derivative and physical delivery sales contracts. Enerplus' policy is to
enter into commodity contracts subject to a maximum of 80% of forecasted production volumes net of royalties and production taxes.
The
following tables summarize Enerplus' price risk management positions at May 2, 2016:
Crude Oil Instruments:
| Instrument Type(1) |
|
bbls/day |
|
US$/bbl |
|
|
|
| April 1, 2016 – April 30, 2016 |
|
|
|
|
|
|
| WTI Swap |
|
3,000 |
|
64.28 |
|
|
| WTI Purchased Put |
|
11,000 |
|
55.82 |
|
|
| WTI Sold Call |
|
11,000 |
|
68.64 |
|
|
| WTI Sold Put |
|
8,000 |
|
50.13 |
|
|
| WCS Differential Swap |
|
3,000 |
|
(14.03 |
) |
|
| MSW Differential Swap |
|
1,000 |
|
(3.50 |
) |
|
May 1, 2016 – May 31, 2016 |
|
|
|
|
|
|
| WTI Swap |
|
3,000 |
|
64.28 |
|
|
| WTI Purchased Put |
|
10,000 |
|
58.30 |
|
|
| WTI Sold Call |
|
10,000 |
|
72.36 |
|
|
| WTI Sold Put |
|
8,000 |
|
50.13 |
|
|
| WCS Differential Swap |
|
3,000 |
|
(14.03 |
) |
|
| MSW Differential Swap |
|
1,000 |
|
(3.50 |
) |
|
Jun 1, 2016 – Jun 30, 2016 |
|
|
|
|
|
|
| WTI Swap |
|
3,000 |
|
64.28 |
|
|
| WTI Purchased Put |
|
8,000 |
|
64.38 |
|
|
| WTI Sold Call |
|
8,000 |
|
79.38 |
|
|
| WTI Sold Put |
|
8,000 |
|
50.13 |
|
|
| WCS Differential Swap |
|
3,000 |
|
(14.03 |
) |
|
| MSW Differential Swap |
|
1,000 |
|
(3.50 |
) |
|
Jul 1, 2016 – Dec 31, 2016 |
|
|
|
|
|
|
| WTI Purchased Put |
|
8,000 |
|
63.98 |
|
|
| WTI Sold Call |
|
8,000 |
|
79.63 |
|
|
| WTI Sold Put |
|
8,000 |
|
49.78 |
|
|
| WCS Differential Swap |
|
3,000 |
|
(14.03 |
) |
|
| MSW Differential Swap |
|
1,000 |
|
(3.50 |
) |
|
Jan 1, 2017 – Dec 31, 2017 |
|
|
|
|
|
|
| WTI Purchased Put |
|
6,000 |
|
48.18 |
|
|
| WTI Sold Call |
|
6,000 |
|
60.00 |
|
|
| WTI Sold Put |
|
6,000 |
|
35.67 |
|
|
|
- (1)
- Transactions
with a common term have been aggregated and presented at weighted average price/bbl.
34 ENERPLUS 2016 Q1
REPORT
Natural Gas Instruments:
| Instrument Type(1) |
|
MMcf/day |
|
US$/Mcf |
|
|
| Apr 1, 2016 – Oct 31, 2016 |
|
|
|
|
|
| NYMEX Swap |
|
50.0 |
|
2.53 |
|
| NYMEX Purchased Put |
|
25.0 |
|
3.00 |
|
| NYMEX Sold Put |
|
25.0 |
|
2.50 |
|
| NYMEX Sold Call |
|
25.0 |
|
3.75 |
|
Nov 1, 2016 – Dec 31, 2016 |
|
|
|
|
|
| NYMEX Swap |
|
25.0 |
|
2.48 |
|
| NYMEX Purchased Put |
|
25.0 |
|
3.00 |
|
| NYMEX Sold Put |
|
25.0 |
|
2.50 |
|
| NYMEX Sold Call |
|
25.0 |
|
3.75 |
|
Jan 1, 2017 – Dec 31, 2017 |
|
|
|
|
|
| NYMEX Purchased Put |
|
35.0 |
|
2.67 |
|
| NYMEX Sold Put |
|
35.0 |
|
2.00 |
|
| NYMEX Sold Call |
|
35.0 |
|
3.32 |
|
|
- (1)
- Transactions
with a common term have been aggregated and presented as the weighted average price/Mcf.
Electricity Instruments:
| Instrument Type |
|
MWh |
|
CDN$/MWh |
|
|
| Apr 1, 2016 – Dec 31, 2016 |
|
|
|
|
|
| AESO Power Swap(1) |
|
15.0 |
|
46.60 |
|
Jan 1, 2017 – Dec 31, 2017 |
|
|
|
|
|
| AESO Power Swap(1) |
|
6.0 |
|
44.38 |
|
|
- (1)
- Alberta
Electrical System Operator ("AESO") fixed pricing.
