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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, 2015
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, 2015
EXHIBIT
99.2 — Unaudited Consolidated Financial Statements for the First Quarter ended March 31, 2015
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 8, 2015
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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 7, 2015 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, 2015 and 2014 (the "Interim Financial Statements");
- •
- the
audited consolidated financial statements of Enerplus as at December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013
and 2012 (the "Financial Statements"); and
- •
- our
MD&A for the year ended December 31, 2014 (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.
6 ENERPLUS 2015 Q1
REPORT
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. The term netback is calculated as oil and natural gas sales less royalties, production taxes, cash operating costs and transportation.
| |
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Three months ended March 31,
|
Calculation of Netback
($ millions) |
|
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2015 |
|
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2014 |
|
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| Oil and natural gas sales |
|
$ |
244.1 |
|
|
|
$ |
495.0 |
|
|
| Less: |
|
|
|
|
|
|
|
|
|
|
| |
Royalties |
|
|
(39.1 |
) |
|
|
|
(87.3 |
) |
|
| |
Production taxes |
|
|
(10.8 |
) |
|
|
|
(19.9 |
) |
|
| |
Cash operating costs(1) |
|
|
(86.8 |
) |
|
|
|
(79.8 |
) |
|
| |
Transportation |
|
|
(26.5 |
) |
|
|
|
(22.3 |
) |
|
|
|
|
| Netback before hedging |
|
$ |
80.9 |
|
|
|
$ |
285.7 |
|
|
| |
Cash gains/(losses) on derivative instruments |
|
|
86.8 |
|
|
|
|
(15.3 |
) |
|
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| Netback after hedging |
|
$ |
167.7 |
|
|
|
$ |
270.4 |
|
|
|
|
|
- (1)
- Operating
costs adjusted to exclude non-cash losses on fixed price electricity swaps of $0.9 million in the three months ended March 31, 2015 and
$0.1 million in the three months ended March 31, 2014.
"Funds Flow" is used by Enerplus and is useful to investors and securities analysts in analyzing operating
performance, leverage and liquidity. Funds flow is calculated as net cash provided by operating activities before asset retirement obligation expenditures and changes in non-cash operating working
capital.
| |
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Three months ended March 31,
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Reconciliation of Cash Flow from Operating Activities to Funds Flow
($ millions) |
|
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2015 |
|
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2014 |
|
|
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| Cash flow from operating activities |
|
$ |
131.1 |
|
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$ |
140.4 |
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| Asset retirement obligation expenditures |
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|
3.9 |
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4.3 |
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| Changes in non-cash operating working capital |
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(25.8 |
) |
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75.8 |
|
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| Funds flow |
|
$ |
109.2 |
|
|
|
$ |
220.5 |
|
|
|
|
"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 12 months of funds flow. This measure is not equivalent to Debt to EBITDA and
is not used by Enerplus to determine compliance with financial covenants.
"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 cash dividends plus capital and office expenditures divided by funds flow.
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Three months ended March 31,
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Calculation of Adjusted Payout Ratio
($ millions) |
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2015 |
|
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2014 |
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| Cash dividends(1) |
|
$ |
47.4 |
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$ |
42.1 |
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| Capital and office expenditures |
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|
167.9 |
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|
218.2 |
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|
| |
|
$ |
215.3 |
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$ |
260.3 |
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| Funds flow |
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|
109.2 |
|
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|
220.5 |
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| Adjusted payout ratio (%) |
|
|
197% |
|
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|
118% |
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- (1)
- Cash
dividends exclude Stock Dividend Plan proceeds in 2014.
ENERPLUS 2015 Q1
REPORT 7
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 proven 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.
OVERVIEW
Our strong operational performance continued during the first quarter of 2015 as we focused on execution under a disciplined capital program. We met or exceeded
all guidance targets and exited the quarter with a strong balance sheet.
Average
daily production for the first quarter was 100,855 BOE/day, exceeding our guidance range of 93,000 – 100,000 BOE/day. Production was
slightly lower compared to the fourth quarter of 2014 as we delayed North Dakota completions in response to low oil prices and cost uncertainties. We expect to re-establish growth in North Dakota in
the second quarter as prices stabilize and costs are reduced. We continued to curtail Marcellus production during the quarter with total curtailments in line with our guidance. We are well positioned
to achieve our annual average production guidance of 93,000 – 100,000 BOE/day and our crude oil and liquids guidance of
42% – 44% despite the previously announced sale of non-core crude oil assets which closed subsequent to the quarter.
First
quarter funds flow decreased to $109.2 million from $220.5 million in the same period in 2014 as oil and gas sales reflected the dramatic decline in commodity prices. Our commodity
hedges provided protection with cash gains of $86.8 million in the first quarter compared to losses of $15.3 million in the same period in 2014. Current quarter funds flow was reduced by
$11 million as a result of a number of one-time charges including severance payments, rig termination charges and retroactive royalty adjustments. In addition, we recorded cash losses of
$8.6 million on our foreign exchange collars as the Canadian dollar weakened against the U.S. dollar.
We
reported a net loss of $293.2 million for the quarter compared to net income of $40.0 million in the same quarter of 2014. Our first quarter earnings benefited from commodity hedging
gains of $50.4 million and one-time realized foreign exchange gains of $39.9 million as we crystalized gains on US$175 million in foreign exchange swaps. These gains were offset
by asset impairment charges of $267.6 million in our U.S. cost centre as a result of the use of a 12-month trailing average commodity price to determine impairment, in accordance with
U.S. GAAP.
Capital
spending is on track, with $167.0 million spent in the first quarter. We continue to expect to spend $480 million in 2015 with the majority of spending weighted to the first half
of the year.
General
and administrative costs came in slightly under guidance of $2.40/BOE at $21.4 million or $2.36/BOE for the quarter compared to $20.5 million or $2.31/BOE in the first quarter of
2014, despite the inclusion of one-time charges for severance.
Effective
in 2015 we have reclassified Marcellus gathering charges from operating expenses to transportation costs. These charges pertain to pipeline costs paid to third parties to transport saleable
natural gas in the Marcellus from the lease to a downstream point of sale. This is a change in presentation and does not affect our netbacks, funds flow or net income. During the first quarter of
2015, gathering costs of $12.4 million or $1.37/BOE were reclassified from operating expenses to transportation costs. We expect annual gathering fees of approximately $1.35/BOE in 2015.
Based
on the reclassification of $1.35/BOE of annual gathering costs, we are revising our 2015 guidance for operating costs downwards from $11.10/BOE to $9.75/BOE. Operating expenses came in below our
revised guidance, totaling $87.7 million or $9.66/BOE compared to $79.9 million or $8.98/BOE in the first quarter of 2014. Operating costs in the first quarter were $6.1 million
lower compared to the fourth quarter of 2014 as we began to see cost savings materialize. We are issuing 2015 transportation guidance of $3.00/BOE compared to previous transportation of $1.65/BOE.
Transportation costs for the quarter were $26.5 million or $2.92/BOE, compared to $22.3 million or $2.51/BOE for the same period in 2014. Our aggregate guidance remains unchanged.
Despite
a continued decline in commodity prices during the quarter we have maintained a strong balance sheet. At March 31, 2015, we were approximately 13% drawn on our
$1.0 billion credit facility and had a debt to funds flow ratio of 1.7x and Senior Debt to Earnings before Interest, Taxes, Depreciation and Amortization and other non-cash charges ("EBITDA")
ratio of 1.6x. Subsequent to the quarter, we closed non-core asset sales with combined proceeds of $185.8 million, net of closing costs, and used the proceeds to repay our outstanding debt.
These divestments include the previously announced sale of our Pembina waterflood assets which closed on April 15, 2015.
8 ENERPLUS 2015 Q1
REPORT
RESULTS OF OPERATIONS
Production
Production for the first quarter totaled 100,855 BOE/day, exceeding our guidance range of
93,000 – 100,000 BOE/day and increasing 2% compared to 98,821 BOE/day in the first quarter of 2014. This increase was driven by growth in our Fort
Berthold assets, where production increased 6% year over year due to our ongoing development program. Gas production remained relatively flat compared to the first quarter of 2014, with growth of
almost 10% in our Marcellus gas production offset by the divestment of non-core Canadian natural gas properties in the second half of 2014.
Compared
to production in the fourth quarter of 2014 of 105,591 BOE/day, production was down 4% primarily due to decreased crude oil and liquids production in the U.S. as we delayed
North Dakota completions in response to low oil prices and cost uncertainties. Natural gas production also decreased slightly, down 3% compared to the fourth quarter. We continued to curtail our
Marcellus natural gas production during the quarter in line with our guidance range.
Given
the decrease in our crude oil production, our crude oil and natural gas liquids weighting decreased to 43% in the first quarter of 2015 from 44% in the fourth quarter of 2014. Our crude oil and
natural gas liquids production remains in line with our guidance range of 42% – 44%.
Average
daily production volumes for the three months ended March 31, 2015 and 2014 are outlined below:
| |
|
Three months ended March 31,
|
| Average Daily Production Volumes |
|
2015 |
|
|
2014 |
|
% Change |
|
|
|
|
| Crude oil (bbls/day) |
|
39,355 |
|
|
37,760 |
|
4% |
|
| Natural gas liquids (bbls/day) |
|
3,735 |
|
|
3,262 |
|
15% |
|
| Natural gas (Mcf/day) |
|
346,589 |
|
|
346,794 |
|
0% |
|
|
|
|
| Total daily sales (BOE/day) |
|
100,855 |
|
|
98,821 |
|
2% |
|
|
|
|
We are maintaining our annual average production guidance for 2015 of 93,000 – 100,000 BOE/day and are well
positioned to achieve both our production and liquids guidance despite the sale of non-core assets with production of approximately 1,900 BOE/day that closed subsequent to the quarter. This
guidance includes our previously announced divestments but does not contemplate any additional acquisitions or divestments.
ENERPLUS 2015 Q1
REPORT 9
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 2015 to the first quarter of 2014:
| Pricing (average for the period) |
|
|
Q1 2015 |
|
|
|
|
Q4 2014 |
|
|
Q3 2014 |
|
|
Q2 2014 |
|
|
Q1 2014 |
|
|
|
|
|
| Benchmarks |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
WTI crude oil (US$/bbl) |
|
$ |
48.64 |
|
|
|
$ |
73.15 |
|
$ |
97.17 |
|
$ |
102.99 |
|
$ |
98.68 |
|
|
| |
AECO natural gas – monthly index (CDN$/Mcf) |
|
|
2.95 |
|
|
|
|
4.01 |
|
|
4.22 |
|
|
4.68 |
|
|
4.76 |
|
|
| |
AECO natural gas – daily index (CDN$/Mcf) |
|
|
2.75 |
|
|
|
|
3.60 |
|
|
4.02 |
|
|
4.69 |
|
|
5.71 |
|
|
| |
NYMEX natural gas – last day (US$/Mcf) |
|
|
2.98 |
|
|
|
|
4.00 |
|
|
4.06 |
|
|
4.67 |
|
|
4.94 |
|
|
| |
US/CDN exchange rate |
|
|
1.24 |
|
|
|
|
1.14 |
|
|
1.09 |
|
|
1.09 |
|
|
1.10 |
|
|
Enerplus selling price(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Crude oil (CDN$/bbl) |
|
$ |
44.04 |
|
|
|
$ |
69.17 |
|
$ |
88.28 |
|
$ |
96.46 |
|
$ |
93.04 |
|
|
| |
Natural gas liquids (CDN$/bbl) |
|
|
22.48 |
|
|
|
|
42.34 |
|
|
46.76 |
|
|
51.80 |
|
|
67.90 |
|
|
| |
Natural gas (CDN$/Mcf) |
|
|
2.58 |
|
|
|
|
3.25 |
|
|
3.36 |
|
|
4.15 |
|
|
5.07 |
|
|
|
|
|
| Average differentials |
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
| |
MSW Edmonton – WTI (US$/bbl) |
|
$ |
(6.80 |
) |
|
|
$ |
(6.36 |
) |
$ |
(7.93 |
) |
$ |
(6.13 |
) |
$ |
(8.25 |
) |
|
| |
WCS Hardisty – WTI (US$/bbl) |
|
|
(14.73 |
) |
|
|
|
(14.24 |
) |
|
(20.18 |
) |
|
(20.04 |
) |
|
(23.13 |
) |
|
| |
Brent Futures (ICE) – WTI (US$/bbl) |
|
|
6.58 |
|
|
|
|
3.85 |
|
|
6.26 |
|
|
6.75 |
|
|
9.19 |
|
|
| |
AECO monthly – NYMEX (US$/Mcf) |
|
|
(0.60 |
) |
|
|
|
(0.47 |
) |
|
(0.18 |
) |
|
(0.38 |
) |
|
(0.63 |
) |
|
Enerplus realized differentials(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Canada crude oil – WTI (US$/bbl) |
|
$ |
(15.22 |
) |
|
|
$ |
(12.17 |
) |
$ |
(20.51 |
) |
$ |
(16.77 |
) |
$ |
(20.07 |
) |
|
| |
Canada natural gas – NYMEX (US$/Mcf) |
|
|
(0.46 |
) |
|
|
|
(0.62 |
) |
|
(0.29 |
) |
|
(0.46 |
) |
|
(0.04 |
) |
|
| |
Bakken crude oil – WTI (US$/bbl) |
|
|
(11.65 |
) |
|
|
|
(12.15 |
) |
|
(12.81 |
) |
|
(12.81 |
) |
|
(9.82 |
) |
|
| |
Marcellus natural gas – NYMEX (US$/Mcf) |
|
|
(1.32 |
) |
|
|
|
(1.62 |
) |
|
(1.70 |
) |
|
(1.48 |
) |
|
(0.86 |
) |
|
|
|
|
- (1)
- Before
transportation costs, royalties and commodity derivative instruments.
