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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 NOVEMBER, 2014
COMMISSION FILE NUMBER 1-15150
Enerplus Corporation
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.
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)
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)
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.
EXHIBIT INDEX
EXHIBIT
99.1 — Management's Discussion and Analysis for the Third Quarter ended September 30, 2014
EXHIBIT
99.2 — Unaudited Consolidated Financial Statements for the Third Quarter ended September 30, 2014
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 |
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DATE: November 7, 2014
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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 November 6, 2014 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 and nine months ended
September 30, 2014 and 2013 (the "Interim Financial Statements");
- •
- the
audited consolidated financial statements of Enerplus as at December 31, 2013 and 2012 and for the years ended December 31, 2013, 2012
and 2011 (the "Financial Statements"); and
- •
- our
MD&A for the year ended December 31, 2013 (the "Annual MD&A").
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.
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.
BASIS OF PRESENTATION
The Interim Financial Statements and notes have been prepared in accordance with accounting principles generally accepted in the United States of America
("U.S. GAAP") including the prior period comparatives. All amounts are stated in Canadian dollars unless otherwise specified.
In
accordance with U.S. GAAP, oil and gas sales are presented net of royalties in our Interim Financial Statements. Under IFRS, industry standard is to present oil and gas sales before
deduction of royalties and as such this MD&A presents production, oil and gas sales, and BOE measures on this basis to remain comparable with our peers.
NON-GAAP MEASURES
The Company utilizes the following terms for measurement within the MD&A that do not have a standardized meaning or definition as prescribed by U.S. GAAP
and therefore may not be comparable with the calculation of similar measures by other entities:
"Netback" is used by Enerplus and is useful to investors and securities analysts in evaluating operating performance of our crude oil and natural gas
assets. The term netback is calculated as oil and natural gas sales revenue (net of transportation), less royalties, production taxes and cash operating costs.
"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 but before asset retirement obligation expenditures and changes in non-cash operating working capital.
| |
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Three months ended September 30,
|
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Nine months ended September 30,
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| Reconciliation of Cash Flow from Operating Activities to Funds Flow |
|
|
2014 |
|
|
|
2013 |
|
|
|
|
2014 |
|
|
|
2013 |
|
|
|
|
|
|
|
|
|
| Cash flow from operating activities |
|
$ |
199,045 |
|
|
$ |
218,170 |
|
|
|
$ |
567,961 |
|
|
$ |
574,828 |
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| Asset retirement obligation expenditures |
|
|
3,299 |
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|
|
3,701 |
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|
11,831 |
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|
10,036 |
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| Changes in non-cash operating working capital |
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|
10,435 |
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|
(25,684 |
) |
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|
66,710 |
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|
(11,372 |
) |
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|
|
|
|
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| Funds flow |
|
$ |
212,779 |
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|
$ |
196,187 |
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|
|
$ |
646,502 |
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|
$ |
573,492 |
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6 ENERPLUS 2014 Q3
REPORT
"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.
"Adjusted Payout Ratio" is used by Enerplus and is useful to investors and securities analysts in analyzing operating performance, leverage and
liquidity. We calculate our adjusted payout ratio as dividends to shareholders, net of our Stock Dividend Program ("SDP") proceeds, plus capital spending (including office capital) divided by
funds flow.
OVERVIEW
Production for the third quarter averaged 104,035 BOE/day, consistent with the prior quarter and an increase of 19% compared to the same period in 2013.
Crude oil and natural gas liquids production grew by 2% compared to the prior quarter, while natural gas volumes were essentially flat. Low natural gas prices and pipeline maintenance resulted in
production curtailments of approximately 3,000-4,000 BOE/day in the Marcellus during the quarter. Despite these interruptions, average production volumes for the year to date are
ahead of expectations and we have increased our guidance again for 2014 to 102,000-104,000 BOE/day from 100,000-104,000 BOE/day.
Our
capital spending program continued to focus on our core development areas, with $207.8 million spent in the third quarter. As discussed in our second quarter release, the successful
divestment of approximately $91.0 million of non-core assets in the second half of 2014 has provided us with additional flexibility and we have redeployed a portion of the divestment proceeds
to accelerate our 2015 capital program in our core areas. Accordingly, we have increased our capital spending guidance for 2014 to $830 million from $800 million.
Funds
flow for the third quarter totaled $212.8 million compared to $213.2 million in the second quarter and $196.2 million in the same period in 2013. In the third quarter our
funds flow was impacted by lower commodity prices however this was partially offset by cash share-based compensation recoveries given the industry wide sell off in equities. Lower commodity prices at
quarter end resulted in a $93.8 million non-cash gain on our commodity derivatives which contributed to a nearly 70% increase in our net income compared to the second quarter.
Cash
general and administrative expenses for the quarter of $1.97/BOE were consistent with the second quarter. Operating costs increased to $10.67/BOE, compared to $10.09/BOE in the prior quarter, due
to production curtailments on our lower operating cost Marcellus properties along with seasonal well servicing and higher repairs and maintenance costs. Based on continued production curtailments in
the Marcellus throughout the fourth quarter, we are reverting to our original 2014 operating costs guidance of $10.25/BOE from $10.10/BOE.
Although
oil prices declined significantly during the quarter, we continue to maintain a strong balance sheet and financial flexibility. During the quarter, we closed a US$200 million private
placement of 3.79%, 10 year average life senior notes and used the proceeds to repay outstanding bank debt. At September 30, 2014 only 5% of our $1 billion credit facility
was drawn and our trailing 12 month debt to funds flow ratio was 1.3x. We also have a strong hedge position in place with approximately 64% of our anticipated remaining 2014 crude oil
production hedged at a price of $95.29, and approximately 38% of our anticipated 2015 crude oil production hedged at $93.68.
RESULTS OF OPERATIONS
Production
Production levels were maintained in the third quarter with production of 104,035 BOE/day despite production curtailments that averaged
3,000-4,000 BOE/day over the quarter due to decreased natural gas prices and pipeline maintenance in the Marcellus. Our Fort Berthold crude oil production grew by 6% from the prior quarter with
our ongoing development program more than fully offsetting the decline in other crude oil assets.
Compared
to the third quarter of 2013, production increased 19% or 16,306 BOE/day. Natural gas volumes grew by approximately 30% due to our ongoing development activity in the Marcellus
combined with the fourth quarter 2013 acquisition of additional working interests in our existing Marcellus properties. Over the same period, our crude oil volumes increased by approximately 4% due to
growth in our Fort Berthold production volumes.
Our
production mix was unchanged from the previous quarter, with natural gas being 58% of production and crude oil and natural gas liquids making up 42% of production.