Physical Contracts:
| Instrument Type |
|
MMcf/day |
|
US$/Mcf |
|
|
|
| Apr 1, 2016 – Oct 31, 2016 |
|
21.4 |
|
(0.68 |
) |
|
| AECO-NYMEX Basis |
|
|
|
|
|
|
Nov 1, 2016 – Oct 31, 2017 |
|
80.0 |
|
(0.65 |
) |
|
| AECO-NYMEX Basis |
|
|
|
|
|
|
Nov 1, 2017 – Oct 31, 2018 |
|
80.0 |
|
(0.65 |
) |
|
| AECO-NYMEX Basis |
|
|
|
|
|
|
Nov 1, 2018 – Oct 31, 2019 |
|
80.0 |
|
(0.64 |
) |
|
| AECO-NYMEX Basis |
|
|
|
|
|
|
|
Foreign Exchange Risk:
Enerplus is exposed to foreign exchange risk in relation to its U.S. operations, and U.S. dollar denominated senior notes and working capital.
Additionally, Enerplus' crude oil sales and a portion of its natural gas sales are based on U.S. dollar indices. To mitigate exposure to fluctuations in foreign exchange, Enerplus may enter
into foreign exchange derivatives. At March 31, 2016 Enerplus did not have any foreign exchange derivatives outstanding.
Interest Rate Risk:
At March 31, 2016, approximately 85% of Enerplus' debt was based on fixed interest rates and 15% was based on floating interest rates. To mitigate
exposure to fluctuation in floating market interest rates, Enerplus may enter into interest rate derivatives. At March 31, 2016 Enerplus did not have any interest rate derivatives
outstanding.
ENERPLUS 2016 Q1
REPORT 35
Equity Price Risk:
Enerplus is exposed to equity price risk in relation to its long-term incentive plans detailed in Note 14. Enerplus has entered into various equity swaps
maturing between 2016 and 2018 and has effectively fixed the future settlement cost on 470,000 shares at a weighted average price of $16.89 per share.
(ii) Credit Risk
Credit risk represents the financial loss Enerplus would experience due to the potential non-performance of counterparties to its financial instruments.
Enerplus is exposed to credit risk mainly through its joint venture, marketing and financial counterparty receivables.
Enerplus
mitigates credit risk through credit management techniques, including conducting financial assessments to establish and monitor counterparties' credit worthiness, setting exposure limits,
monitoring exposures against these limits and obtaining financial assurances such as letters of credit, parental guarantees, or third party credit insurance where warranted. Enerplus monitors and
manages its concentration of counterparty credit risk on an ongoing basis.
Enerplus'
maximum credit exposure at the balance sheet date consists of the carrying amount of its non-derivative financial assets and the fair value of its derivative financial assets. At
March 31, 2016 approximately 62% of Enerplus' marketing receivables were with companies considered investment grade
(December 31, 2015 – 61%).
At
March 31, 2016 approximately $2.6 million or 2% of Enerplus' total accounts receivable were aged over 120 days and considered past due
(December 31, 2015 – $2.6 million and 2%). The majority of these accounts are due from various joint venture partners. Enerplus actively
monitors past due accounts and takes the necessary actions to expedite collection, which can include withholding production, netting amounts off future payments or seeking other remedies including
legal action. Should Enerplus determine that the ultimate collection of a receivable is in doubt, it will provide the necessary provision in its allowance for doubtful accounts with a corresponding
charge to earnings. If Enerplus subsequently determines an account is uncollectible the account is written off with a corresponding charge to the allowance account. Enerplus' allowance for doubtful
accounts balance at March 31, 2016 was $3.2 million (December 31, 2015 – $3.2 million).
(iii) Liquidity Risk & Capital Management
Liquidity risk represents the risk that Enerplus will be unable to meet its financial obligations as they become due. Enerplus mitigates liquidity risk through
actively managing its capital, which it defines as debt (net of cash) and shareholders' capital. Enerplus' objective is to provide adequate short and longer term liquidity while maintaining a
flexible capital structure to sustain the future development of its business. Enerplus strives to balance the portion of debt and equity in its capital structure given its current oil and natural gas
assets and planned investment opportunities.
Management
monitors a number of key variables with respect to its capital structure, including debt levels, capital spending plans, dividends, access to capital markets, as well as acquisition and
divestment activity.
At
March 31, 2016, Enerplus was in full compliance with all covenants under the bank credit facility and outstanding senior notes.
16) CONTINGENCIES
Enerplus is subject to various legal claims and actions arising in the normal course of business. Although the outcome of such claims and actions cannot be
predicted with certainty, the Company does not expect these matters to have a material impact on the Consolidated Financial Statements. In instances where the Company determines that a loss is
probable and the amount can be reasonably estimated, an accrual is recorded.