Crude Oil and Natural Gas Liquids
WTI crude oil prices continued their decline from the previous quarter, averaging US$48.64/bbl due to global oversupply and growing inventories in the U.S.,
which increased by 22% from the end of 2014. Growing concerns that storage could reach maximum levels in certain regions, specifically at Cushing, Oklahoma, resulted in daily WTI prices settling at a
low of US$43.46/bbl in March. WTI prices have since recovered as the threat of storage congestion in the U.S. has eased somewhat heading into the summer.
Heavy
crude oil differentials in Canada weakened slightly during the quarter, with WCS averaging US$14.73/bbl below WTI, compared to US$14.24/bbl below WTI in the previous quarter. Light crude oil
differentials also weakened, averaging US$6.80/bbl below WTI during the quarter, compared to US$6.36/bbl in the previous quarter. Canadian heavy oil production continued to move on rail despite higher
transportation costs compared to pipelines due to existing term rail commitments made by shippers. Despite Canadian crude differentials trading wider in the quarter, the outlook ahead is positive.
Improved market access, particularly to the U.S. Gulf Coast, has reduced the downside impact mid-continent refinery outages have historically had on Canadian prices. Reduced supply from oil
sands producers due to seasonal maintenance is expected to further strengthen Canadian crude oil differentials in the second quarter.
In
the U.S., our average realized crude oil differential was US$11.65/bbl less than WTI, an improvement of US$0.50/bbl versus the previous quarter. Strong Brent/WTI spreads improved the netback
associated with oil sold to rail buyers. Increased rail capacity coming into service started to compete for production that would otherwise flow via pipeline, which caused narrowing Bakken
differentials during the quarter.
The reversal of Enbridge's Line 9 scheduled for the second quarter of 2015 is expected to provide support for U.S. Bakken differentials in the coming months.
Our
sales price for natural gas liquids during the quarter fell by 47% compared to the fourth quarter of 2014 to average $22.48/bbl. The price received for propane decreased almost 60% versus the
previous quarter due to the decline in crude oil prices as well as rapidly building inventories, with propane stocks in the U.S. almost 90% higher on average during the quarter compared to the
same period last year. Additionally, the benchmark prices for butane and condensate fell by 27% and 30%, respectively, during the quarter due to the significant weakness in crude oil prices.
10 ENERPLUS 2015 Q1
REPORT
Natural Gas
Natural gas prices at both AECO and NYMEX were sharply lower in the quarter as strong production in the U.S. combined with a lengthy delay to winter
demand in key regions in the U.S. allowed gas in storage to return to more seasonally average levels compared to this time last year. AECO monthly index prices fell by 26% versus the previous
quarter to average $2.95/Mcf, while NYMEX gas prices also fell by 26% to average US$2.98/Mcf. Natural gas prices have continued to weaken throughout April as we head into a shoulder season for demand
and U.S. production remains strong relative to last year.
Natural
gas prices in the Marcellus also traded sharply lower in the quarter. Spot prices on the Transco Leidy pipeline averaged US$1.29/Mcf and TGP Zone 4 Marcellus daily prices averaged
US$1.29/Mcf, both over 35% lower than the previous quarter. Outside of the northeast Pennsylvania producing region, prices at Dominion South Point fell by only 22% to average US$1.85/Mcf in
the quarter.
With
approximately 46% of our Marcellus production sold under long-term sales contracts with stronger price exposure outside of the northeast Pennsylvania producing region, our overall realized
Marcellus sales price was US$1.66/Mcf. This equated to a discount to NYMEX of US$1.32/Mcf for our Marcellus production.
Foreign
Exchange
During the first quarter of 2015 the Canadian dollar continued to weaken and fell 8%; the largest quarterly decline since 2008 during the credit crisis. This
was due to a number of factors including the Bank of Canada's unexpected interest rate cut of 25 basis points in January, the continued decline of global oil prices, and the anticipation of
increasing interest rates in the U.S. as a result of a strengthening economy. The Canadian dollar began the year at a USD/CDN exchange rate of 1.17 and weakened to 1.28 before ending the
quarter at 1.27. Subsequent to the quarter end, the Canadian dollar has strengthened to 1.20 as a result of improved oil prices and a more balanced tone from the Bank of Canada. The majority of
our oil and gas sales are based on U.S. dollar denominated indices and therefore a weaker Canadian dollar relative to the U.S. dollar increases the amount of our realized sales. Because
we report in Canadian dollars, the weaker Canadian dollar also increases our U.S. dollar denominated operating costs, capital spending and the interest on our U.S. dollar denominated
senior notes.
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. As of
May 5, 2015, we have swapped an average of 16,841 bbls/day of crude oil from April 1, 2015 to June 30, 2015 at an average price of US$90.40/bbl, which
represents approximately 54% of our forecasted crude oil production after royalties for the same period. For the second half of 2015, we have 8,000 bbls/day of crude oil swapped at an average
price of US$93.86/bbl, which represents approximately 26% of our forecasted crude oil production after royalties. In relation to these swaps, we have purchased call options to participate in price
upside above US$93.00/bbl on 4,000 bbls/d, and sold put options at an average strike price of US$62.23/bbl, offsetting the cost of the call premium. If actual monthly WTI prices fall below
US$62.23/bbl for individual months during the remainder of 2015, our swaps on approximately 13% of our forecasted net crude oil production are effectively converted to WTI monthly index plus
US$29.87/bbl, using a weighted average swap price for the year of $92.10/bbl. Additionally, we have entered into WCS differential swap positions to manage our exposure related to Canadian crude oil
differentials. Overall, we expect our crude related hedge contracts to protect a significant portion of our funds flow during 2015.
For
2016, we have downside protection on 26% of our forecasted crude oil production net of royalties, with 6,000 bbls/day protected through 3 way collars (US$50/bbl by US$65/bbl by
$US80/bbl), and an additional 2,000 bbls/day swapped at $65.50/bbl.
During
the quarter we added modestly to our 2015 NYMEX gas hedge program. As of May 5, 2015, we are swapped on an average of 115,600 Mcf/day at an average price of US$3.92/Mcf for
the remainder of 2015, representing approximately 46% of our forecasted natural gas production after royalties. In relation to the swaps, we have purchased a call spread on 5,000 Mcf/d to
participate in NYMEX price upside and sold NYMEX put options on 5,000 Mcf/day at an average price of $3.25/Mcf to offset the net cost of the call spread. We do not have any gas hedging in place
for 2016.
ENERPLUS 2015 Q1
REPORT 11
The
following is a summary of our financial contracts in place at May 5, 2015, expressed as a percentage of our anticipated net production volumes:
| |
|
WTI Crude Oil (US$/bbl)(1)
|
|
NYMEX Natural Gas (US$/Mcf)(1)
|
|
| |
|
|
Apr 1,
2015 –
Jun 30,
2015 |
|
|
Jul 1,
2015 –
Dec 31,
2015 |
|
|
Jan 1,
2016 –
Dec 31,
2016 |
|
|
Apr 1,
2015 –
Jun 30,
2015 |
|
|
Jul 1,
2015 –
Sep 30,
2015 |
|
|
Oct 1,
2015 –
Oct 31,
2015 |
|
|
Nov 1,
2015 –
Dec 31,
2015 |
|
|
| Downside Protection |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Sold Swaps |
|
$ |
90.40 |
|
$ |
93.86 |
|
$ |
65.50 |
|
$ |
3.98 |
|
$ |
3.83 |
|
$ |
3.85 |
|
$ |
4.04 |
|
| % |
|
|
54% |
|
|
26% |
|
|
7% |
|
|
43% |
|
|
53% |
|
|
45% |
|
|
37% |
|
| Purchased Puts |
|
|
– |
|
|
– |
|
$ |
65.00 |
|
|
– |
|
|
– |
|
|
– |
|
|
– |
|
| % |
|
|
– |
|
|
– |
|
|
19% |
|
|
– |
|
|
– |
|
|
– |
|
|
– |
|
Upside Participation Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Sold Puts |
|
$ |
62.23 |
|
$ |
62.23 |
|
$ |
50.00 |
|
$ |
3.25 |
|
$ |
3.25 |
|
$ |
3.25 |
|
$ |
3.25 |
|
| % |
|
|
13% |
|
|
13% |
|
|
19% |
|
|
2% |
|
|
2% |
|
|
2% |
|
|
2% |
|
| Purchased Calls |
|
|
93.00 |
|
|
93.00 |
|
|
– |
|
$ |
4.29 |
|
$ |
4.29 |
|
$ |
4.29 |
|
$ |
4.29 |
|
| % |
|
|
13% |
|
|
13% |
|
|
– |
|
|
2% |
|
|
2% |
|
|
2% |
|
|
2% |
|
| Sold Calls |
|
|
– |
|
|
– |
|
$ |
80.00 |
|
$ |
5.00 |
|
$ |
5.00 |
|
$ |
5.00 |
|
$ |
5.00 |
|
| % |
|
|
– |
|
|
– |
|
|
19% |
|
|
2% |
|
|
2% |
|
|
2% |
|
|
2% |
|
|
- (1)
- Based
on weighted average price (before premiums) and assumed average annual production of 93,000 – 100,000 BOE/day for 2015 and 2016,
less royalties and production taxes of 21.0% in aggregate.
During 2014, we entered into foreign exchange collars to hedge a floor exchange rate on a portion of our U.S. dollar denominated oil and natural gas
sales with upside participation in the event the Canadian dollar weakened. As of May 5, 2015 we have US$24 million per month hedged for 2015 at an average USD/CDN floor of 1.1088,
a ceiling of 1.1845 and a conditional ceiling of 1.1263. Under these contracts, if the monthly foreign exchange rate settles above the ceiling rate the conditional ceiling is used to determine the
settlement amount.
ACCOUNTING
FOR PRICE RISK MANAGEMENT
| |
|
Three months ended March 31,
|
Commodity Risk Management Gains/(Losses)
($ millions) |
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
|
| Cash gains/(losses): |
|
|
|
|
|
|
|
|
|
|
| |
Crude oil |
|
$ |
70.6 |
|
|
|
$ |
(10.7 |
) |
|
| |
Natural gas |
|
|
16.2 |
|
|
|
|
(4.6 |
) |
|
|
|
|
| Total cash gains/(losses) |
|
$ |
86.8 |
|
|
|
$ |
(15.3 |
) |
|
Non-cash gains/(losses): |
|
|
|
|
|
|
|
|
|
|
| |
Change in fair value – crude oil |
|
$ |
(36.0 |
) |
|
|
$ |
(9.4 |
) |
|
| |
Change in fair value – natural gas |
|
|
(0.4 |
) |
|
|
|
(7.9 |
) |
|
|
|
|
| Total non-cash gains/(losses) |
|
$ |
(36.4 |
) |
|
|
$ |
(17.3 |
) |
|
|
|
|
| Total gains/(losses) |
|
$ |
50.4 |
|
|
|
$ |
(32.6 |
) |
|
|
|
|
| |
|
Three months ended March 31,
|
| (Per BOE) |
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
|
| Total cash gains/(losses) |
|
$ |
9.56 |
|
|
|
$ |
(1.72 |
) |
|
| Total non-cash gains/(losses) |
|
|
(4.01 |
) |
|
|
|
(1.94 |
) |
|
|
|
|
| Total gains/(losses) |
|
$ |
5.55 |
|
|
|
$ |
(3.66 |
) |
|
|
|
|
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. In comparison, during the first quarter of 2014, we realized cash losses of $10.7 million on our crude oil contracts and $4.6 million on
12 ENERPLUS 2015 Q1
REPORT
our
natural gas contracts. The cash gains in 2015 were due to contracts which provided floor protection above market prices, while cash losses in 2014 were a result of prices rising above our fixed
price swap positions.
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 2015 the fair value of our crude oil and natural gas contracts represented net gain positions of $131.2 million and $48.8 million,
respectively. The change in the fair value of our crude oil and natural gas contracts during the first quarter of 2015 represented losses of $36.0 million and $0.4 million, respectively.
During
the first quarter of 2015 we recorded total cash losses of $8.6 million on our foreign exchange collars and $39.9 million in cash gains on the unwind of our US$175 million
in foreign exchange swaps. Unrealized foreign exchange derivative losses of $51.8 million included $27.6 million to reverse cumulative mark-to-market gains on the foreign exchange swaps
and $24.2 million of mark-to-market losses on our foreign exchange collars. At March 31, 2015, the fair value of foreign exchange derivatives was a net loss of
$29.9 million. See Note 15 for further information.
Revenues
| |
|
Three months ended March 31,
|
| ($ millions) |
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
|
| Oil and natural gas sales |
|
$ |
244.1 |
|
|
|
$ |
495.0 |
|
|
| Royalties |
|
|
(39.1 |
) |
|
|
|
(87.3 |
) |
|
|
|
|
| Oil and natural gas sales, net of royalties |
|
$ |
205.0 |
|
|
|
$ |
407.7 |
|
|
|
|
|
Oil and natural gas revenues were $244.1 million in the first quarter of 2015, a decrease of 51% or $250.9 million compared to the same period in
2014. The decrease in revenue was driven by the weak commodity price environment, which saw benchmark prices decline between 40% and 50% in the first quarter of 2015 compared to the same period
in 2014.