ENERPLUS 2014 Q3
REPORT 7
Average
daily production volumes for the three and nine months ended September 30, 2014 and 2013 are outlined below:
| |
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Three months ended September 30,
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Nine months ended September 30,
|
| Average Daily Production Volumes |
|
2014 |
|
|
2013 |
|
% Change |
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|
2014 |
|
|
2013 |
|
% Change |
|
|
|
|
|
|
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| Crude oil (bbls/day) |
|
40,332 |
|
|
38,883 |
|
4% |
|
|
39,328 |
|
|
38,426 |
|
2% |
|
| Natural gas liquids (bbls/day) |
|
3,869 |
|
|
2,985 |
|
30% |
|
|
3,591 |
|
|
3,357 |
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7% |
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| Natural gas (Mcf/day) |
|
359,007 |
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|
275,164 |
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30% |
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|
356,288 |
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|
279,212 |
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28% |
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| Total daily sales (BOE/day) |
|
104,035 |
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|
87,729 |
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19% |
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|
102,300 |
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|
88,318 |
|
16% |
|
|
|
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|
Based on our year to date performance, we have revised our 2014 annual average production guidance to 102,000-104,000 BOE/day from
100,000-104,000 BOE/day. The lower end of the guidance range assumes ongoing production curtailments in the Marcellus throughout the fourth quarter. This guidance also includes the impact of
the September 30, 2014 non-core asset disposition of 1,900 BOE/day and the divestment of non-core gas weighted properties with production of approximately 1,200 BOE/day in
the fourth quarter.
Our
crude oil and natural gas liquids production has been strong in October. We have just finished drilling and completing a five well pad in North Dakota that we expect to have tied-in by early
November. We expect our crude oil and natural gas liquids production to increase to approximately 47,000 BOE/day for the fourth quarter and continue to expect average annual crude oil and
natural gas liquids production to grow by 5% from 2013 to average 44,000 BOE/day.
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
the nine month period ended September 30, 2014 and 2013 and quarterly average prices from the third quarter of 2014 to the third quarter of 2013.
| |
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Nine months ended
September 30,
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| Pricing (average for the period) |
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2014 |
|
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2013 |
|
|
|
|
Q3 2014 |
|
|
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Q2 2014 |
|
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Q1 2014 |
|
|
Q4 2013 |
|
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Q3 2013 |
|
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|
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| Benchmarks |
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| |
WTI crude oil (US$/bbl) |
|
$ |
99.61 |
|
|
|
$ |
98.14 |
|
|
|
$ |
97.17 |
|
|
|
$ |
102.99 |
|
$ |
98.68 |
|
$ |
97.46 |
|
$ |
105.82 |
|
|
| |
AECO natural gas – monthly index (CDN$/Mcf) |
|
|
4.55 |
|
|
|
|
3.16 |
|
|
|
|
4.22 |
|
|
|
|
4.68 |
|
|
4.76 |
|
|
3.16 |
|
|
2.82 |
|
|
| |
AECO natural gas – daily index (CDN$/Mcf) |
|
|
4.81 |
|
|
|
|
3.05 |
|
|
|
|
4.02 |
|
|
|
|
4.69 |
|
|
5.71 |
|
|
3.53 |
|
|
2.43 |
|
|
| |
NYMEX natural gas – last day (US$/Mcf) |
|
|
4.55 |
|
|
|
|
3.67 |
|
|
|
|
4.06 |
|
|
|
|
4.67 |
|
|
4.94 |
|
|
3.60 |
|
|
3.58 |
|
|
| |
US/CDN exchange rate |
|
|
1.09 |
|
|
|
|
1.02 |
|
|
|
|
1.09 |
|
|
|
|
1.09 |
|
|
1.10 |
|
|
1.05 |
|
|
1.04 |
|
|
Enerplus selling price (1) |
|
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|
|
|
|
|
| |
Crude oil (CDN$/ bbl) |
|
$ |
90.91 |
|
|
|
$ |
86.05 |
|
|
|
$ |
86.49 |
|
|
|
$ |
94.90 |
|
$ |
91.48 |
|
$ |
77.77 |
|
$ |
96.30 |
|
|
| |
Natural gas liquids (CDN$/ bbl) |
|
|
53.01 |
|
|
|
|
51.48 |
|
|
|
|
44.85 |
|
|
|
|
49.98 |
|
|
66.30 |
|
|
54.26 |
|
|
49.88 |
|
|
| |
Natural gas (CDN$/ Mcf) |
|
|
4.04 |
|
|
|
|
3.26 |
|
|
|
|
3.22 |
|
|
|
|
4.02 |
|
|
4.93 |
|
|
3.26 |
|
|
2.96 |
|
|
|
|
|
|
|
|
|
Average differentials |
|
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|
|
|
|
|
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|
|
|
|
|
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|
|
|
|
|
|
|
| |
MSW Edmonton – WTI (US$/bbl) |
|
$ |
(7.44 |
) |
|
|
$ |
(5.11 |
) |
|
|
$ |
(7.93 |
) |
|
|
$ |
(6.13 |
) |
$ |
(8.25 |
) |
$ |
(14.93 |
) |
$ |
(4.72 |
) |
|
| |
WCS Hardisty – WTI (US$/bbl) |
|
|
(21.12 |
) |
|
|
|
(22.86 |
) |
|
|
|
(20.18 |
) |
|
|
|
(20.04 |
) |
|
(23.13 |
) |
|
(32.20 |
) |
|
(17.48 |
) |
|
| |
Brent Futures (ICE) – WTI (US$/bbl) |
|
|
7.40 |
|
|
|
|
10.40 |
|
|
|
|
6.25 |
|
|
|
|
6.75 |
|
|
9.19 |
|
|
11.86 |
|
|
3.83 |
|
|
| |
AECO monthly – NYMEX (US$/Mcf) |
|
|
(0.40 |
) |
|
|
|
(0.62 |
) |
|
|
|
(0.18 |
) |
|
|
|
(0.38 |
) |
|
(0.63 |
) |
|
(0.60 |
) |
|
(0.86 |
) |
|
Enerplus realized differentials(1) |
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Canada crude oil – WTI (US$/bbl) |
|
$ |
(20.45 |
) |
|
|
$ |
(19.96 |
) |
|
|
$ |
(21.78 |
) |
|
|
$ |
(17.80 |
) |
$ |
(20.70 |
) |
$ |
(30.73 |
) |
$ |
(15.18 |
) |
|
| |
Canada natural gas – NYMEX (US$/Mcf) |
|
|
(0.54 |
) |
|
|
|
(0.77 |
) |
|
|
|
(0.55 |
) |
|
|
|
(0.71 |
) |
|
(0.31 |
) |
|
(0.63 |
) |
|
(1.06 |
) |
|
| |
Bakken crude oil – WTI (US$/bbl) |
|
|
(13.78 |
) |
|
|
|
(8.84 |
) |
|
|
|
(14.72 |
) |
|
|
|
(14.55 |
) |
|
(11.85 |
) |
|
(17.47 |
) |
|
(11.41 |
) |
|
| |
Marcellus natural gas – NYMEX (US$/Mcf) |
|
|
(1.38 |
) |
|
|
|
(0.25 |
) |
|
|
|
(1.72 |
) |
|
|
|
(1.50 |
) |
|
(0.88 |
) |
|
(0.50 |
) |
|
(0.52 |
) |
|
|
|
|
|
|
|
|
- (1)
- Net
of oil and gas transportation costs, but before the effects of royalties and commodity derivative instruments.
8 ENERPLUS 2014 Q3
REPORT
Crude Oil and Natural Gas Liquids
Our crude oil selling price decreased 9% from the prior quarter as a result of lower benchmark prices and widening differentials. WTI crude oil averaged
US$97.17/bbl during the third quarter, down almost US$6.00/bbl from the previous period. Global prices declined steadily due to a combination of seasonal refinery turnarounds reducing demand and
higher than anticipated global oil production, primarily in North America and Libya. WTI exited September at US$91.16/bbl and continued to weaken in the fourth quarter.