36 ENERPLUS 2016 Q1
REPORT
17) SUPPLEMENTAL CASH FLOW INFORMATION
a) Changes in Non-Cash Operating Working Capital
| ($ thousands) |
|
|
Three months ended,
March 31, 2016 |
|
|
|
|
Three months ended,
March 31, 2015 |
|
|
|
|
|
| Accounts receivable |
|
$ |
61,077 |
|
|
|
$ |
47,966 |
|
|
| Other current assets |
|
|
3,331 |
|
|
|
|
(4,798 |
) |
|
| Accounts payable |
|
|
(33,934 |
) |
|
|
|
(17,346 |
) |
|
|
|
|
| |
|
$ |
30,474 |
|
|
|
$ |
25,822 |
|
|
|
|
|
b) Other
| ($ thousands) |
|
|
Three months ended,
March 31, 2016 |
|
|
|
|
Three months ended,
March 31, 2015 |
|
|
|
|
|
| Income taxes paid/(received) |
|
$ |
(1,924 |
) |
|
|
$ |
(19,344 |
) |
|
| Interest paid |
|
$ |
9,806 |
|
|
|
$ |
6,482 |
|
|
|
|
|
18) SUBSEQUENT EVENTS
Subsequent to March 31, 2016, Enerplus entered into an agreement to sell non-core assets in Northwest Alberta for proceeds of approximately
$95.5 million, before closing adjustments. A gain of approximately $70 million is expected to be recognized on this transaction.
Subsequent
to March 31, 2016, Enerplus repurchased US$95 million in senior notes at a discount, and it is expected that an additional gain on repurchase will be recorded.
ENERPLUS 2016 Q1
REPORT 37
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Exhibit 99.3
FORM 52-109F2
CERTIFICATION OF INTERIM FILINGS
FULL CERTIFICATE
I,
IAN C. DUNDAS, President and Chief Executive Officer of Enerplus Corporation, certify the following:
- 1.
- Review: I have reviewed the interim financial report and interim MD&A (together, the "interim
filings") of Enerplus Corporation (the "issuer") for the interim period ended March 31, 2016.
- 2.
- No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim
filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the
circumstances under which it was made, with respect to the period covered by the interim filings.
- 3.
- Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim
financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of
the issuer, as of the date of and for the periods presented in the interim filings.
- 4.
- Responsibility: The issuer's other certifying officer and I are responsible for establishing and
maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers' Annual and
Interim Filings, for the issuer.
- 5.
- Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3,
the issuer's other certifying officer and I have, as at the end of the period covered by the interim filings
- (a)
- designed
DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that
- (i)
- material
information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being
prepared; and
- (ii)
- information
required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities
legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and
- (b)
- designed
ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with the issuer's GAAP.
- 5.1
- Control framework: The control framework the issuer's other certifying officer and I used to
design the issuer's ICFR is Internal Control — Integrated Framework (2013 Framework) issued by the Committee of
Sponsoring Organizations of the Treadway Commission.
- 5.2
- ICFR — material weakness relating to design: N/A
- 5.3
- Limitation on scope of design: N/A
- 6.
- Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the
issuer's ICFR that occurred during the period beginning on January 1, 2016 and ended on March 31, 2016 that has materially affected, or is reasonably likely to materially affect, the
issuer's ICFR.
Date:
May 6, 2016
(signed by)
Ian
C. Dundas
President and Chief Executive Officer
Enerplus Corporation
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FORM 52-109F2 CERTIFICATION OF INTERIM FILINGS FULL CERTIFICATE
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Exhibit 99.4
FORM 52-109F2
CERTIFICATION OF INTERIM FILINGS
FULL CERTIFICATE
I,
JODI JENSON LABRIE, Senior Vice President and Chief Financial Officer of Enerplus Corporation, certify the following:
- 1.
- Review: I have reviewed the interim financial report and interim MD&A (together, the "interim
filings") of Enerplus Corporation (the "issuer") for the interim period ended March 31, 2016.
- 2.
- No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim
filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the
circumstances under which it was made, with respect to the period covered by the interim filings.
- 3.
- Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim
financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of
the issuer, as of the date of and for the periods presented in the interim filings.
- 4.
- Responsibility: The issuer's other certifying officer and I are responsible for establishing and
maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers' Annual and
Interim Filings, for the issuer.
- 5.
- Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3,
the issuer's other certifying officer and I have, as at the end of the period covered by the interim filings
- (a)
- designed
DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that
- (i)
- material
information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being
prepared; and
- (ii)
- information
required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities
legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and
- (b)
- designed
ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with the issuer's GAAP.
- 5.1
- Control framework: The control framework the issuer's other certifying officer and I used to
design the issuer's ICFR is Internal Control — Integrated Framework (2013 Framework) issued by The Committee of
Sponsoring Organizations of the Treadway Commission.
- 5.2
- ICFR — material weakness relating to design: N/A
- 5.3
- Limitation on scope of design: N/A
- 6.
- Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the
issuer's ICFR that occurred during the period beginning on January 1, 2016 and ended on March 31, 2016 that has materially affected, or is reasonably likely to materially affect, the
issuer's ICFR.
Date:
May 6, 2016
(signed by)
Jodi
Jenson Labrie
Senior Vice President and Chief Financial Officer
Enerplus Corporation
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FORM 52-109F2 CERTIFICATION OF INTERIM FILINGS FULL CERTIFICATE
This regulatory filing also includes additional resources:
a2228533zex99-1.pdfa2228533zex99-2.pdf
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