Royalties and Production Taxes
| |
|
Three months ended March 31,
|
| ($ millions, except per BOE amounts) |
|
|
2015 |
|
|
|
2014 |
|
|
|
|
| Royalties |
|
$ |
39.1 |
|
|
$ |
87.3 |
|
| Per BOE |
|
$ |
4.31 |
|
|
$ |
9.82 |
|
Production taxes |
|
$ |
10.8 |
|
|
$ |
19.9 |
|
| Per BOE |
|
$ |
1.19 |
|
|
$ |
2.23 |
|
|
|
|
| Royalties and production taxes |
|
$ |
49.9 |
|
|
$ |
107.2 |
|
| Per BOE |
|
$ |
5.50 |
|
|
$ |
12.05 |
|
Royalties and production taxes (% of oil and natural gas sales, before transportation) |
|
|
20% |
|
|
|
22% |
|
|
|
|
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. During the first quarter royalties and production taxes decreased to $49.9 million from $107.2 million in the same quarter of
2014, primarily due to lower realized prices. Royalties and production taxes averaged 20% of oil and gas sales before transportation in 2015 compared to 22% for the same period in 2014.
We
continue to expect an average royalty and production tax rate of 21% in 2015.
Operating Expenses and Transportation Costs
As of January 1, 2015, we have reclassified Marcellus gathering costs from operating expenses to transportation costs. These charges relate to
pipeline costs paid to third parties to transport saleable natural gas from the lease to downstream points of sale. This is a presentation change with no impact on our netback, funds flow or net
income. All comparative periods have been presented to conform with the current period presentation.
ENERPLUS 2015 Q1
REPORT 13
During
the first quarter of 2015, Marcellus gathering fees were $12.4 million or $1.37/BOE compared to $9.2 million or $1.04/BOE during the same period of 2014.
Total
operating expenses and transportation costs for the current quarter and comparative periods before and after the reclassification are provided below:
| |
|
2015
Guidance
|
|
Three months ended March 31, 2015
|
|
Three months ended March 31, 2014
|
| |
|
|
Per BOE |
|
|
$ millions |
|
|
Per BOE |
|
|
|
|
$ millions |
|
|
Per BOE |
|
|
|
|
|
| Operating Expenses, before reclassification |
|
$ |
11.10 |
|
$ |
100.1 |
|
$ |
11.03 |
|
|
|
$ |
89.1 |
|
$ |
10.02 |
|
|
| Gathering Fees |
|
|
(1.35 |
) |
|
(12.4 |
) |
|
(1.37 |
) |
|
|
|
(9.2 |
) |
|
(1.04 |
) |
|
|
|
|
| Operating Expenses, after reclassification |
|
$ |
9.75 |
|
$ |
87.7 |
|
$ |
9.66 |
|
|
|
$ |
79.9 |
|
$ |
8.98 |
|
|
Transportation Costs, before reclassification |
|
$ |
1.65 |
(1) |
$ |
14.1 |
|
$ |
1.55 |
|
|
|
$ |
13.1 |
|
$ |
1.47 |
|
|
| Gathering Fees |
|
|
1.35 |
|
|
12.4 |
|
|
1.37 |
|
|
|
|
9.2 |
|
|
1.04 |
|
|
|
|
|
| Transportation Costs, after reclassification |
|
$ |
3.00 |
|
$ |
26.5 |
|
$ |
2.92 |
|
|
|
$ |
22.3 |
|
$ |
2.51 |
|
|
|
|
|
- (1)
- Traditionally,
we have not provided guidance for transportation costs (total costs of $1.52/BOE in 2014, before reclassification of gathering costs). After the reclassification of
gathering costs, we are guiding to $3.00/BOE for 2015
Operating costs totaled $87.7 million or $9.66/BOE during the first quarter compared to $79.9 million or $8.98/BOE in the first quarter of 2014.
The increase in operating costs was due the impact of a weak Canadian dollar on our U.S. operating costs along with higher well servicing and repairs and maintenance costs in the U.S.
Compared
to the fourth quarter of 2014, operating costs decreased $6.1 million as we began to realize cost savings across our operations as a result of our ongoing cost control measures. These
savings were offset somewhat by the weakening Canadian dollar.
Transportation
costs totaled $26.5 million or $2.92/BOE, compared to $22.3 million or $2.51/BOE for the same period in 2014. Transportation expense increased over the prior year as a
result of higher Marcellus gathering fees and an overall increase in U.S. transportation fees due to a weak Canadian dollar.
We
are adjusting our 2015 guidance for operating costs from $11.10/BOE to $9.75/BOE and are issuing transportation guidance of $3.00/BOE from $1.65/BOE to take into account the reclassification of the
Marcellus gathering fees of $1.35/BOE between the two categories. The aggregate guidance remains unchanged from the beginning of the year.
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. Certain prior period amounts have been reclassified to conform with current period presentation.
| |
|
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 costs |
|
|
(13.45 |
) |
|
(1.08 |
) |
|
(9.56 |
) |
|
| |
Transportation |
|
|
(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 |
|
|
|
14 ENERPLUS 2015 Q1
REPORT
| |
|
Three months ended March 31, 2014
|
| Netbacks by Property Type |
|
|
Crude Oil |
|
|
Natural Gas |
|
|
Total |
|
|
|
| Average Daily Production |
|
|
42,307 BOE/day |
|
|
339,084 Mcfe/day |
|
|
98,821 BOE/day |
|
|
|
| |
Netback(1) $ per BOE or Mcfe |
|
|
(per BOE |
) |
|
(per Mcfe |
) |
|
(per BOE |
) |
|
|
| |
Oil and natural gas sales(2) |
|
$ |
86.23 |
|
$ |
5.44 |
|
$ |
55.66 |
|
|
| |
Royalties and production taxes |
|
|
(21.64 |
) |
|
(0.81 |
) |
|
(12.05 |
) |
|
| |
Cash operating costs |
|
|
(12.43 |
) |
|
(1.06 |
) |
|
(8.97 |
) |
|
| |
Transportation |
|
|
(1.85 |
) |
|
(0.48 |
) |
|
(2.51 |
) |
|
|
| |
Netback before hedging |
|
$ |
50.31 |
|
$ |
3.09 |
|
$ |
32.13 |
|
|
|
| |
Cash gains/(losses) |
|
|
(2.80 |
) |
|
(0.15 |
) |
|
(1.72 |
) |
|
|
| |
Netback after hedging |
|
$ |
47.51 |
|
$ |
2.94 |
|
$ |
30.41 |
|
|
|
| |
Netback before hedging ($ millions) |
|
$ |
191.5 |
|
$ |
94.2 |
|
$ |
285.7 |
|
|
|
| |
Netback after hedging ($ millions) |
|
$ |
180.9 |
|
$ |
89.5 |
|
$ |
270.4 |
|
|
|
- (1)
- See
"Non-GAAP Measures" in this MD&A.
Our crude oil properties accounted for 69% of our corporate netback before hedging for the first quarter of 2015 compared to 67% for the same period in 2014.
Crude oil and natural gas netbacks per BOE decreased in 2015 from the same period in 2014 as a result of a significant decline in commodity prices. The impact of lower prices was partially offset by
cash hedging gains.
General and Administrative ("G&A") 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 for further detail). SBC charges are dependent on our share price and can fluctuate from period to period.
| |
|
Three months ended March 31,
|
| ($ millions) |
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
|
| Cash: |
|
|
|
|
|
|
|
|
|
|
| |
G&A expense |
|
$ |
21.4 |
|
|
|
$ |
20.5 |
|
|
| |
Share based compensation expense |
|
|
7.3 |
|
|
|
|
6.9 |
|
|
Non-Cash: |
|
|
|
|
|
|
|
|
|
|
| |
Share based compensation expense |
|
|
5.0 |
|
|
|
|
2.9 |
|
|
| |
Equity swap loss/(gain) |
|
|
(1.6 |
) |
|
|
|
(1.2 |
) |
|
|
|
|
| Total G&A expenses |
|
$ |
32.1 |
|
|
|
$ |
29.1 |
|
|
|
|
|
| |
|
Three months ended March 31,
|
| (Per BOE) |
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
|
| Cash: |
|
|
|
|
|
|
|
|
|
|
| |
G&A expense |
|
$ |
2.36 |
|
|
|
$ |
2.31 |
|
|
| |
Share based compensation expense |
|
|
0.80 |
|
|
|
|
0.77 |
|
|
Non-Cash: |
|
|
|
|
|
|
|
|
|
|
| |
Share based compensation expense |
|
|
0.55 |
|
|
|
|
0.33 |
|
|
| |
Equity swap loss/(gain) |
|
|
(0.18 |
) |
|
|
|
(0.14 |
) |
|
|
|
|
| Total G&A expenses |
|
$ |
3.53 |
|
|
|
$ |
3.27 |
|
|
|
|
|
Cash G&A expenses during the first quarter of 2015 were $21.4 million or $2.36/BOE, in line with guidance of $2.40/BOE and slightly higher than
$20.5 million or $2.31/BOE in the first quarter of 2014. The increase in cash G&A for the first quarter was primarily due to one-time severance payments of $2.0 million.
Our
share price increased by 15% during the quarter, increasing our cash and non-cash SBC to $7.3 million ($0.80/BOE) and $5.0 million ($0.55/BOE), respectively, compared to
$6.9 million ($0.77/BOE) and $2.9 million ($0.33/BOE) during the same period in 2014.
ENERPLUS 2015 Q1
REPORT 15
We
have 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
$1.6 million on these hedges during the first quarter of 2015. As of March 31, 2015 we had 630,000 units hedged at a weighted average price of $15.82/share.
We
continue to expect cash G&A expenses of approximately $2.40/BOE for 2015. We do not provide guidance for SBC because it is dependent on our share price and our performance relative to
our peers.
Interest Expense
| |
|
Three months ended March 31,
|
| ($ millions) |
|
|
2015 |
|
|
|
2014 |
|
|
|
|
| Interest on senior notes and bank facility |
|
$ |
16.8 |
|
|
$ |
14.7 |
|
| Non-cash interest expense |
|
|
0.2 |
|
|
|
0.5 |
|
|
|
|
| Total interest expense |
|
$ |
17.0 |
|
|
$ |
15.2 |
|
|
|
|
We recorded total interest expense of $17.0 million during the first quarter of 2015 compared to $15.2 million for the same period in 2014. The
increase in interest expense corresponds to an increase in higher interest rate senior notes following our September 2014 private placement of US$200 million, the proceeds of which were
used to repay our short-term bank debt. Interest expense was further increased by the impact of a weaker Canadian dollar on our U.S. dollar denominated interest payments.
Non-cash
amounts recorded in interest expense include amortization of deferred financing charges. See Note 11 for further details.
At
March 31, 2015 approximately 90% of our debt was based on fixed interest rates and 10% on floating interest rates, with weighted average interest rates of 5.3% and 2.6%, respectively.
Foreign Exchange
| |
|
Three months ended March 31,
|
| ($ millions) |
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
| Realized loss/(gain) |
|
$ |
(35.6 |
) |
|
|
$ |
0.1 |
|
| Unrealized loss/(gain) |
|
|
139.8 |
|
|
|
|
1.4 |
|
|
|
|
| Total foreign exchange loss/(gain) |
|
$ |
104.2 |
|
|
|
$ |
1.5 |
|
|
|
|
We recorded a net foreign exchange loss of $104.2 million during the first quarter of 2015 compared to $1.5 million for the same period in 2014.
During the quarter, we unwound our US$175 million foreign exchange swaps with terms extending to 2021 for proceeds of $39.9 million. This gain was offset by realized losses on our
foreign exchange collars and day-to-day transactions denominated in foreign currencies.
We
recorded unrealized losses of $51.8 million on our foreign exchange derivatives and $88.0 million on the translation of U.S. dollar debt and working capital. See Note 12
for further details.
16 ENERPLUS 2015 Q1
REPORT
Capital Investment
| |
|
Three months ended March 31,
|
| ($ millions) |
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
|
| Capital spending |
|
$ |
167.0 |
|
|
|
$ |
217.8 |
|
|
| Office capital |
|
|
0.9 |
|
|
|
|
0.4 |
|
|
|
|
|
| Sub-total |
|
$ |
167.9 |
|
|
|
$ |
218.2 |
|
|
|
|
|
| Property and land acquisitions |
|
$ |
(0.2 |
) |
|
|
$ |
10.0 |
|
|
| Property divestments |
|
|
(3.7 |
) |
|
|
|
(117.2 |
) |
|
|
|
|
| Sub-total |
|
$ |
(3.9 |
) |
|
|
$ |
(107.2 |
) |
|
|
|
|
| Total |
|
$ |
164.0 |
|
|
|
$ |
111.0 |
|
|
|
|
|
Capital spending for the first quarter of 2015 totaled $167.0 million compared to $217.8 million during the same period in 2014. Although spending
slowed in the first quarter due to continued weakness in commodity prices, we continued to invest modestly in our core areas, with spending of $78.4 million on our Fort Berthold crude oil
properties, $56.8 million on our Canadian crude properties, $19.5 million on our deep gas properties in Canada and $11.3 million on our Marcellus assets.