Light
sweet crude oil differentials in Canada weakened considerably during the third quarter with mixed sweet blend (MSW) differentials averaging US$7.93/bbl below WTI as a result of continued
apportionment on the Canadian pipeline systems decreasing takeaway capacity. The market continues to await the start of the Line 9 pipeline reversal from Sarnia, Ontario to Montreal, Quebec,
which is now delayed until early 2015. Once operational, this reversal will provide access to refineries in Eastern Canada and may provide support for light sweet crude prices. In the US, delays in
the startup of the Pony Express pipeline from Guernsey, Wyoming to Cushing, Oklahoma continued to restrict takeaway capacity and negatively impact our realized Bakken differentials in the field, which
averaged US$14.72/bbl below WTI for the quarter. Western Canadian Select (WCS) heavy oil differentials remained steady at US$20.18/bbl below WTI but began to strengthen near the end of the quarter as
the Flanagan South pipeline project from Pontiac, Illinois to Cushing, Oklahoma began purchasing line fill prior to start-up in the fourth quarter.
Natural
Gas
Our selling price decreased 20% compared to the second quarter as a result of lower benchmark prices and widening differentials in the Marcellus region.
U.S. natural gas prices continued to fall throughout the third quarter as a result of cooler than average summer weather. This led to significantly higher than expected storage injections
across most regions and contributed to NYMEX prices falling by over US$0.60/Mcf, averaging US$4.06/Mcf in the third quarter.
In
Canada, the AECO differential to NYMEX narrowed to US$0.18/Mcf below NYMEX during the third quarter, compared to US$0.38/Mcf in the second quarter, given the slower pace of storage refill in
western Canada. We continue to maintain a balanced mix of AECO basis, month
and day index price exposures in our Canadian gas portfolio, with our index exposure split almost evenly between month and day AECO indices.
Natural
gas prices in the Marcellus continued to trade at a significant discount to NYMEX, as Marcellus and Utica production continued to outpace growth in pipeline takeaway capacity. Our production
is priced primarily off of northeast Pennsylvania and Dominion South Point prices. Scheduled maintenance across a number of interstate pipelines resulted in volatility of spot prices throughout
northeast Pennsylvania, with spot prices in the region averaging approximately US$2.00/Mcf below NYMEX for the quarter. With approximately 55% of our Marcellus production during the quarter exposed to
spot prices in northeast Pennsylvania and approximately 36% exposed to Dominion South Point, we realized a Marcellus price differential of US$1.72/Mcf below NYMEX. We continue to expect wide
differentials in the Marcellus for the remainder of the year, although new pipeline capacity coming on-stream on November 1, 2014 may provide some relief.
Foreign
Exchange
The majority of our oil and gas sales are based on U.S. dollar denominated indices, and a weaker Canadian dollar relative to the U.S. dollar
increases the amount of our realized sales. After regaining some ground in the second quarter, the Canadian dollar weakened by nearly 5% in the third quarter and exited September near year to date
lows. During the third quarter, we continued to enter into foreign exchange costless collars on our oil and gas sales to hedge a floor exchange rate on a portion of our U.S. dollar denominated
oil and gas sales and to participate in some upside potential in the event the Canadian dollar continues to weaken.
As
of October 22, 2014 we have US$26 million per month hedged for the remainder of 2014 at an average USD/CDN floor of 1.1064, ceiling of 1.1500 and conditional ceiling of 1.1212.
For 2015, we have US$24 million per month hedged at an average USD/CDN floor of 1.1088, ceiling of 1.1845 and 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. During the third quarter, we recorded cash gains of $0.6 million and non-cash
mark-to-market losses of $8.7 million on these contracts.
ENERPLUS 2014 Q3
REPORT 9
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. During
the third quarter and fourth quarter to date we continued to add risk management positions for both crude oil and natural gas. With the decline in crude oil prices we bought back the upside on a
portion of our previously swapped crude oil volumes through costless upside participation collars. With respect to natural gas, we entered into additional swap positions for 2015 and 2016 to add more
downside protection.
As
of October 22, 2014, we have swapped approximately 64% of our forecasted net crude oil production for the remainder of 2014 at an average price of US$95.29/bbl. For the first and
second half of 2015, we have swapped approximately 50% and 26%, respectively, of our forecasted net crude oil production at an average price of US$93.58/bbl, and US$93.86/bbl, respectively. In
relation to a portion of the volumes swapped we have purchased call options to participate in price upside above US$94.00/bbl and sold put options at an average strike price of US$63.00/bbl,
offsetting the call premium. We also have WCS and MSW differential swap positions to manage our exposure to Canadian crude oil differentials. We expect these contracts to protect a significant portion
of our funds flow in the near term.
As
of October 22, 2014, we have downside protection on approximately 49% and 28% of our forecasted net natural gas production after royalties for the remainder of 2014 and full year
2015, respectively, consisting of a combination of NYMEX swaps, NYMEX collars and AECO swaps.
The
following is a summary of our financial contracts in place at October 22, 2014 expressed as a percentage of our anticipated net production volumes:
| |
WTI Crude Oil
(US$/bbl)(1)
|
|
AECO
Natural Gas
(CDN$/Mcf)(1)
|
|
NYMEX Natural Gas
(US$/Mcf)(1)
|
|
| |
|
Oct 1,
2014 –
Dec 31,
2014 |
|
|
Jan 1,
2015 –
Jun 30,
2015 |
|
|
Jul 1,
2015 –
Dec 31,
2015 |
|
|
Oct 1,
2014 –
Dec 31,
2014 |
|
|
Oct 1,
2014 –
Dec 31,
2014 |
|
|
Jan 1,
2015 –
Mar 31,
2015 |
|
|
Apr 1,
2015 –
Jun 30,
2015 |
|
|
Jul 1,
2015 –
Dec 31,
2015 |
|
|
Jan 1,
2016 –
Dec 31,
2016 |
|
|
| Downside Protection Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Sold Swaps |
$ |
95.29 |
|
$ |
93.58 |
|
$ |
93.86 |
|
$ |
4.25 |
|
$ |
4.14 |
|
$ |
4.25 |
|
$ |
4.25 |
|
$ |
4.16 |
|
$ |
4.03 |
|
| % |
|
64% |
|
|
50% |
|
|
26% |
|
|
10% |
|
|
28% |
|
|
29% |
|
|
29% |
|
|
22% |
|
|
4% |
|
Downside Protection Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Purchased Puts |
|
– |
|
|
– |
|
|
– |
|
|
– |
|
$ |
4.30 |
|
$ |
4.53 |
|
|
– |
|
|
– |
|
|
– |
|
| % |
|
– |
|
|
– |
|
|
– |
|
|
– |
|
|
11% |
|
|
11% |
|
|
– |
|
|
– |
|
|
– |
|
| Sold Calls |
|
– |
|
|
– |
|
|
– |
|
|
– |
|
$ |
5.08 |
|
$ |
5.53 |
|
|
– |
|
|
– |
|
|
– |
|
| % |
|
– |
|
|
– |
|
|
– |
|
|
– |
|
|
11% |
|
|
11% |
|
|
– |
|
|
– |
|
|
– |
|
Upside Participation Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Sold Puts |
|
– |
|
$ |
63.00 |
|
$ |
63.00 |
|
|
– |
|
$ |
3.23 |
|
$ |
3.25 |
|
$ |
3.25 |
|
$ |
3.25 |
|
|
– |
|
| % |
|
– |
|
|
6% |
|
|
6% |
|
|
– |
|
|
9% |
|
|
2% |
|
|
2% |
|
|
2% |
|
|
– |
|
| Sold Calls |
|
– |
|
|
– |
|
|
– |
|
|
– |
|
$ |
5.00 |
|
$ |
5.00 |
|
$ |
5.00 |
|
$ |
5.00 |
|
|
– |
|
| % |
|
– |
|
|
– |
|
|
– |
|
|
– |
|
|
9% |
|
|
2% |
|
|
2% |
|
|
2% |
|
|
– |
|
| Purchased Calls |
|
– |
|
$ |
94.00 |
|
$ |
94.00 |
|
|
– |
|
$ |
4.17 |
|
$ |
4.29 |
|
$ |
4.29 |
|
$ |
4.29 |
|
|
– |
|
| % |
|
– |
|
|
6% |
|
|
6% |
|
|
– |
|
|
9% |
|
|
2% |
|
|
2% |
|
|
2% |
|
|
– |
|
|
- (1)
- Based
on weighted average price (before premiums), assumed average annual production of 102,000 – 104,000 BOE/day for 2014 and 2015, less
royalties and production taxes of 23% in aggregate.