There
were no acquisitions during the first quarter of 2015, although we recorded adjustments pertaining to prior period property acquisitions. In comparison, during the first quarter of 2014 we spent
$10.0 million which included the purchase of additional undeveloped land in North Dakota and Pennsylvania.
During
the first quarter of 2015, we completed several minor non-core property divestments of undeveloped land for proceeds of approximately $3.7 million. During the first quarter of 2014,
property divestments totaled $117.2 million which included the sale of the balance of our Montney acreage and our overriding gas royalty interest in the Jonah property in Wyoming.
Subsequent
to the quarter, we completed the sales of non-core assets for combined proceeds of $185.8 million, net of closing costs, including the previously announced sale of our Pembina
waterflood assets that closed on April 15, 2015.
We
continue to expect annual capital spending of $480 million, with the majority of spending weighted to the first half of 2015.
Depletion, Depreciation, Amortization and Accretion ("DDA&A")
| |
|
Three months ended March 31,
|
| ($ millions, except per BOE amounts) |
|
|
2015 |
|
|
|
2014 |
|
|
|
|
| DDA&A expense |
|
$ |
132.4 |
|
|
$ |
132.2 |
|
| Per BOE |
|
$ |
14.58 |
|
|
$ |
14.86 |
|
|
|
|
DDA&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, 2015 DDA&A was $132.4 million compared to $132.2 million for the same period in 2014.
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.
During
the first quarter of 2015, trailing 12-month averages of crude oil and natural gas prices decreased significantly and resulted in a non-cash impairment of $267.6 million (before tax)
being recorded in the U.S. cost centre. No impairment was recorded to the Canadian cost centre. Enerplus did not record any ceiling test impairments on its oil and natural gas properties in
2014. If commodity prices remain at levels
ENERPLUS 2015 Q1
REPORT 17
experienced
during the first quarter of 2015, the trailing twelve month prices used in the ceiling calculation will decline further and may lead to additional write downs of our oil and natural gas
properties. See Note 5 for trailing 12-month prices used and further information.
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 estimated by Enerplus based on our net ownership interest, anticipated 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 $295.2 million at March 31, 2015 compared to $288.7 million at
December 31, 2014. See Note 8 for further information. Asset retirement obligation settlements for the first quarter totaled $3.9 million compared to $19.4 million
for the same period in 2014.
Income Taxes
| |
|
Three months ended March 31,
|
| ($ millions) |
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
| Current tax expense |
|
$ |
0.1 |
|
|
|
$ |
7.7 |
|
| Deferred tax expense/(recovery) |
|
|
(138.4 |
) |
|
|
|
24.5 |
|
|
|
|
| Total tax expense/(recovery) |
|
$ |
(138.3 |
) |
|
|
$ |
32.2 |
|
|
|
|
We recorded a total tax recovery of $138.3 million for the three months ended March 31, 2015 compared to a $32.2 million expense for
the same period in 2014. The decrease in total tax expense is due primarily to lower income in 2015 which included a $267.6 million non-cash asset impairment expense recorded in the
U.S. cost centre during the quarter.
Given
the decrease in commodity prices and U.S. forecasted net income for the year, we expect current tax of less than 1% of our U.S. funds flow in 2015. As a result, our current tax
expense has decreased to $0.1 million for the three months ended March 31, 2015 from $7.7 million for the same period in 2014. Our U.S. current tax is comprised
mainly of Alternative Minimum Tax ("AMT") payable with respect to our U.S. subsidiary. We expect to recover any AMT paid in future years as an offset to regular U.S. income taxes
otherwise payable. We do not expect to pay any cash taxes in Canada in 2015. These estimates may vary depending on numerous factors including commodity prices, capital spending, tax regulations and
acquisitions and divestment activity. See Note 13 for further information.
18 ENERPLUS 2015 Q1
REPORT
SELECTED QUARTERLY CANADIAN AND U.S. FINANCIAL RESULTS
| |
|
Three months ended March 31, 2015
|
|
Three months ended March 31, 2014
|
| (CDN$ millions, except per unit amounts) |
|
|
Canada |
|
|
U.S. |
|
|
Total |
|
|
|
|
Canada |
|
|
U.S. |
|
|
Total |
|
|
|
|
|
| Average Daily Production Volumes(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Crude oil (bbls/day) |
|
|
16,973 |
|
|
22,382 |
|
|
39,355 |
|
|
|
|
16,577 |
|
|
21,183 |
|
|
37,760 |
|
|
| |
Natural gas liquids (bbls/day) |
|
|
2,359 |
|
|
1,376 |
|
|
3,735 |
|
|
|
|
2,540 |
|
|
722 |
|
|
3,262 |
|
|
| |
Natural gas (Mcf/day) |
|
|
135,419 |
|
|
211,170 |
|
|
346,589 |
|
|
|
|
151,627 |
|
|
195,167 |
|
|
346,794 |
|
|
| |
|
|
|
|
| |
Total average daily production (BOE/day) |
|
|
41,902 |
|
|
58,953 |
|
|
100,855 |
|
|
|
|
44,388 |
|
|
54,433 |
|
|
98,821 |
|
|
| |
|
|
|
|
| Pricing(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Crude oil (per bbl) |
|
$ |
41.47 |
|
$ |
45.99 |
|
$ |
44.04 |
|
|
|
$ |
86.74 |
|
$ |
97.97 |
|
$ |
93.04 |
|
|
| |
Natural gas liquids (per bbl) |
|
|
29.14 |
|
|
11.06 |
|
|
22.48 |
|
|
|
|
69.46 |
|
|
62.38 |
|
|
67.90 |
|
|
| |
Natural gas (per Mcf) |
|
|
3.13 |
|
|
2.22 |
|
|
2.58 |
|
|
|
|
5.41 |
|
|
4.81 |
|
|
5.07 |
|
|
Capital Expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Capital spending |
|
$ |
76.9 |
|
$ |
90.1 |
|
$ |
167.0 |
|
|
|
$ |
127.7 |
|
$ |
90.1 |
|
$ |
217.8 |
|
|
| |
Acquisitions |
|
|
1.2 |
|
|
(1.4 |
) |
|
(0.2 |
) |
|
|
|
– |
|
|
10.0 |
|
|
10.0 |
|
|
| |
Divestments |
|
|
(1.0 |
) |
|
(2.7 |
) |
|
(3.7 |
) |
|
|
|
(67.7 |
) |
|
(49.5 |
) |
|
(117.2 |
) |
|
Netback Before Hedging |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Oil and natural gas sales |
|
$ |
107.9 |
|
$ |
136.2 |
|
$ |
244.1 |
|
|
|
$ |
220.0 |
|
$ |
275.0 |
|
$ |
495.0 |
|
|
| |
Royalties |
|
|
(12.4 |
) |
|
(26.7 |
) |
|
(39.1 |
) |
|
|
|
(34.0 |
) |
|
(53.3 |
) |
|
(87.3 |
) |
|
| |
Production taxes |
|
|
(1.8 |
) |
|
(9.0 |
) |
|
(10.8 |
) |
|
|
|
(2.0 |
) |
|
(17.9 |
) |
|
(19.9 |
) |
|
| |
Cash operating expense |
|
|
(57.0 |
) |
|
(29.8 |
) |
|
(86.8 |
) |
|
|
|
(62.1 |
) |
|
(17.7 |
) |
|
(79.8 |
) |
|
| |
Transportation expense |
|
|
(6.2 |
) |
|
(20.3 |
) |
|
(26.5 |
) |
|
|
|
(5.9 |
) |
|
(16.4 |
) |
|
(22.3 |
) |
|
| |
|
|
|
|
| |
Netback before hedging |
|
$ |
30.5 |
|
$ |
50.4 |
|
$ |
80.9 |
|
|
|
$ |
116.0 |
|
$ |
169.7 |
|
$ |
285.7 |
|
|
| |
|
|
|
|
Other Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Commodity derivative instruments loss/(gain) |
|
$ |
(50.4 |
) |
$ |
– |
|
$ |
(50.4 |
) |
|
|
$ |
32.6 |
|
$ |
– |
|
$ |
32.6 |
|
|
| |
General and administrative expense(3) |
|
|
23.5 |
|
|
8.6 |
|
|
32.1 |
|
|
|
|
23.3 |
|
|
5.8 |
|
|
29.1 |
|
|
| |
Current income tax expense/(recovery) |
|
|
– |
|
|
0.1 |
|
|
0.1 |
|
|
|
|
(0.2 |
) |
|
7.9 |
|
|
7.7 |
|
|
|
|
|
- (1)
- Company
interest volumes.
- (2)
- Before
transportation costs, royalties and the effects of commodity derivative instruments.
- (3)
- Includes
share based compensation.
ENERPLUS 2015 Q1
REPORT 19
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 |
|
|
|
| 2015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| First Quarter |
|
$ |
205.0 |
|
$ |
(293.2 |
) |
$ |
(1.42 |
) |
$ |
(1.42 |
) |
|
|
| 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 |
|
|
|
| 2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Fourth Quarter |
|
$ |
332.4 |
|
$ |
29.6 |
|
$ |
0.15 |
|
$ |
0.15 |
|
|
| Third Quarter |
|
|
365.4 |
|
|
(3.7 |
) |
|
(0.02 |
) |
|
(0.02 |
) |
|
| Second Quarter |
|
|
341.3 |
|
|
38.5 |
|
|
0.19 |
|
|
0.19 |
|
|
| First Quarter |
|
|
313.4 |
|
|
(16.4 |
) |
|
(0.08 |
) |
|
(0.08 |
) |
|
|
|
|
|
|
|
|
|
|
| Total 2013 |
|
$ |
1,352.5 |
|
$ |
48.0 |
|
$ |
0.24 |
|
$ |
0.24 |
|
|
|
Oil and gas sales decreased in the first quarter of 2015 due to lower realized commodity prices and a decrease in crude oil production compared to the fourth
quarter of 2014. From the first quarter of 2013, oil and gas sales increased steadily until the third quarter of 2014 when realized commodity prices began to decline significantly. Net income in the
first quarter of 2015 was impacted by asset impairments related to the decrease in crude oil prices and by the significant fluctuation in the U.S. dollar relative to the Canadian dollar.
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, 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, 2015 our senior debt to EBITDA ratio was 1.6x and our debt to funds flow ratio was 1.7x. Debt to funds flow is often used by investors
and analysts to evaluate our liquidity, however, this measure is not used by Enerplus to determine compliance with financial covenants.
Total
debt net of cash at March 31, 2015 was $1,272.2 million compared to $1,134.9 million at December 31, 2014. Total debt was comprised of
$125.7 million of bank indebtedness and $1,149.1 million of senior notes less $2.6 million in cash. At March 31, 2015 we were approximately 13% drawn on our
$1.0 billion senior, unsecured bank facility. Subsequent to quarter end, we closed non-core asset sales for proceeds of $185.8 million, net of closing costs, and used the proceeds to
repay the drawn balance on our credit facility. The maturities on our senior notes range between 2015 and 2026, with approximately $100 million of scheduled principal repayments during 2015 and
none in 2016.
Our
working capital deficiency, excluding cash and current deferred financial and tax balances, increased to $290.6 million at March 31, 2015 from $260.5 million at
December 31, 2014. We expect to finance our working capital deficit through funds flow and our bank credit facility.
Our
adjusted payout ratio, which is calculated as cash dividends plus capital and office expenditures divided by funds flow, was 197% for the first quarter of 2015 compared to 118% for the same period
in 2014. Despite the increase in our adjusted payout ratio we have continued to maintain our financial flexibility through an ongoing focus on cost efficiencies and the success of our non-core asset
divestment program. As previously announced, in order to maintain our balance sheet strength we have reduced our monthly dividend by 44% from $0.09/share to $0.05/share effective with our
March 2015 dividend, paid in April. We have also decreased our capital spending by 40% compared to 2014 levels, deferring spending and preserving opportunities.
We
have a $1.0 billion senior, unsecured, covenant-based bank credit facility that matures on October 31, 2017. Drawn and undrawn fees range between 150 and 315 basis
points over Bankers' Acceptance rates, with current drawn fees of 170 basis points. The bank credit facility ranks equally with our senior, unsecured, covenant-based notes. At
March 31, 2015 we were in compliance with all covenants under our bank credit
20 ENERPLUS 2015 Q1
REPORT
facility
and outstanding senior notes. 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, 2015:
| Covenant Description |
|
|
|
|
March 31, 2015 |
|
|
|
|
| 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(1) |
|
50% |
|
|
29% |
|
Senior Notes: |
|
Maximum Ratio |
|
|
|
|
| Senior Debt to EBITDA(2) |
|
3.0 x – 3.5 x |
|
|
1.6x |
|
| Maximum debt to consolidated present value of total proven reserves |
|
60% |
|
|
42% |
|
|
|
Minimum Ratio |
|
|
|
|
| EBITDA to Interest |
|
4.0 x |
|
|
12.9 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, 2015 were $165.9 million and $827.9 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 shareholders' equity plus a $1.1 billion adjustment
related to our adoption of U.S. GAAP.
Footnotes
- (1)
- Upon completion of a material acquisition, the Total Debt to Capitalization maximum ratio may increase to 55% for a period extending to and
including the second full fiscal quarter after the completion of the acquisition
- (2)
- Senior
debt to EBITDA maximum ratio for the senior notes may increase to 3.5x for a period of 6 months, after which the ratio decreases to 3.0x
Dividends
| |
|
Three months ended March 31,
|
| ($ millions, except per share amounts) |
|
|
2015 |
|
|
|
2014 |
|
|
|
|
| Cash dividends |
|
$ |
47.4 |
|
|
$ |
42.1 |
|
| Stock Dividend Plan |
|
|
– |
|
|
|
12.8 |
|
|
|
|
| Total dividends to shareholders |
|
$ |
47.4 |
|
|
$ |
54.9 |
|
|
|
|
| Per weighted average share (Basic) |
|
$ |
0.23 |
|
|
$ |
0.27 |
|
|
|
|
We reported a total of $47.4 million or $0.23 per share in dividends to our shareholders in the first quarter of 2015 compared to $54.9 million or
$0.27 per share in the first quarter of 2014.
Effective
with the April 2015 payment, we reduced the monthly dividend by 44% from $0.09 per share to $0.05 per share to preserve our balance sheet strength in both the near and long term. The
dividend is an important part of our strategy to create shareholder value and we will continue to monitor commodity prices and economic conditions and are prepared to make adjustments
as necessary.
ENERPLUS 2015 Q1
REPORT 21
Shareholders' Capital
| |
|
Three months ended March 31,
|
| |
|
|
2015 |
|
|
|
2014 |
|
|
|
|
| Share capital ($ millions) |
|
$ |
3,125.9 |
|
|
$ |
3,081.8 |
|
Common shares outstanding (thousands) |
|
|
206,179 |
|
|
|
203,839 |
|
| Weighted average shares outstanding – basic (thousands) |
|
|
205,845 |
|
|
|
203,178 |
|
| Weighted average shares outstanding – diluted (thousands) |
|
|
205,845 |
|
|
|
205,878 |
|
|
|
|
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 Restricted Share Unit plan. In comparison, during the first quarter of 2014 a total of 1,081,000 shares and $18.9 million of additional equity was issued pursuant to
the stock option plan and the currently inactive stock dividend plan. For further details see Note 14.
At
March 31, 2015 we had 206,179,000 shares outstanding (2014 – 203,839,000) and at May 7, 2015 we had
206,224,000 shares outstanding.
2015 GUIDANCE
A summary of our 2015 guidance is below. This guidance does not include any unannounced acquisitions or divestments.
There
have been no changes to our guidance this quarter, with the exception of a reclassification between operating expenses and transportation costs. This reclassification does not impact our
netback, funds flow or net income.
| Summary of 2015 Expectations |
|
Target |
|
|
| Average annual production |
|
93,000 – 100,000 BOE/day |
|
| Capital spending |
|
$480 million |
|
| Production mix (volumes) |
|
42% – 44% crude oil and liquids |
|
Average royalty and production tax rate
(% of gross sales, before transportation) |
|
21% |
|
| Operating costs |
|
$9.75/BOE (from $11.10/BOE, revised for Marcellus gathering cost reclassification) |
|
| Transportation costs |
|
$3.00/BOE (revised for Marcellus gathering cost reclassification) |
|
| Cash G&A expenses |
|
$2.40/BOE |
|
| U.S. Cash taxes (% of U.S. funds flow) |
|
< 1% |
|
|
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, 2015, 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, 2015 and ended March 31, 2015 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.
22 ENERPLUS 2015 Q1
REPORT
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 2015 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 proportion and average production volumes associated with curtailments in the Marcellus; the results from our drilling program and the
timing of related production; oil and natural gas prices and differentials and our commodity and foreign exchange risk management programs in 2015 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 2015 and its impact on our production level; potential future asset 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; our future acquisitions and dispositions; 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 further curtailment
of production and/or reduced realized prices; current commodity price and cost assumptions; the general continuance of current or, where applicable, assumed industry conditions; the continuation of
assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve and 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; the availability of third party services; and the extent of our liabilities. In addition, our 2015 guidance contained in this MD&A is based on the
following: a WTI price of US$55/bbl, a NYMEX price of US$2.75/Mcf, an AECO price of $2.50/GJ and a USD/CDN exchange rate of 1.25.
We believe the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors,
expectations and assumptions will prove to be correct.
The forward-looking information included in this MD&A is not a guarantee of future performance and should not be unduly relied upon. Such information involves known and unknown
risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information including, without limitation: changes
in, including further decline of, commodity prices; changes in realized prices of Enerplus' products; changes in the demand for or supply of our products; unanticipated operating results, results from
our capital spending activities or production declines; curtailment of our production due to low realized prices
or lack of adequate infrastructure; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in our capital plans or by third party operators of our properties;
increased debt levels or debt service requirements; inaccurate estimation of our oil and gas reserve and resource volumes; limited, unfavourable or a lack of access to capital markets; increased
costs; a lack of adequate insurance coverage; the impact of competitors; reliance on industry partners and third party service providers; and certain other risks detailed from time to time in our
public disclosure documents (including, without limitation, those risks and contingencies described under "Risk Factors and Risk Management" in our Annual MD&A and in our other public
filings).
ENERPLUS 2015 Q1
REPORT 23
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Exhibit 99.2
STATEMENTS
Condensed Consolidated Balance Sheets
| (CDN$ thousands) unaudited |
|
Note |
|
|
|
March 31, 2015 |
|
|
|
|
December 31, 2014 |
|
|
|
|
|
| Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Current assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Cash |
|
|
|
|
$ |
2,603 |
|
|
|
$ |
2,036 |
|
|
| |
Accounts receivable |
|
3 |
|
|
|
151,816 |
|
|
|
|
199,745 |
|
|
| |
Deferred financial assets |
|
15 |
|
|
|
182,713 |
|
|
|
|
215,706 |
|
|
| |
Other current assets |
|
|
|
|
|
9,827 |
|
|
|
|
8,241 |
|
|
|
|
|
| |
|
|
|
|
|
346,959 |
|
|
|
|
425,728 |
|
|
|
|
|
| Property, plant and equipment: |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Oil and natural gas properties (full cost method) |
|
4 |
|
|
|
2,559,288 |
|
|
|
|
2,632,474 |
|
|
| |
Other capital assets, net |
|
4 |
|
|
|
20,927 |
|
|
|
|
20,591 |
|
|
|
|
|
| |
Property, plant and equipment |
|
|
|
|
|
2,580,215 |
|
|
|
|
2,653,065 |
|
|
|
|
|
| Goodwill |
|
|
|
|
|
640,551 |
|
|
|
|
624,390 |
|
|
| Deferred income tax asset |
|
|
|
|
|
488,177 |
|
|
|
|
348,117 |
|
|
| Deferred financial assets |
|
15 |
|
|
|
– |
|
|
|
|
30,997 |
|
|
|
|
|
| Total Assets |
|
|
|
|
$ |
4,055,902 |
|
|
|
$ |
4,082,297 |
|
|
|
|
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Current liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Accounts payable |
|
6 |
|
|
$ |
337,537 |
|
|
|
$ |
351,006 |
|
|
| |
Dividends payable |
|
|
|
|
|
10,309 |
|
|
|
|
18,516 |
|
|
| |
Current portion of long-term debt |
|
7 |
|
|
|
104,430 |
|
|
|
|
98,933 |
|
|
| |
Deferred income tax liability |
|
|
|
|
|
34,495 |
|
|
|
|
50,805 |
|
|
| |
Deferred financial credits |
|
15 |
|
|
|
36,731 |
|
|
|
|
10,826 |
|
|
|
|
|
| |
|
|
|
|
|
523,502 |
|
|
|
|
530,086 |
|
|
|
|
|
| Deferred financial credits |
|
15 |
|
|
|
– |
|
|
|
|
2,396 |
|
|
| Long-term debt |
|
7 |
|
|
|
1,170,377 |
|
|
|
|
1,037,997 |
|
|
| Asset retirement obligation |
|
8 |
|
|
|
295,162 |
|
|
|
|
288,692 |
|
|
|
|
|
| |
|
|
|
|
|
1,465,539 |
|
|
|
|
1,329,085 |
|
|
|
|
|
| Total Liabilities |
|
|
|
|
|
1,989,041 |
|
|
|
|
1,859,171 |
|
|
|
|
|
Shareholders' Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
Share capital – authorized unlimited common shares, no par value
Issued and outstanding: March 31, 2015 – 206 million shares
December 31, 2014 – 206 million shares |
|
14 |
|
|
|
3,125,895 |
|
|
|
|
3,120,002 |
|
|
| Paid-in capital |
|
14 |
|
|
|
48,554 |
|
|
|
|
46,906 |
|
|
| Accumulated deficit |
|
|
|
|
|
(1,379,825 |
) |
|
|
|
(1,039,260 |
) |
|
| Accumulated other comprehensive income/(loss) |
|
|
|
|
|
272,237 |
|
|
|
|
95,478 |
|
|
|
|
|
| |
|
|
|
|
|
2,066,861 |
|
|
|
|
2,223,126 |
|
|
|
|
|
| Total Liabilities & Equity |
|
|
|
|
$ |
4,055,902 |
|
|
|
$ |
4,082,297 |
|
|
|
|
|
Contingencies |
|
16 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to the Condensed Consolidated Financial Statements
24 ENERPLUS 2015 Q1
REPORT
Condensed Consolidated Statements of Income/(Loss) and
Comprehensive Income/(Loss)
| Three months ended March 31 (CDN$ thousands) unaudited |
|
Note |
|
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
|
| Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Oil and natural gas sales, net of royalties |
|
9 |
|
|
$ |
204,960 |
|
|
|
$ |
407,740 |
|
|
| Commodity derivative instruments gain/(loss) |
|
15 |
|
|
|
50,398 |
|
|
|
|
(32,597 |
) |
|
|
|
|
| |
|
|
|
|
|
255,358 |
|
|
|
|
375,143 |
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Production taxes |
|
|
|
|
|
10,813 |
|
|
|
|
19,872 |
|
|
| Operating |
|
|
|
|
|
87,727 |
|
|
|
|
79,857 |
|
|
| Transportation |
|
|
|
|
|
26,483 |
|
|
|
|
22,333 |
|
|
| General and administrative |
|
10 |
|
|
|
32,080 |
|
|
|
|
29,123 |
|
|
| Depletion, depreciation, amortization and accretion |
|
|
|
|
|
132,350 |
|
|
|
|
132,180 |
|
|
| Asset impairment |
|
5 |
|
|
|
267,611 |
|
|
|
|
– |
|
|
| Interest |
|
11 |
|
|
|
17,033 |
|
|
|
|
15,179 |
|
|
| Foreign exchange (gain)/loss |
|
12 |
|
|
|
104,202 |
|
|
|
|
1,469 |
|
|
| Other expense/(income) |
|
|
|
|
|
8,612 |
|
|
|
|
2,912 |
|
|
|
|
|
| |
|
|
|
|
|
686,911 |
|
|
|
|
302,925 |
|
|
|
|
|
| Income/(loss) before taxes |
|
|
|
|
|
(431,553 |
) |
|
|
|
72,218 |
|
|
| Current income tax expense/(recovery) |
|
13 |
|
|
|
63 |
|
|
|
|
7,678 |
|
|
| Deferred income tax expense/(recovery) |
|
13 |
|
|
|
(138,410 |
) |
|
|
|
24,503 |
|
|
|
|
|
| Net Income/(loss) |
|
|
|
|
$ |
(293,206 |
) |
|
|
$ |
40,037 |
|
|
|
|
|