10 ENERPLUS 2014 Q3
REPORT
ACCOUNTING FOR PRICE RISK MANAGEMENT
| |
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
Risk Management Gains/(Losses)
($ millions) |
|
|
2014 |
|
|
|
|
2013 |
|
|
|
|
2014 |
|
|
|
|
2013 |
|
|
|
|
|
|
|
|
|
| Cash gains/(losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Crude oil |
|
$ |
(4.2 |
) |
|
|
$ |
(12.9 |
) |
|
|
$ |
(36.2 |
) |
|
|
$ |
9.0 |
|
|
| |
Natural gas |
|
|
1.7 |
|
|
|
|
2.3 |
|
|
|
|
(6.2 |
) |
|
|
|
1.1 |
|
|
|
|
|
|
|
|
|
| Total cash gains/(losses) |
|
$ |
(2.5 |
) |
|
|
$ |
(10.6 |
) |
|
|
$ |
(42.4 |
) |
|
|
$ |
10.1 |
|
|
Non-cash gains/(losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Change in fair value – crude oil |
|
$ |
82.9 |
|
|
|
$ |
(45.6 |
) |
|
|
$ |
48.7 |
|
|
|
$ |
(66.5 |
) |
|
| |
Change in fair value – natural gas |
|
|
10.9 |
|
|
|
|
0.5 |
|
|
|
|
8.3 |
|
|
|
|
4.3 |
|
|
|
|
|
|
|
|
|
| Total non-cash gains/(losses) |
|
$ |
93.8 |
|
|
|
$ |
(45.1 |
) |
|
|
$ |
57.0 |
|
|
|
$ |
(62.2 |
) |
|
|
|
|
|
|
|
|
| Total gains/(losses) |
|
$ |
91.3 |
|
|
|
$ |
(55.7 |
) |
|
|
$ |
14.6 |
|
|
|
$ |
(52.1 |
) |
|
|
|
|
|
|
|
|
| |
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
| (Per BOE) |
|
|
2014 |
|
|
|
|
2013 |
|
|
|
|
2014 |
|
|
|
|
2013 |
|
|
|
|
|
|
|
|
|
| Total cash gains/(losses) |
|
$ |
(0.26 |
) |
|
|
$ |
(1.30 |
) |
|
|
$ |
(1.52 |
) |
|
|
$ |
0.42 |
|
|
| Total non-cash gains/(losses) |
|
|
9.80 |
|
|
|
|
(5.60 |
) |
|
|
|
2.04 |
|
|
|
|
(2.58 |
) |
|
|
|
|
|
|
|
|
| Total gains/(losses) |
|
$ |
9.54 |
|
|
|
$ |
(6.90 |
) |
|
|
$ |
0.52 |
|
|
|
$ |
(2.16 |
) |
|
|
|
|
|
|
|
|
During the third quarter we realized cash losses of $4.2 million on our crude oil contracts and cash gains of $1.7 million on our natural gas
contracts. In comparison, during the third quarter of 2013, we realized cash losses of $12.8 million on our crude oil contracts and cash gains of $2.3 million on our natural gas
contracts. The cash losses realized in 2014 and 2013 were a result of crude oil prices rising above our fixed price swap positions, while cash gains were due to natural gas contracts that provided
floor protection above market prices.
As
the forward markets for crude oil and natural gas fluctuate, as new contracts are executed, and as 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 third quarter of 2014, the fair value of our crude oil and natural gas contracts represented net gain positions of $33.8 million and $8.6 million,
respectively. For the three and nine months ended September 30, 2014 the change in the fair value of our crude oil contracts represented gains of $82.9 million and
$48.7 million, respectively, while the change in fair value of our natural gas contracts represented gains of $10.9 million and $8.3 million, respectively.
Revenues
| |
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
| ($ millions) |
|
|
2014 |
|
|
|
|
2013 |
|
|
|
|
2014 |
|
|
|
|
2013 |
|
|
|
|
|
|
|
|
|
| Oil and natural gas sales |
|
$ |
456.2 |
|
|
|
$ |
441.5 |
|
|
|
$ |
1,455.8 |
|
|
|
$ |
1,219.8 |
|
|
| Royalties |
|
|
(77.9 |
) |
|
|
|
(76.1 |
) |
|
|
|
(254.8 |
) |
|
|
|
(199.7 |
) |
|
|
|
|
|
|
|
|
| Oil and natural gas sales, net of royalties |
|
$ |
378.3 |
|
|
|
$ |
365.4 |
|
|
|
$ |
1,201.0 |
|
|
|
$ |
1,020.1 |
|
|
|
|
|
|
|
|
|
Oil and natural gas sales were $456.2 million in the third quarter of 2014, an increase of 3% or $14.7 million compared to the same period in
2013. For the nine months ended September 30, 2014, oil and natural gas sales were $1,455.8 million, an increase of 19% or $236.0 million compared to the same period a year
ago. The increase in revenues was driven primarily by year over year production growth. Although crude oil and natural gas liquids selling prices were lower during the quarter compared to the same
period in 2013, improved pricing in the first half of the year led to an overall improvement in realized prices year to date.
ENERPLUS 2014 Q3
REPORT 11
Royalties and Production Taxes
| |
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
| ($ millions) |
|
|
2014 |
|
|
|
2013 |
|
|
|
2014 |
|
|
|
2013 |
|
|
|
|
|
|
|
|
| Royalties |
|
$ |
77.9 |
|
|
$ |
76.1 |
|
|
$ |
254.8 |
|
|
$ |
199.7 |
|
| Production taxes |
|
|
21.3 |
|
|
|
20.0 |
|
|
|
61.1 |
|
|
|
52.5 |
|
|
|
|
|
|
|
|
| Royalties and production taxes |
|
$ |
99.2 |
|
|
$ |
96.1 |
|
|
$ |
315.9 |
|
|
$ |
252.2 |
|
|
|
|
|
|
|
|
| As a % of oil and natural gas sales, net of transportation |
|
|
22% |
|
|
|
22% |
|
|
|
22% |
|
|
|
21% |
|
|
|
|
|
|
|
|
| |
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
| (Per BOE) |
|
|
2014 |
|
|
|
2013 |
|
|
|
2014 |
|
|
|
2013 |
|
|
|
|
|
|
|
|
| Royalties |
|
$ |
8.14 |
|
|
$ |
9.43 |
|
|
$ |
9.12 |
|
|
$ |
8.27 |
|
| Production taxes |
|
|
2.22 |
|
|
|
2.48 |
|
|
|
2.19 |
|
|
|
2.19 |
|
|
|
|
|
|
|
|
| Royalties and production taxes |
|
$ |
10.36 |
|
|
$ |
11.91 |
|
|
$ |
11.31 |
|
|
$ |
10.46 |
|
|
|
|
|
|
|
|
| As a % of oil and natural gas sales, net of transportation |
|
|
22% |
|
|
|
22% |
|
|
|
22% |
|
|
|
21% |
|
|
|
|
|
|
|
|
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 three and nine months ended September 30, 2014 royalties and production taxes increased to $99.2 million
and $315.9 million, respectively, from $96.1 million and $252.2 million for the same periods in 2013. This upward trend is primarily due to increased production from higher
royalty rate U.S. properties. As a percentage of oil and gas sales, net of transportation costs, royalties and production taxes averaged 22% for the three and nine months ended
September 30, 2014 compared to 22% and 21%, respectively, for the same periods in 2013.
We
continue to expect an average royalty and production tax rate of 23% in 2014.
Operating Expenses
| |
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
| ($ millions, except per BOE amounts) |
|
|
2014 |
|
|
|
2013 |
|
|
|
2014 |
|
|
|
2013 |
|
|
|
|
|
|
|
|
| Operating Expenses |
|
$ |
102.1 |
|
|
$ |
85.5 |
|
|
$ |
286.7 |
|
|
$ |
252.3 |
|
| Per BOE |
|
$ |
10.67 |
|
|
$ |
10.60 |
|
|
$ |
10.27 |
|
|
$ |
10.46 |
|
|
|
|
|
|
|
|
Operating expenses for the three and nine months ended September 30, 2014 were $102.1 million or $10.67/BOE and $286.7 million or
$10.27/BOE, respectively. In comparison, operating costs were $85.5 million or $10.60/BOE and $252.3 million or $10.46/BOE for the same periods in 2013.
The
production curtailments at our lower operating cost Marcellus properties negatively impacted operating costs on a per BOE basis during the quarter. Seasonal well servicing and higher repairs and
maintenance costs also increased our operating costs in the third quarter.
Based
on ongoing production curtailments in the Marcellus in the fourth quarter we have revised our 2014 guidance to $10.25/BOE from $10.10/BOE, consistent with our original guidance for 2014.
Transportation Costs
| |
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
| ($ millions, except per BOE amounts) |
|
|
2014 |
|
|
|
2013 |
|
|
|
2014 |
|
|
|
2013 |
|
|
|
|
|
|
|
|
| Transportation costs |
|
$ |
14.7 |
|
|
$ |
8.8 |
|
|
$ |
40.9 |
|
|
$ |
22.3 |
|
| Per BOE |
|
$ |
1.53 |
|
|
$ |
1.09 |
|
|
$ |
1.46 |
|
|
$ |
0.92 |
|
|
|
|
|
|
|
|
12 ENERPLUS 2014 Q3
REPORT
Transportation costs for the three and nine months ended September 30, 2014 were $14.7 million or $1.53/BOE and $40.9 million or
$1.46/BOE, respectively, compared to $8.8 million or $1.09/BOE and $22.3 million or $0.92/BOE for the same periods in 2013. The increase from the prior year was related to higher
U.S. production as well as costs associated with securing U.S. pipeline capacity.
Netbacks
The following tables outline our crude oil and natural gas netbacks for the three and nine months ended September 30, 2014 and 2013. 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 September 30, 2014
|
| Netbacks by Property Type |
|
|
Crude Oil |
|
|
Natural Gas |
|
|
Total |
|
|
|
| Average Daily Production |
|
|
45,263 BOE/day |
|
|
352,632 Mcfe/day |
|
|
104,035 BOE/day |
|
|
|
| Netback(1) $ per BOE or Mcfe |
|
|
(per BOE |
) |
|
(per Mcfe |
) |
|
(per BOE |
) |
|
|
| Oil and natural gas sales(2) |
|
$ |
80.15 |
|
$ |
3.32 |
|
$ |
46.13 |
|
|
| Royalties and production taxes |
|
|
(20.73 |
) |
|
(0.40 |
) |
|
(10.36 |
) |
|
| Cash operating costs |
|
|
(13.13 |
) |
|
(1.46 |
) |
|
(10.67 |
) |
|
|
| Netback before hedging |
|
$ |
46.29 |
|
$ |
1.46 |
|
$ |
25.10 |
|
|
|
| Cash gains/(losses) |
|
|
(1.01 |
) |
|
0.05 |
|
|
(0.26 |
) |
|
|
| Netback after hedging |
|
$ |
45.28 |
|
$ |
1.51 |
|
$ |
24.84 |
|
|
|
| Netback before hedging ($ millions) |
|
$ |
192.8 |
|
$ |
47.5 |
|
$ |
240.3 |
|
|
|
| Netback after hedging ($ millions) |
|
$ |
188.6 |
|
$ |
49.2 |
|
$ |
237.8 |
|
|
|
| |
|
Three months ended September 30, 2013
|
| Netbacks by Property Type |
|
|
Crude Oil |
|
|
Natural Gas |
|
|
Total |
|
|
|
| Average Daily Production |
|
|
43,670 BOE/day |
|
|
264,354 Mcfe/day |
|
|
87,729 BOE/day |
|
|
|
| Netback(1) $ per BOE or Mcfe |
|
|
(per BOE |
) |
|
(per Mcfe |
) |
|
(per BOE |
) |
|
|
| Oil and natural gas sales(2) |
|
$ |
88.44 |
|
$ |
3.18 |
|
$ |
53.61 |
|
|
| Royalties and production taxes |
|
|
(20.74 |
) |
|
(0.53 |
) |
|
(11.91 |
) |
|
| Cash operating costs |
|
|
(12.26 |
) |
|
(1.49 |
) |
|
(10.58 |
) |
|
|
| Netback before hedging |
|
$ |
55.44 |
|
$ |
1.16 |
|
$ |
31.12 |
|
|
|
| Cash gains/(losses) |
|
|
(3.20 |
) |
|
0.10 |
|
|
(1.30 |
) |
|
|
| Netback after hedging |
|
$ |
52.24 |
|
$ |
1.26 |
|
$ |
29.82 |