Other Comprehensive Income/(loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Changes due to marketable securities (net of tax) |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Unrealized gain/(loss) |
|
|
|
|
|
– |
|
|
|
|
(145 |
) |
|
| |
Realized (gain)/loss reclassified to net income |
|
|
|
|
|
– |
|
|
|
|
2,503 |
|
|
| Change in cumulative translation adjustment |
|
|
|
|
|
176,759 |
|
|
|
|
45,644 |
|
|
|
|
|
| Other Comprehensive Income/(loss) |
|
|
|
|
|
176,759 |
|
|
|
|
48,002 |
|
|
|
|
|
| Total Comprehensive Income/(loss) |
|
|
|
|
$ |
(116,447 |
) |
|
|
$ |
88,039 |
|
|
|
|
|
Net income/(loss) per share |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Basic |
|
14 |
|
|
$ |
(1.42 |
) |
|
|
$ |
0.20 |
|
|
| Diluted |
|
14 |
|
|
$ |
(1.42 |
) |
|
|
$ |
0.19 |
|
|
|
|
|
See accompanying notes to the Condensed Consolidated Financial Statements
ENERPLUS 2015 Q1
REPORT 25
Condensed Consolidated Statements of Changes
in Shareholders' Equity
| Three months ended March 31 (CDN$ thousands) unaudited |
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
|
| Share Capital |
|
|
|
|
|
|
|
|
|
|
| Balance, beginning of year |
|
$ |
3,120,002 |
|
|
|
$ |
3,061,839 |
|
|
| Stock Option Plan – cash |
|
|
2,571 |
|
|
|
|
6,138 |
|
|
| Share-based compensation – settled |
|
|
3,095 |
|
|
|
|
– |
|
|
| Stock Option Plan – exercised |
|
|
227 |
|
|
|
|
1,012 |
|
|
| Stock Dividend Plan |
|
|
– |
|
|
|
|
12,781 |
|
|
|
|
|
| Balance, end of period |
|
$ |
3,125,895 |
|
|
|
$ |
3,081,770 |
|
|
|
|
|
Paid-in Capital |
|
|
|
|
|
|
|
|
|
|
| Balance, beginning of year |
|
$ |
46,906 |
|
|
|
$ |
38,398 |
|
|
| Share-based compensation – settled |
|
|
(3,095 |
) |
|
|
|
– |
|
|
| Stock Option Plan – exercised |
|
|
(227 |
) |
|
|
|
(1,012 |
) |
|
| Share-based compensation – non-cash |
|
|
4,970 |
|
|
|
|
2,952 |
|
|
|
|
|
| Balance, end of period |
|
$ |
48,554 |
|
|
|
$ |
40,338 |
|
|
|
|
|
Accumulated Deficit |
|
|
|
|
|
|
|
|
|
|
| Balance, beginning of year |
|
$ |
(1,039,260 |
) |
|
|
$ |
(1,117,238 |
) |
|
| Net income/(loss) |
|
|
(293,206 |
) |
|
|
|
40,037 |
|
|
| Dividends |
|
|
(47,359 |
) |
|
|
|
(54,935 |
) |
|
|
|
|
| Balance, end of period |
|
$ |
(1,379,825 |
) |
|
|
$ |
(1,132,136 |
) |
|
|
|
|
Accumulated Other Comprehensive Income/(Loss) |
|
|
|
|
|
|
|
|
|
|
| Balance, beginning of year |
|
$ |
95,478 |
|
|
|
$ |
(50,697 |
) |
|
| Changes due to marketable securities (net of tax) |
|
|
|
|
|
|
|
|
|
|
| |
Unrealized gain/(loss) |
|
|
– |
|
|
|
|
(145 |
) |
|
| |
Realized (gain)/loss reclassified to net income |
|
|
– |
|
|
|
|
2,503 |
|
|
| Change in cumulative translation adjustment |
|
|
176,759 |
|
|
|
|
45,644 |
|
|
|
|
|
| Balance, end of period |
|
$ |
272,237 |
|
|
|
$ |
(2,695 |
) |
|
|
|
|
| Total Shareholders' Equity |
|
$ |
2,066,861 |
|
|
|
$ |
1,987,277 |
|
|
|
|
|
See accompanying notes to the Condensed Consolidated Financial Statements
26 ENERPLUS 2015 Q1
REPORT
Condensed Consolidated Statements of Cash Flows
| Three months ended March 31 (CDN$ thousands) unaudited |
|
Note |
|
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
|
| Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net income/(loss) |
|
|
|
|
$ |
(293,206 |
) |
|
|
$ |
40,037 |
|
|
| Non-cash items add/(deduct): |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Depletion, depreciation, amortization and accretion |
|
|
|
|
|
132,350 |
|
|
|
|
132,180 |
|
|
| |
Asset impairment |
|
5 |
|
|
|
267,611 |
|
|
|
|
– |
|
|
| |
Changes in fair value of derivative instruments |
|
15 |
|
|
|
87,499 |
|
|
|
|
6,809 |
|
|
| |
Deferred income tax expense/(recovery) |
|
13 |
|
|
|
(138,410 |
) |
|
|
|
24,503 |
|
|
| |
Foreign exchange (gain)/loss on debt and working capital |
|
12 |
|
|
|
88,014 |
|
|
|
|
10,987 |
|
|
| |
Share-based compensation |
|
14 |
|
|
|
4,970 |
|
|
|
|
2,952 |
|
|
| |
Amortization of debt issue costs |
|
|
|
|
|
240 |
|
|
|
|
246 |
|
|
| |
Asset divestments (gain)/loss |
|
|
|
|
|
– |
|
|
|
|
2,798 |
|
|
| Derivative settlement of foreign exchange swaps |
|
|
|
|
|
(39,904 |
) |
|
|
|
– |
|
|
| Asset retirement obligation expenditures |
|
8 |
|
|
|
(3,890 |
) |
|
|
|
(4,292 |
) |
|
| Changes in non-cash operating working capital |
|
17 |
|
|
|
25,822 |
|
|
|
|
(75,810 |
) |
|
|
|
|
| Cash flow from operating activities |
|
|
|
|
|
131,096 |
|
|
|
|
140,410 |
|
|
|
|
|
Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Proceeds from the issuance of shares |
|
14 |
|
|
|
2,571 |
|
|
|
|
6,138 |
|
|
| Cash dividends |
|
14 |
|
|
|
(47,359 |
) |
|
|
|
(42,154 |
) |
|
| Change in bank credit facility |
|
|
|
|
|
45,820 |
|
|
|
|
(30,570 |
) |
|
| Derivative settlement of foreign exchange swaps |
|
|
|
|
|
39,904 |
|
|
|
|
– |
|
|
| Changes in non-cash financing working capital |
|
|
|
|
|
(8,207 |
) |
|
|
|
101 |
|
|
|
|
|
| Cash flow from financing activities |
|
|
|
|
|
32,729 |
|
|
|
|
(66,485 |
) |
|
|
|
|
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Capital and office expenditures |
|
|
|
|
|
(167,888 |
) |
|
|
|
(218,193 |
) |
|
| Property and land acquisitions |
|
|
|
|
|
236 |
|
|
|
|
(9,969 |
) |
|
| Property dispositions |
|
|
|
|
|
3,712 |
|
|
|
|
117,225 |
|
|
| Sale of marketable securities |
|
|
|
|
|
– |
|
|
|
|
13,300 |
|
|
| Changes in non-cash investing working capital |
|
|
|
|
|
931 |
|
|
|
|
24,677 |
|
|
|
|
|
| Cash flow from investing activities |
|
|
|
|
|
(163,009 |
) |
|
|
|
(72,960 |
) |
|
|
|
|
| Effect of exchange rate changes on cash |
|
|
|
|
|
(249 |
) |
|
|
|
1,782 |
|
|
|
|
|
| Change in cash |
|
|
|
|
|
567 |
|
|
|
|
2,747 |
|
|
| Cash, beginning of period |
|
|
|
|
|
2,036 |
|
|
|
|
2,990 |
|
|
|
|
|
| Cash, end of period |
|
|
|
|
$ |
2,603 |
|
|
|
$ |
5,737 |
|
|
|
|
|
See accompanying notes to the Condensed Consolidated Financial Statements
ENERPLUS 2015 Q1
REPORT 27
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 7, 2015.
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, 2015, and the 2014 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, 2014. 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, 2014.
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, 2015 |
|
|
|
|
December 31, 2014 |
|
|
|
|
|
| Accrued receivables |
|
$ |
111,005 |
|
|
|
$ |
136,949 |
|
|
| Accounts receivable – trade |
|
|
37,113 |
|
|
|
|
41,618 |
|
|
| Current income tax receivable |
|
|
6,474 |
|
|
|
|
23,900 |
|
|
| Allowance for doubtful accounts |
|
|
(2,776 |
) |
|
|
|
(2,722 |
) |
|
|
|
|
| Total accounts receivable |
|
$ |
151,816 |
|
|
|
$ |
199,745 |
|
|
|
|
|
4) PROPERTY, PLANT AND EQUIPMENT ("PP&E")
As at March 31, 2015
($ thousands) |
|
|
Cost |
|
|
Accumulated
Depletion and
Depreciation |
|
|
Net Book Value |
|
|
| Oil and natural gas properties |
|
$ |
13,084,358 |
|
$ |
10,525,070 |
|
$ |
2,559,288 |
|
| Other capital assets |
|
|
100,057 |
|
|
79,130 |
|
|
20,927 |
|
|
| Total PP&E |
|
$ |
13,184,415 |
|
$ |
10,604,200 |
|
$ |
2,580,215 |
|
|
As at December 31, 2014
($ thousands) |
|
|
Cost |
|
|
Accumulated
Depletion and
Depreciation |
|
|
Net Book Value |
|
|
| Oil and natural gas properties |
|
$ |
12,478,953 |
|
$ |
9,846,479 |
|
$ |
2,632,474 |
|
| Other capital assets |
|
|
97,893 |
|
|
77,302 |
|
|
20,591 |
|
|
| Total PP&E |
|
$ |
12,576,846 |
|
$ |
9,923,781 |
|
$ |
2,653,065 |
|
|
28 ENERPLUS 2015 Q1
REPORT
5) ASSET IMPAIRMENT
| |
|
Three months ended March 31
|
| ($ thousands) |
|
|
2015 |
|
|
|
2014 |
|
|
|
|
| Oil and natural gas properties |
|
$ |
267,611 |
|
|
$ |
– |
|
|
|
|
| Impairment expense |
|
$ |
267,611 |
|
|
$ |
– |
|
|
|
|
For the three months ended March 31, 2015 non-cash impairment of $267.6 million was recorded in the United States cost centre due to
lower 12-month average trailing crude oil prices. No impairments were recorded to the Canadian cost centre for the same period, and no impairments were recorded in either the United States or
Canada cost centre for the period ending March 31, 2014.
The
following table outlines the 12-month average trailing benchmark prices and exchange rates used in Enerplus' ceiling tests from March 31, 2014 through March 31, 2015:
| Period |
|
|
WTI Crude Oil
US$/bbl |
|
|
Exchange Rate
US$/CDN$ |
|
|
Edm Light
Crude
CDN$/bbl |
|
|
U.S. Henry Hub
Gas
US$/Mcf |
|
|
AECO Natural
Gas Spot
CDN$/Mcf |
|
|
| Q1 2015 |
|
$ |
82.73 |
|
$ |
1.14 |
|
$ |
84.61 |
|
$ |
3.88 |
|
$ |
3.86 |
|
| Q4 2014 |
|
|
94.99 |
|
|
1.09 |
|
|
94.84 |
|
|
4.30 |
|
|
4.60 |
|
| Q3 2014 |
|
|
99.08 |
|
|
1.08 |
|
|
95.97 |
|
|
4.23 |
|
|
4.42 |
|
| Q2 2014 |
|
|
100.27 |
|
|
1.06 |
|
|
98.28 |
|
|
4.08 |
|
|
4.05 |
|
| Q1 2014 |
|
|
98.46 |
|
|
1.05 |
|
|
95.45 |
|
|
3.98 |
|
|
3.79 |
|
|
6) ACCOUNTS PAYABLE
| ($ thousands) |
|
|
March 31, 2015 |
|
|
|
December 31, 2014 |
|
|
|
|
| Accrued payables |
|
$ |
246,548 |
|
|
$ |
239,773 |
|
| Accounts payable – trade |
|
|
90,989 |
|
|
|
111,233 |
|
|
|
|
| Total accounts payable |
|
$ |
337,537 |
|
|
$ |
351,006 |
|
|
|
|
7) DEBT
| ($ thousands) |
|
|
March 31, 2015 |
|
|
|
December 31, 2014 |
|
|
|
|
| Current: |
|
|
|
|
|
|
|
|
| |
Senior notes |
|
$ |
104,430 |
|
|
$ |
98,933 |
|
|
|
|
| |
|
|
104,430 |
|
|
|
98,933 |
|
|
|
|
| Long-term: |
|
|
|
|
|
|
|
|
| |
Bank credit facility |
|
$ |
125,737 |
|
|
$ |
79,917 |
|
| |
Senior notes |
|
|
1,044,640 |
|
|
|
958,080 |
|
|
|
|
| |
|
|
1,170,377 |
|
|
|
1,037,997 |
|
|
|
|
| Total debt |
|
$ |
1,274,807 |
|
|
$ |
1,136,930 |
|
|
|
|
ENERPLUS 2015 Q1
REPORT 29
8) ASSET RETIREMENT OBLIGATION
Enerplus has estimated the present value of its asset retirement obligation to be $295.2 million at March 31, 2015 compared to
$288.7 million at December 31, 2014, based on a total undiscounted liability of $741.8 million and $730.9 million, respectively. The asset retirement obligation was
calculated using a weighted credit-adjusted risk-free rate of 5.89% (December 31, 2014 – 5.92%).
| ($ thousands) |
|
|
Three months ended
March 31, 2015 |
|
|
|
|
Year ended
December 31, 2014 |
|
|
|
|
|
| Balance, beginning of year |
|
$ |
288,692 |
|
|
|
$ |
291,761 |
|
|
| Change in estimates |
|
|
5,755 |
|
|
|
|
4,378 |
|
|
| Property acquisition and development activity |
|
|
492 |
|
|
|
|
1,778 |
|
|
| Dispositions |
|
|
(40 |
) |
|
|
|
(4,313 |
) |
|
| Settlements |
|
|
(3,890 |
) |
|
|
|
(19,409 |
) |
|
| Accretion expense |
|
|
4,153 |
|
|
|
|
14,497 |
|
|
|
|
|
| Balance, end of period |
|
$ |
295,162 |
|
|
|
$ |
288,692 |
|
|
|
|
|
9) OIL AND NATURAL GAS SALES
| |
|
Three months ended March 31
|
| ($ thousands) |
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
|
| Oil and natural gas sales |
|
$ |
244,077 |
|
|
|
$ |
495,024 |
|
|
| Royalties(1) |
|
|
(39,117 |
) |
|
|
|
(87,284 |
) |
|
|
|
|
| Oil and natural gas sales, net of royalties |
|
$ |
204,960 |
|
|
|
$ |
407,740 |
|
|
|
|
|
- (1)
- Royalties
above do not include production taxes which are reported separately on the Consolidated Statements of Income/(Loss).