|
|
|
| Netback before hedging ($ millions) |
|
$ |
222.7 |
|
$ |
28.5 |
|
$ |
251.2 |
|
|
|
| Netback after hedging ($ millions) |
|
$ |
209.9 |
|
$ |
30.8 |
|
$ |
240.6 |
|
|
|
ENERPLUS 2014 Q3
REPORT 13
| |
|
Nine months ended September 30, 2014
|
| Netbacks by Property Type |
|
|
Crude Oil |
|
|
Natural Gas |
|
|
Total |
|
|
|
| Average Daily Production |
|
|
44,317 BOE/day |
|
|
347,898 Mcfe/day |
|
|
102,300 BOE/day |
|
|
|
| Netback(1) $ per BOE or Mcfe |
|
|
(per BOE |
) |
|
(per Mcfe |
) |
|
(per BOE |
) |
|
|
| Oil and natural gas sales(2) |
|
$ |
84.18 |
|
$ |
4.17 |
|
$ |
50.66 |
|
|
| Royalties and production taxes |
|
|
(21.08 |
) |
|
(0.64 |
) |
|
(11.31 |
) |
|
| Cash operating costs |
|
|
(12.78 |
) |
|
(1.39 |
) |
|
(10.28 |
) |
|
|
| Netback before hedging |
|
$ |
50.32 |
|
$ |
2.14 |
|
$ |
29.07 |
|
|
|
| Cash gains/(losses) |
|
|
(2.99 |
) |
|
(0.07 |
) |
|
(1.52 |
) |
|
|
| Netback after hedging |
|
$ |
47.33 |
|
$ |
2.07 |
|
$ |
27.55 |
|
|
|
| Netback before hedging ($ millions) |
|
$ |
608.9 |
|
$ |
203.2 |
|
$ |
812.1 |
|
|
|
| Netback after hedging ($ millions) |
|
$ |
572.7 |
|
$ |
197.0 |
|
$ |
769.7 |
|
|
|
| |
|
Nine months ended September 30, 2013
|
| Netbacks by Property Type |
|
|
Crude Oil |
|
|
Natural Gas |
|
|
Total |
|
|
|
| Average Daily Production |
|
|
43,447 BOE/day |
|
|
269,226 Mcfe/day |
|
|
88,318 BOE/day |
|
|
|
| Netback(1) $ per BOE or Mcfe |
|
|
(per BOE |
) |
|
(per Mcfe |
) |
|
(per BOE |
) |
|
|
| Oil and natural gas sales(2) |
|
$ |
78.41 |
|
$ |
3.64 |
|
$ |
49.67 |
|
|
| Royalties and production taxes |
|
|
(18.37 |
) |
|
(0.47 |
) |
|
(10.46 |
) |
|
| Cash operating costs |
|
|
(12.25 |
) |
|
(1.47 |
) |
|
(10.52 |
) |
|
|
| Netback before hedging |
|
$ |
47.79 |
|
$ |
1.70 |
|
$ |
28.69 |
|
|
|
| Cash gains/(losses) |
|
|
0.76 |
|
|
0.02 |
|
|
0.42 |
|
|
|
| Netback after hedging |
|
$ |
48.55 |
|
$ |
1.72 |
|
$ |
29.11 |
|
|
|
| Netback before hedging ($ millions) |
|
$ |
566.8 |
|
$ |
125.0 |
|
$ |
691.8 |
|
|
|
| Netback after hedging ($ millions) |
|
$ |
575.8 |
|
$ |
126.1 |
|
$ |
701.9 |
|
|
|
- (1)
- See
"Non-GAAP Measures" in this MD&A.
- (2)
- Net
of transportation costs.
Our crude oil properties accounted for 75% of our corporate netback before hedging for the year to date compared to 82% for the same period in 2013. Crude oil
netbacks per BOE before hedging decreased during the three months ended September 30, 2014 compared to the same period in 2013 primarily due to lower realized crude oil prices. For the
nine months ended September 30, 2014 average realized crude oil prices were higher than the same period in 2013 which resulted in higher crude oil netbacks before hedging compared to the
previous year. Natural gas netbacks per Mcfe before hedging increased for the three and nine months ended compared to the same period last year primarily due to the increase in realized natural gas
prices from 2013.
14 ENERPLUS 2014 Q3
REPORT
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. SBC charges are dependent on our share price and can fluctuate from period to period.
| |
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
| ($ millions) |
|
|
2014 |
|
|
|
|
2013 |
|
|
|
|
2014 |
|
|
|
|
2013 |
|
|
|
|
|
|
|
|
|
| Cash: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| G&A expense(1) |
|
$ |
18.9 |
|
|
|
$ |
20.0 |
|
|
|
$ |
58.1 |
|
|
|
$ |
63.5 |
|
|
| SBC expense/(recovery) |
|
|
(5.2 |
) |
|
|
|
4.9 |
|
|
|
|
12.3 |
|
|
|
|
14.1 |
|
|
Non-Cash: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| SBC |
|
|
3.4 |
|
|
|
|
1.7 |
|
|
|
|
9.9 |
|
|
|
|
7.2 |
|
|
| SBC – equity swap loss/(gain) |
|
|
5.8 |
|
|
|
|
(1.5 |
) |
|
|
|
(0.1 |
) |
|
|
|
(3.8 |
) |
|
|
|
|
|
|
|
|
| Total G&A expenses |
|
$ |
22.9 |
|
|
|
$ |
25.1 |
|
|
|
$ |
80.2 |
|
|
|
$ |
81.0 |
|
|
|
|
|
|
|
|
|
| |
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
| (Per BOE) |
|
|
2014 |
|
|
|
|
2013 |
|
|
|
|
2014 |
|
|
|
2013 |
|
|
|
|
|
|
|
|
|
| Cash: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| G&A expense(1) |
|
$ |
1.97 |
|
|
|
$ |
2.48 |
|
|
|
$ |
2.08 |
|
|
$ |
2.63 |
|
|
| SBC expense/(recovery) |
|
|
(0.54 |
) |
|
|
|
0.60 |
|
|
|
|
0.44 |
|
|
|
0.58 |
|
|
Non-Cash: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| SBC |
|
|
0.36 |
|
|
|
|
0.21 |
|
|
|
|
0.35 |
|
|
|
0.30 |
|
|
| SBC – equity swap loss/(gain) |
|
|
0.61 |
|
|
|
|
(0.18 |
) |
|
|
|
– |
|
|
|
(0.16 |
) |
|
|
|
|
|
|
|
|
| Total G&A expenses |
|
$ |
2.40 |
|
|
|
$ |
3.11 |
|
|
|
$ |
2.87 |
|
|
$ |
3.35 |
|
|
|
|
|
|
|
|
|
- (1)
- Excluding
SBC.
Cash G&A expenses during the third quarter were $18.9 million or $1.97/BOE compared to $20.0 million or $2.48/BOE in the third quarter of 2013.
For the nine months ended September 30, 2014 cash G&A expenses were $58.1 million or $2.08/BOE compared to $63.5 million or $2.63/BOE for the same period in 2013. The
decrease during 2014 was partially due to one-time charges recorded in the prior year associated with the departure of personnel, while higher production volumes in 2014 also contributed to a decrease
in our reported G&A on a per BOE basis. We are maintaining our cash G&A guidance at $2.30/BOE for the year.
Our
share price decreased by 21% during the quarter, reducing our cash SBC expense and resulting in a recovery of $5.2 million or $0.54/BOE compared to a charge of $4.9 million or
$0.60/BOE during the third quarter of 2013. For the nine months ended September 30, 2014 cash SBC expense was $12.3 million or $0.44/BOE compared to $14.1 million or
$0.58/BOE for the same period in the prior year.