10) GENERAL AND ADMINISTRATIVE EXPENSE
| |
|
Three months ended March 31
|
| ($ thousands) |
|
|
2015 |
|
|
|
2014 |
|
|
|
|
| |
General and administrative expense |
|
$ |
21,435 |
|
|
$ |
20,529 |
|
| |
Share-based compensation expense |
|
|
10,645 |
|
|
|
8,594 |
|
|
|
|
| General and administrative expense |
|
$ |
32,080 |
|
|
$ |
29,123 |
|
|
|
|
11) INTEREST EXPENSE
| |
|
Three months ended March 31
|
| ($ thousands) |
|
|
2015 |
|
|
|
2014 |
|
|
|
|
| Realized: |
|
|
|
|
|
|
|
|
| |
|
Interest on bank debt and senior notes |
|
$ |
16,793 |
|
|
$ |
14,666 |
|
| Unrealized: |
|
|
|
|
|
|
|
|
| |
Cross currency interest rate swap (gain)/loss |
|
|
– |
|
|
|
267 |
|
| |
Amortization of debt issue costs |
|
|
240 |
|
|
|
246 |
|
|
|
|
| Interest expense |
|
$ |
17,033 |
|
|
$ |
15,179 |
|
|
|
|
30 ENERPLUS 2015 Q1
REPORT
12) FOREIGN EXCHANGE
| |
|
Three months ended March 31
|
| ($ thousands) |
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
|
| Realized: |
|
|
|
|
|
|
|
|
|
|
| |
Foreign exchange (gain)/loss |
|
$ |
(35,574 |
) |
|
|
$ |
50 |
|
|
| Unrealized: |
|
|
|
|
|
|
|
|
|
|
| |
Translation of U.S. dollar debt and working capital (gain)/loss |
|
|
88,014 |
|
|
|
|
10,987 |
|
|
| |
Cross currency interest rate swap (gain)/loss |
|
|
– |
|
|
|
|
(1,245 |
) |
|
| |
Foreign exchange derivatives (gain)/loss |
|
|
51,762 |
|
|
|
|
(8,323 |
) |
|
|
|
|
| Foreign exchange (gain)/loss |
|
$ |
104,202 |
|
|
|
$ |
1,469 |
|
|
|
|
|
13) INCOME TAXES
| |
|
Three months ended March 31
|
| ($ thousands) |
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
|
| Current tax expense/(recovery) |
|
|
|
|
|
|
|
|
|
|
| |
Canada |
|
$ |
– |
|
|
|
$ |
(184 |
) |
|
| |
United States |
|
|
63 |
|
|
|
|
7,862 |
|
|
|
|
|
| Current tax expense/(recovery) |
|
|
63 |
|
|
|
|
7,678 |
|
|
|
|
|
| Deferred tax expense/(recovery) |
|
|
|
|
|
|
|
|
|
|
| |
Canada |
|
$ |
(9,263 |
) |
|
|
$ |
1,687 |
|
|
| |
United States |
|
|
(129,147 |
) |
|
|
|
22,816 |
|
|
|
|
|
| Deferred tax expense/(recovery) |
|
|
(138,410 |
) |
|
|
|
24,503 |
|
|
|
|
|
| Income tax expense/(recovery) |
|
$ |
(138,347 |
) |
|
|
$ |
32,181 |
|
|
|
|
|
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, foreign rate differentials for foreign operations, statutory and other rate differentials, the reversal or recognition of previously unrecognized
deferred tax assets, non-taxable portions of capital gains and losses, and non-deductible share-based compensation.
14) SHAREHOLDERS' EQUITY
a) Share Capital
| |
|
Three months ended March 31 |
|
Year ended December 31 |
| |
|
|
|
|
| |
|
2015 |
|
2014 |
|
|
|
Authorized unlimited number of common shares
Issued: (thousands) |
|
Shares |
|
|
Amount |
|
|
Shares |
|
|
Amount |
|
|
|
|
| Balance, beginning of year |
|
205,732 |
|
$ |
3,120,002 |
|
|
202,758 |
|
$ |
3,061,839 |
|
| Issued for cash: |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Stock Option Plan |
|
189 |
|
|
2,571 |
|
|
1,944 |
|
|
31,350 |
|
| Non-cash: |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Share-based compensation – settled |
|
258 |
|
|
3,095 |
|
|
– |
|
|
– |
|
| |
Stock Option Plan – exercised |
|
– |
|
|
227 |
|
|
– |
|
|
4,978 |
|
| |
Stock Dividend Plan(1) |
|
– |
|
|
– |
|
|
1,030 |
|
|
21,835 |
|
|
|
|
| Balance, end of period |
|
206,179 |
|
$ |
3,125,895 |
|
|
205,732 |
|
$ |
3,120,002 |
|
|
|
|
- (1)
- Effective
with the October, 2014 dividend, Enerplus suspended the Stock Dividend Plan.
ENERPLUS 2015 Q1
REPORT 31
b) Dividends
| |
|
Three months ended March 31
|
| ($ thousands) |
|
|
2015 |
|
|
|
2014 |
|
|
|
|
| Cash dividends |
|
$ |
47,359 |
|
|
$ |
42,154 |
|
| Stock dividends(1) |
|
|
– |
|
|
|
12,781 |
|
|
|
|
| Dividends to shareholders |
|
$ |
47,359 |
|
|
$ |
54,935 |
|
|
|
|
- (1)
- Effective
with the October 2014 dividend Enerplus suspended the Stock Dividend Plan.
c) 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) |
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
|
| Cash: |
|
|
|
|
|
|
|
|
|
|
| |
Long-term incentive plans expense |
|
$ |
7,274 |
|
|
|
$ |
6,864 |
|
|
| Non-Cash: |
|
|
|
|
|
|
|
|
|
|
| |
Share-based compensation |
|
|
4,970 |
|
|
|
|
2,952 |
|
|
| |
Equity swap (gain)/loss |
|
|
(1,599 |
) |
|
|
|
(1,222 |
) |
|
|
|
|
| Share-based compensation expense |
|
$ |
10,645 |
|
|
|
$ |
8,594 |
|
|
|
|
|
(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 our grant in March of 2014 and any prior grants will continue to be settled in cash.
The
following table summarizes the PSU, RSU and Director Share Unit ("DSU") activity for the three months ended March 31, 2015:
For the three months ended
March 31, 2015 |
|
Cash-settled LTI Plans
|
|
Equity-settled LTI Plans
|
|
|
|
|
| (thousands of units) |
|
PSU |
|
RSU |
|
DSU |
|
PSU |
|
RSU |
|
Total |
|
|
|
| Balance, beginning of year |
|
406 |
|
398 |
|
122 |
|
510 |
|
775 |
|
2,211 |
|
|
| Granted |
|
– |
|
– |
|
77 |
|
907 |
|
1,333 |
|
2,317 |
|
|
| Vested |
|
– |
|
(211 |
) |
– |
|
– |
|
(258 |
) |
(469 |
) |
|
| Forfeited |
|
(10 |
) |
(19 |
) |
– |
|
(13 |
) |
(43 |
) |
(85 |
) |
|
|
| Balance, end of period |
|
396 |
|
168 |
|
199 |
|
1,404 |
|
1,807 |
|
3,974 |
|
|
|
Cash-settled LTI Plans
For three months ended March 31, 2015 the Company recorded cash share-based compensation expense of $7.3 million
(2014 – $6.9 million). For the three months ended March 31, 2015, the Company made cash payments of $5.6 million related to its
cash-settled plans (2014 – $11.5 million).
32 ENERPLUS 2015 Q1
REPORT
The
following table summarizes the cumulative share-based compensation expense recognized to-date, which has been recorded to Accounts Payable on the Consolidated Balance Sheets. Unrecognized amounts
will be recorded to cash share-based compensation expense over the remaining vesting terms.
| At March 31, 2015 ($ thousands, except for years) |
|
|
PSU(1) |
|
|
RSU |
|
|
DSU |
|
|
Total |
|
|
| Cumulative recognized share-based compensation expense |
|
$ |
10,316 |
|
$ |
2,441 |
|
$ |
3,089 |
|
$ |
15,846 |
|
| Unrecognized share-based compensation expense |
|
|
2,472 |
|
|
574 |
|
|
– |
|
|
3,046 |
|
|
| Intrinsic value |
|
$ |
12,788 |
|
$ |
3,015 |
|
$ |
3,089 |
|
$ |
18,892 |
|
|
Weighted-average remaining contractual term (years) |
|
|
0.6 |
|
|
0.7 |
|
|
– |
|
|
|
|
|
- (1)
- Includes
estimated performance multipliers.
Equity-settled LTI Plans
For the three months ended March 31, 2015 the Company recorded non-cash share-based compensation expense of $5.0 million
(2014 – $3.0 million).
The
following table summarizes the cumulative share-based compensation expense recognized to-date which is recorded to Paid-in Capital on the Consolidated Balance Sheets. Unrecognized amounts will be
recorded to non-cash share-based compensation expense over the remaining vesting terms.
| At March 31, 2015 ($ thousands, except for years) |
|
|
PSU(1) |
|
|
RSU |
|
|
Total |
|
|
| Cumulative recognized share-based compensation expense |
|
$ |
3,820 |
|
$ |
10,109 |
|
$ |
13,929 |
|
| Unrecognized share-based compensation expense |
|
|
20,204 |
|
|
18,342 |
|
|
38,546 |
|
|
| Fair value |
|
$ |
24,024 |
|
$ |
28,451 |
|
$ |
52,475 |
|
|
Weighted-average remaining contractual term (years) |
|
|
2.5 |
|
|
1.8 |
|
|
|
|
|
- (1)
- Includes
estimated performance multipliers.
(ii) Stock Option Plan
The Company did not grant any stock options for the three months ended March 31, 2015. The following table summarizes the stock option plan
activity for the period ended March 31, 2015:
| Period ended March 31, 2015 |
|
Number of
Options
(thousands) |
|
|
Weighted
Average
Exercise Price |
|
|
| Options outstanding, beginning of year |
|
10,368 |
|
$ |
18.65 |
|
| |
Granted |
|
– |
|
|
– |
|
| |
Exercised |
|
(189 |
) |
|
13.71 |
|
| |
Forfeited |
|
(388 |
) |
|
19.98 |
|
|
| Options outstanding, end of period |
|
9,791 |
|
$ |
18.70 |
|
|
| Options exercisable, end of period |
|
7,764 |
|
$ |
19.95 |
|
|
At March 31, 2015, 7,764,000 options were exercisable at a weighted average reduced exercise price of $19.95 with a weighted average
remaining contractual term of 3.9 years, giving an aggregate intrinsic value of nil (2014 – $20.3 million). The intrinsic value of options exercised
for the period ended March 31, 2015 was $0.1 million (2014 – $2.9 million).
At
March 31, 2015 the total share-based compensation expense related to non-vested options not yet recognized was $0.6 million. The expense is expected to be recognized in net
income over a weighted-average period of 0.9 years.
ENERPLUS 2015 Q1
REPORT 33
d) Paid-in Capital
The following table summarizes the paid-in capital activity for the three months ended March 31, 2015 and the year ended
December 31, 2014:
| ($ thousands) |
|
|
Three months ended
March 31, 2015 |
|
|
|
|
Year ended
December 31, 2014 |
|
|
|
|
|
| Balance, beginning of year |
|
$ |
46,906 |
|
|
|
$ |
38,398 |
|
|
| Share-based compensation – settled |
|
|
(3,095 |
) |
|
|
|
– |
|
|
| Stock Option Plan – exercised |
|
|
(227 |
) |
|
|
|
(4,978 |
) |
|
| Share-based compensation – non-cash |
|
|
4,970 |
|
|
|
|
13,486 |
|
|
|
|
|
| Balance, end of period |
|
$ |
48,554 |
|
|
|
$ |
46,906 |
|
|
|
|
|
e) Basic and Diluted Earnings Per Share
Net income/(loss) per share has been determined as follows:
| |
|
Three months ended March 31
|
| (thousands, except per share amounts) |
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
| Net income/(loss) |
|
$ |
(293,206 |
) |
|
|
$ |
40,037 |
|
Weighted average shares outstanding – Basic |
|
|
205,845 |
|
|
|
|
203,178 |
|
| Dilutive impact of share-based compensation(1) |
|
|
– |
|
|
|
|
2,700 |
|
|
|
|
| Weighted average shares outstanding – Diluted |
|
|
205,845 |
|
|
|
|
205,878 |
|
|
|
|
Net income/(loss) per share |
|
|
|
|
|
|
|
|
|
| |
Basic |
|
$ |
(1.42 |
) |
|
|
$ |
0.20 |
|
| |
Diluted(1) |
|
|
(1.42 |
) |
|
|
|
0.19 |
|
|
|
|
- (1)
- For
the three months ended March 31, 2015 the impact of share-based compensation was anti-dilutive as a conversion to shares would not increase the loss per share.
15) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
a) Fair Value Measurements
At March 31, 2015, 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, 2015 senior notes included in long-term debt had a carrying value of $1,170.4 million and a fair value of $1,276.2 million
(December 31, 2014 – $1,038.0 million and $1,150.0 million, respectively).
There
were no transfers between fair value hierarchy levels during the period.
b) Derivative Financial Instruments
The deferred financial assets and credits on the Consolidated Balance Sheets result from recording derivative financial instruments at fair value.
The
following table summarizes the change in fair value for the three months ended March 31, 2015 and 2014:
| Gain/(Loss) ($ thousands) |
|
|
March 31, 2015 |
|
|
|
|
March 31, 2014 |
|
Income Statement
Presentation |
|
|
|
|
| Cross Currency Interest Rate Swap: |
|
|
|
|
|
|
|
|
|
|
|
| |
Interest |
|
$ |
– |
|
|
|
$ |
(267 |
) |
Interest expense |
|
| |
Foreign Exchange |
|
|
– |
|
|
|
|
1,245 |
|
Foreign exchange |
|
| Foreign Exchange Derivatives |
|
|
(51,762 |
) |
|
|
|
8,323 |
|
Foreign exchange |
|
| Electricity Swaps |
|
|
(927 |
) |
|
|
|
(46 |
) |
Operating expense |
|
| Equity Swaps |
|
|
1,599 |
|
|
|
|
1,222 |
|
General and administrative expense |
|
Commodity Derivative Instruments: |
|
|
|
|
|
|
|
|
|
|
|
| |
Oil |
|
|
(35,959 |
) |
|
|
|
(9,393 |
) |
Commodity derivative |
|
| |
Gas |
|
|
(450 |
) |
|
|
|
(7,893 |
) |
instruments |
|
|
|
|
| Total |
|
$ |
(87,499 |
) |
|
|
$ |
(6,809 |
) |
|
|
|
|
|
34 ENERPLUS 2015 Q1
REPORT
The following table summarizes the income statement effects of Enerplus' commodity derivative instruments:
| |
|
Three months ended March 31
|
| ($ thousands) |
|
|
2015 |
|
|
|
|
2014 |
|
|
|
|
|
| Change in fair value gain/(loss) |
|
$ |
(36,409 |
) |
|
|
$ |
(17,286 |
) |
|
| Net realized cash gain/(loss) |
|
|
86,807 |
|
|
|
|
(15,311 |
) |
|
|
|
|
| Commodity derivative instruments gain/(loss) |
|
$ |
50,398 |
|
|
|
$ |
(32,597 |
) |
|
|
|
|
The following table summarizes the fair values at the respective period ends:
| |
|
March 31, 2015
|
|
December 31, 2014
|
| |
|
Assets
|
|
Liabilities
|
|
|
Assets
|
|
Liabilities
|
| ($ thousands) |
|
|
Current |
|
|
Current |
|
|
|
Current |
|
|
Long-term |
|
|
Current |
|
|
Long-term |
|
|
|
|
| Foreign Exchange Derivatives |
|
$ |
2,700 |
|
$ |
32,615 |
|
|
$ |
1,616 |
|
$ |
28,665 |
|
$ |
8,434 |
|
$ |
– |
|
| Electricity Swaps |
|
|
– |
|
|
2,295 |
|
|
|
– |
|
|
– |
|
|
1,368 |
|
|
– |
|
| Equity Swaps |
|
|
– |
|
|
1,821 |
|
|
|
– |
|
|
– |
|
|
1,024 |
|
|
2,396 |
|
Commodity Derivative Instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Oil |
|
|
131,228 |
|
|
– |
|
|
|
167,187 |
|
|
– |
|
|
– |
|
|
– |
|
| |
Gas |
|
|
48,785 |
|
|
– |
|
|
|
46,903 |
|
|
2,332 |
|
|
– |
|
|
– |
|
|
|
|
| Total |
|
$ |
182,713 |
|
$ |
36,731 |
|
|
$ |
215,706 |
|
$ |
30,997 |
|
$ |
10,826 |
|
$ |
2,396 |
|
|
|
|
c) Risk Management
(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.
ENERPLUS 2015 Q1
REPORT 35
The
following tables summarize Enerplus' price risk management positions at May 5, 2015:
Crude Oil Instruments:
| Instrument Type(1) |
|
bbls/day |
|
US$/bbl |
|
|
|
| April 1, 2015 – April 30, 2015 |
|
|
|
|
|
|
| WTI Swap |
|
17,500 |
|
88.85 |
|
|
| WCS Differential Swap |
|
4,000 |
|
(18.24 |
) |
|
| WTI Purchased Call |
|
4,000 |
|
93.00 |
|
|
| WTI Sold Put |
|
4,000 |
|
62.23 |
|
|
May 1, 2015 – May 31, 2015 |
|
|
|
|
|
|
| WTI Swap |
|
17,500 |
|
89.18 |
|
|
| WCS Differential Swap |
|
4,000 |
|
(18.24 |
) |
|
| WTI Purchased Call |
|
4,000 |
|
93.00 |
|
|
| WTI Sold Put |
|
4,000 |
|
62.23 |
|
|
Jun 1, 2015 – Jun 30, 2015 |
|
|
|
|
|
|
| WTI Swap |
|
15,500 |
|
93.58 |
|
|
| WCS Differential Swap |
|
4,000 |
|
(18.24 |
) |
|
| WTI Purchased Call |
|
4,000 |
|
93.00 |
|
|
| WTI Sold Put |
|
4,000 |
|
62.23 |
|
|
Jul 1, 2015 – Dec 31, 2015 |
|
|
|
|
|
|
| WTI Swap |
|
8,000 |
|
93.86 |
|
|
| WCS Differential Swap |
|
3,000 |
|
(17.85 |
) |
|
| WTI Purchased Call |
|
4,000 |
|
93.00 |
|
|
| WTI Sold Put |
|
4,000 |
|
62.23 |
|
|
Jan 1, 2016 – Dec 31, 2016 |
|
|
|
|
|
|
| WTI Swap |
|
2,000 |
|
65.50 |
|
|
| WTI Purchased Put |
|
6,000 |
|
65.00 |
|
|
| WTI Sold Put |
|
6,000 |
|
50.00 |
|
|
| WTI Sold Call |
|
6,000 |
|
80.00 |
|
|
|
- (1)
- Transactions
with a common term have been aggregated and presented at weighted average price/bbl.
Natural Gas Instruments:
| Instrument Type |
|
MMcf/day |
|
US$/Mcf |
|
|
Apr 1, 2015 – Jun 30, 2015 |
|
|
|
|
|
| NYMEX Swap |
|
110.0 |
|
3.98 |
|
| NYMEX Purchased Call |
|
5.0 |
|
4.29 |
|
| NYMEX Sold Put |
|
5.0 |
|
3.25 |
|
| NYMEX Sold Call |
|
5.0 |
|
5.00 |
|
Jul 1, 2015 – Sep 30, 2015 |
|
|
|
|
|
| NYMEX Swap |
|
135.0 |
|
3.83 |
|
| NYMEX Purchased Call |
|
5.0 |
|
4.29 |
|
| NYMEX Sold Put |
|
5.0 |
|
3.25 |
|
| NYMEX Sold Call |
|
5.0 |
|
5.00 |
|
Oct 1, 2015 – Oct 31, 2015 |
|
|
|
|
|
| NYMEX Swap |
|
115.0 |
|
3.85 |
|
| NYMEX Purchased Call |
|
5.0 |
|
4.29 |
|
| NYMEX Sold Put |
|
5.0 |
|
3.25 |
|
| NYMEX Sold Call |
|
5.0 |
|
5.00 |
|
Nov 1, 2015 – Dec 31, 2015 |
|
|
|
|
|
| NYMEX Swap |
|
95.0 |
|
4.04 |
|
| NYMEX Purchased Call |
|
5.0 |
|
4.29 |
|
| NYMEX Sold Put |
|
5.0 |
|
3.25 |
|
| NYMEX Sold Call |
|
5.0 |
|
5.00 |
|
|
36 ENERPLUS 2015 Q1
REPORT
Electricity Instruments:
| Instrument Type |
|
MWh |
|
CDN$/MWh |
|
|
| Apr 1, 2015 – Dec 31, 2015 |
|
|
|
|
|
| AESO Power Swap |
|
16.0 |
|
48.30 |
|
Jan 1, 2016 – Dec 31, 2016 |
|
|
|
|
|
| AESO Power Swap |
|
12.0 |
|
47.00 |
|
|
- (1)
- Alberta
Electrical System Operator ("AESO") fixed pricing.
Foreign Exchange Risk:
Enerplus is exposed to foreign exchange risk in relation to its U.S. operations, and U.S. dollar denominated senior notes and working capital.
Additionally, Enerplus' crude oil sales and a portion of its natural gas sales are based on U.S. dollar indices. Enerplus manages currency risk relating to its senior notes through the
derivative instruments detailed below.
Foreign Exchange Derivatives:
During 2014, Enerplus entered into foreign exchange collars to hedge a portion of its foreign exchange exposure on U.S. dollar denominated oil and gas
sales. The following contracts are outstanding at May 5, 2015:
| Instrument Type(1) |
|
Monthly Notional Amount
(US$ millions) |
|
Floor |
|
Ceiling |
|
Conditional
Ceiling(2) |
|
|
| Apr 1, 2015 – Dec 31, 2015 |
|
24.0 |
|
1.1088 |
|
1.1845 |
|
1.1263 |
|
|
- (1)
- Transactions
with a common term have been aggregated and presented at average USD/CDN foreign exchange rates.
- (2)
- If
the USD/CDN average monthly rate settles above the ceiling rate the settlement amount is determined based on the conditional ceiling.
During 2007 Enerplus entered into foreign exchange swaps on US$54.0 million of notional debt at an average US$/CDN$ exchange rate of 1.02. The remaining
$10.8 million notional amount under the swap matures in October 2015 in conjunction with the final principal repayment on the US$54.0 million senior notes.
During
2011 Enerplus entered into foreign exchange swaps on US$175.0 million of notional debt at approximately par. During the quarter, Enerplus unwound these swaps and recognized a gain of
$39.9 million and an offsetting non-cash loss of $27.6 million which have been included in foreign exchange gain/loss on the Consolidated Statements of Income/(Loss).
Interest Rate Risk:
At March 31, 2015, approximately 90% of Enerplus' debt was based on fixed interest rates and 10% was based on floating interest rates. At
March 31, 2015 Enerplus did not have any interest rate derivatives outstanding.
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 2015 and 2017 and has effectively fixed the future settlement cost on 630,000 shares at a weighted average price of $15.82 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 2015 Q1
REPORT 37
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, 2015 approximately 73% of Enerplus' marketing receivables were with companies considered investment grade.
At
March 31, 2015 approximately $7.4 million or 5% of Enerplus' total accounts receivable were aged over 120 days and considered past due. 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, 2015 was $2.8 million
(December 31, 2014 – $2.7 million).
(iii) Liquidity Risk & Capital Management
Liquidity risk represents the risk that Enerplus will be unable to meet its financial obligations as they become due. Enerplus mitigates liquidity risk through
actively managing its capital, which it defines as debt (net of cash) and shareholders' capital. Enerplus' objective is to provide adequate short and longer term liquidity while maintaining a
flexible capital structure to sustain the future development of its business. Enerplus strives to balance the portion of debt and equity in its capital structure given its current oil and natural gas
assets and planned investment opportunities.
Management
monitors a number of key variables with respect to its capital structure, including debt levels, capital spending plans, dividends, access to capital markets, as well as acquisition and
divestment activity.
At
March 31, 2015, Enerplus was in full compliance with all covenants under the bank credit facility and outstanding senior notes.
16) CONTINGENCIES
Enerplus is subject to various legal claims and actions arising in the normal course of business. Although the outcome of such claims and actions cannot be
predicted with certainty, the Company does not expect these matters to have a material impact on the Consolidated Financial Statements. In instances where the Company determines that a loss is
probable and the amount can be reasonably estimated, an accrual is recorded.
17) SUPPLEMENTAL CASH FLOW INFORMATION
a) Changes in Non-Cash Operating Working Capital
| ($ thousands) |
|
|
Three months ended,
March 31, 2015 |
|
|
|
|
Three months ended
March 31, 2014 |
|
|
|
|
|
| Accounts receivable |
|
$ |
47,966 |
|
|
|
$ |
(37,424 |
) |
|
| Other current assets |
|
|
(4,798 |
) |
|
|
|
923 |
|
|
| Accounts payable |
|
|
(17,346 |
) |
|
|
|
(39,309 |
) |
|
|
|
|
| |
|
$ |
25,822 |
|
|
|
$ |
(75,810 |
) |
|
|
|
|
b) Supplementary Cash Flow Information
| ($ thousands) |
|
|
Three months ended,
March 31, 2015 |
|
|
|
|
Three months ended,
March 31, 2014 |
|
|
|
|
|
| Income taxes paid/(received) |
|
$ |
(19,344 |
) |
|
|
$ |
(134 |
) |
|
| Interest paid |
|
$ |
6,482 |
|
|
|
$ |
2,383 |
|
|
|
|
|
18) SUBSEQUENT EVENT
Subsequent to March 31, 2015 Enerplus closed non-core asset dispositions for proceeds of $185.8 million, after closing adjustments.
38 ENERPLUS 2015 Q1
REPORT
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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, 2015.
- 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(s) 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(s) 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(s) 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, 2015 and ended on March 31, 2015 that has materially affected, or is reasonably likely to materially affect, the issuer's ICFR.
Date:
May 8, 2015
(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,
ROBERT J. WATERS, 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, 2015.
- 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(s) 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(s) 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(s) 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, 2015 and ended on March 31, 2015 that has materially affected, or is reasonably likely to materially affect, the
issuer's ICFR.
Date:
May 8, 2015
(signed
by)
Robert J. Waters
Senior Vice President and Chief Financial Officer
Enerplus Corporation
QuickLinks
FORM 52-109F2 CERTIFICATION OF INTERIM FILINGS FULL CERTIFICATE
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