We
have hedged a portion of the outstanding cash settled units under our LTI plans at an average price of $14.92/share. As a result of the decrease in our share price we recorded a non-cash
mark-to-market loss of $5.8 million for the quarter and a gain of $0.1 million for the nine months ended September 30, 2014.
Based
on our September 30, 2014 share price of $21.26 we have revised our 2014 guidance for cash SBC to $0.45/BOE from $0.60/BOE.
Interest Expense
| |
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
| ($ millions) |
|
|
2014 |
|
|
|
2013 |
|
|
|
2014 |
|
|
|
2013 |
|
|
|
|
|
|
|
|
| Interest on senior notes and bank facility |
|
$ |
14.9 |
|
|
$ |
14.7 |
|
|
$ |
45.5 |
|
|
$ |
43.1 |
|
| Non-cash interest expense |
|
|
0.3 |
|
|
|
0.4 |
|
|
|
1.4 |
|
|
|
1.2 |
|
|
|
|
|
|
|
|
| Total interest expense |
|
$ |
15.2 |
|
|
$ |
15.1 |
|
|
$ |
46.9 |
|
|
$ |
44.3 |
|
|
|
|
|
|
|
|
For the three and nine months ended September 30, 2014 we recorded total interest expense of $15.2 million and $46.9 million,
respectively, compared to $15.1 million and $44.3 million in the same periods in 2013.
ENERPLUS 2014 Q3
REPORT 15
Interest
expense increased marginally for the three and nine months ended September 30, 2014 compared to the same periods in 2013 mainly due to the impact of a weaker Canadian dollar on
our U.S. dollar denominated interest payments.
At
September 30, 2014, after including our underlying derivatives, approximately 95% of our debt was based on fixed interest rates and 5% on floating interest rates, with weighted
average interest rates of 5.28% and 2.92%, respectively. The percentage of fixed rate debt has increased from prior periods as we closed our US$200.0 million senior notes offering on
September 3, 2014 and used the proceeds to pay down bank debt.
Foreign Exchange
| |
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
| ($ millions) |
|
|
2014 |
|
|
|
|
2013 |
|
|
|
|
2014 |
|
|
|
2013 |
|
|
|
|
|
|
|
|
|
| Realized loss/(gain) |
|
$ |
(2.6 |
) |
|
|
$ |
0.1 |
|
|
|
$ |
14.0 |
|
|
$ |
17.7 |
|
|
| Unrealized loss/(gain) |
|
|
33.1 |
|
|
|
|
(2.6 |
) |
|
|
|
10.7 |
|
|
|
(13.7 |
) |
|
|
|
|
|
|
|
|
| Total foreign exchange loss/(gain) |
|
$ |
30.5 |
|
|
|
$ |
(2.5 |
) |
|
|
$ |
24.7 |
|
|
$ |
4.0 |
|
|
|
|
|
|
|
|
|
We recorded a net foreign exchange loss of $30.5 million during the third quarter and a loss of $24.7 million year to date, compared to a net gain
of $2.5 million and a net loss of $4.0 million, respectively, during the same periods in 2013.
Realized
gains during the quarter resulted from foreign exchange gains on day-to-day transactions denominated in foreign currencies. Unrealized foreign exchange losses related to the translation of
our U.S. dollar denominated debt and working capital.
Capital Investment and Dispositions
| |
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
| ($ millions) |
|
|
2014 |
|
|
|
|
2013 |
|
|
|
|
2014 |
|
|
|
|
2013 |
|
|
|
|
|
|
|
|
|
| Capital spending |
|
$ |
207.8 |
|
|
|
$ |
145.8 |
|
|
|
$ |
630.0 |
|
|
|
$ |
458.4 |
|
|
| Office capital |
|
|
1.4 |
|
|
|
|
1.2 |
|
|
|
|
3.0 |
|
|
|
|
3.4 |
|
|
|
|
|
|
|
|
|
| Sub-total |
|
$ |
209.2 |
|
|
|
$ |
147.0 |
|
|
|
$ |
633.0 |
|
|
|
$ |
461.8 |
|
|
|
|
|
|
|
|
|
| Property and land acquisitions |
|
$ |
4.0 |
|
|
|
$ |
15.8 |
|
|
|
$ |
17.2 |
|
|
|
$ |
71.5 |
|
|
| Property dispositions |
|
|
(68.9 |
) |
|
|
|
(124.5 |
) |
|
|
|
(185.6 |
) |
|
|
|
(197.1 |
) |
|
|
|
|
|
|
|
|
| Sub-total |
|
$ |
(64.9 |
) |
|
|
$ |
(108.7 |
) |
|
|
$ |
(168.4 |
) |
|
|
$ |
(125.6 |
) |
|
|
|
|
|
|
|
|
| Total net capital investment |
|
$ |
144.3 |
|
|
|
$ |
38.3 |
|
|
|
$ |
464.6 |
|
|
|
$ |
336.2 |
|
|
|
|
|
|
|
|
|
Capital spending for the third quarter totaled $207.8 million compared to $145.8 million during the same period in 2013. We continue to focus our
spending on our core development areas with 64% directed towards crude oil development. Crude oil spending for the quarter included $95.7 million at Fort Berthold and $37.0 million on
our Canadian waterflood properties. Natural gas spending included $56.6 million in the Marcellus and $16.1 million on our Deep Basin assets.
During
the quarter we had minor property and land acquisitions totaling $4.0 million, of which $2.0 million related to undeveloped land acquisitions in our Deep Basin properties and
$2.0 million related to additional land interests around our existing Marcellus acreage. In the third quarter of 2013 we spent $15.8 million which included $6.4 million for
additional land interests in the Deep Basin, $7.5 million in Fort Berthold and $1.9 million in the Marcellus.
On
September 30, 2014, we divested of $69.0 million of non-core natural gas properties in the Deep Basin area with production of approximately 1,900 BOE/day. During the
quarter, we also entered into an agreement to sell additional non-core Canadian natural gas
properties with production of approximately 1,200 BOE/day for net proceeds of approximately $22.0 million. This transaction closed in early November. Combined, we expect to realize
approximately $30,000 per flowing barrel on these non-core gas divestments.
16 ENERPLUS 2014 Q3
REPORT
Property
dispositions during the third quarter of 2013 totaled $124.5 million which included non-core Canadian properties primarily in Saskatchewan and Alberta for proceeds of
$89.3 million as well as certain facilities in Fort Berthold for proceeds of $35.2 million.
Our
successful non-core divestments have allowed us to increase our capital spending program and redeploy a portion of the proceeds to accelerate our 2015 capital spending programs in Fort Berthold
and the Wilrich. As a result, we have increased our capital spending guidance for the year to $830 million from $800 million.
Depletion, Depreciation, Amortization and Accretion ("DDA&A")
| |
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
| ($ millions, except per BOE amounts) |
|
|
2014 |
|
|
|
2013 |
|
|
|
2014 |
|
|
|
2013 |
|
|
|
|
|
|
|
|
| DDA&A expense |
|
$ |
159.7 |
|
|
$ |
163.3 |
|
|
$ |
440.5 |
|
|
$ |
470.1 |
|
| Per BOE |
|
$ |
16.68 |
|
|
$ |
20.24 |
|
|
$ |
15.77 |
|
|
$ |
19.50 |
|
|
|
|
|
|
|
|
DDA&A of property, plant and equipment ("PP&E") is recognized using the unit-of-production method based on proved reserves. For the three and nine months ended
September 30, 2014 DDA&A decreased to $159.7 million and $440.5 million, respectively, compared to $163.3 million and $470.1 million during the same periods
in 2013. The decrease was primarily due to significant reserve additions for the year ended December 31, 2013 that lowered our depletion rate for 2014.
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 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 $286.7 million at September 30, 2014 compared to $291.8 million at
December 31, 2013.
Income Taxes
| |
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
| ($ millions) |
|
|
2014 |
|
|
|
2013 |
|
|
|
|
2014 |
|
|
|
2013 |
|
|
|
|
|
|
|
|
| Current tax expense |
|
$ |
– |
|
|
$ |
5.2 |
|
|
|
$ |
11.4 |
|
|
$ |
7.9 |
|
| Deferred tax expense/(recovery) |
|
|
36.9 |
|
|
|
(6.6 |
) |
|
|
|
74.1 |
|
|
|
15.6 |
|
|
|
|
|
|
|
|
| Total tax expense/(recovery) |
|
$ |
36.9 |
|
|
$ |
(1.4 |
) |
|
|
$ |
85.5 |
|
|
$ |
23.5 |
|
|
|
|
|
|
|
|
For the three and nine months ended September 30, 2014, we recorded a total tax expense of $36.9 million and $85.5 million
respectively, compared to a $1.4 million tax recovery and a $23.5 million tax expense in the same periods in 2013. The increase in our total tax expense is due to higher net income
in 2014.
Our
current tax is comprised mainly of Alternative Minimum Tax ("AMT") payable with respect to our U.S. subsidiary. We expect to recover AMT in future years as an offset to regular
U.S. income taxes otherwise payable. Given the decrease in commodity prices and resulting decrease in forecasted net income for the year, a current tax accrual was not needed during the third
quarter. Based on current commodity prices and assuming no acquisitions and divestiture activity, we expect to pay U.S. cash taxes of approximately 2% of our U.S. funds flow in 2014, and
approximately 3% – 5% from 2015 to 2018. We currently do not expect to pay material cash taxes in Canada until after 2018.
ENERPLUS 2014 Q3
REPORT 17
SELECTED CANADIAN AND U.S. FINANCIAL RESULTS
The following table provides a geographical split of key operating and financial results for the three and nine months ended September 30, 2014
and 2013.
| |
|
Three months ended September 30, 2014
|
|
Three months ended September 30, 2013
|
| (millions, except per unit amounts) |
|
|
Canada |
|
|
U.S. |
|
|
Total |
|
|
|
|
Canada |
|
|
U.S. |
|
|
Total |
|
|
|
|
|
| Average Daily Production Volumes(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Crude oil (bbls/day) |
|
|
16,837 |
|
|
23,495 |
|
|
40,332 |
|
|
|
|
17,246 |
|
|
21,637 |
|
|
38,883 |
|
|
| |
Natural gas liquids (bbls/day) |
|
|
2,578 |
|
|
1,291 |
|
|
3,869 |
|
|
|
|
2,265 |
|
|
720 |
|
|
2,985 |
|
|
| |
Natural gas (Mcf/day) |
|
|
154,855 |
|
|
204,152 |
|
|
359,007 |
|
|
|
|
174,169 |
|
|
100,995 |
|
|
275,164 |
|
|
| |
|
|
|
|
| |
Total average daily production (BOE/day) |
|
|
45,224 |
|
|
58,811 |
|
|
104,035 |
|
|
|
|
48,539 |
|
|
39,190 |
|
|
87,729 |
|
|
| |
|
|
|
|
| Pricing(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Crude oil (per bbl) |
|
$ |
82.11 |
|
$ |
89.63 |
|
$ |
86.49 |
|
|
|
$ |
94.12 |
|
$ |
98.04 |
|
$ |
96.30 |
|
|
| |
Natural gas liquids (per bbl) |
|
|
46.28 |
|
|
42.01 |
|
|
44.85 |
|
|
|
|
58.64 |
|
|
22.31 |
|
|
49.88 |
|
|
| |
Natural gas (per Mcf) |
|
|
3.82 |
|
|
2.77 |
|
|
3.22 |
|
|
|
|
2.62 |
|
|
3.55 |
|
|
2.96 |
|
|
Capital Expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Capital spending |
|
$ |
55.2 |
|
$ |
152.6 |
|
$ |
207.8 |
|
|
|
$ |
57.0 |
|
$ |
88.8 |
|
$ |
145.8 |
|
|
| |
Acquisitions |
|
|
2.0 |
|
|
2.0 |
|
|
3.9 |
|
|
|
|
6.4 |
|
|
9.4 |
|
|
15.8 |
|
|
| |
Dispositions |
|
|
(68.9 |
) |
|
0.0 |
|
|
(68.9 |
) |
|
|
|
(89.3 |
) |
|
(35.2 |
) |
|
(124.5 |
) |
|
Netback Before Hedging |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Oil and natural gas sales |
|
$ |
199.3 |
|
$ |
256.9 |
|
$ |
456.2 |
|
|
|
$ |
209.6 |
|
$ |
231.9 |
|
$ |
441.5 |
|
|
| |
Royalties |
|
|
(27.1 |
) |
|
(50.8 |
) |
|
(77.9 |
) |
|
|
|
(31.6 |
) |
|
(44.5 |
) |
|
(76.1 |
) |
|
| |
Cash operating expense |
|
|
(64.7 |
) |
|
(37.3 |
) |
|
(102.0 |
) |
|
|
|
(62.2 |
) |
|
(23.2 |
) |
|
(85.4 |
) |
|
| |
Production taxes |
|
|
(2.5 |
) |
|
(18.8 |
) |
|
(21.3 |
) |
|
|
|
(1.4 |
) |
|
(18.6 |
) |
|
(20.0 |
) |
|
| |
Transportation expense |
|
|
(6.2 |
) |
|
(8.5 |
) |
|
(14.7 |
) |
|
|
|
(5.5 |
) |
|
(3.3 |
) |
|
(8.8 |
) |
|
| |
|
|
|
|
| |
Netback before hedging |
|
$ |
98.8 |
|
$ |
141.5 |
|
$ |
240.3 |
|
|
|
$ |
108.9 |
|
$ |
142.3 |
|
$ |
251.2 |
|
|
| |
|
|
|
|
Other Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Commodity derivative instruments loss/(gain) |
|
$ |
(91.3 |
) |
$ |
– |
|
$ |
(91.3 |
) |
|
|
$ |
55.7 |
|
$ |
– |
|
$ |
55.7 |
|
|
| |
General and administrative expense |
|
|
19.8 |
|
|
3.1 |
|
|
22.9 |
|
|
|
|
20.7 |
|
|
4.4 |
|
|
25.1 |
|
|
| |
Current income tax expense/(recovery) |
|
|
(0.1 |
) |
|
0.1 |
|
|
– |
|
|
|
|
(0.3 |
) |
|
5.5 |
|
|
5.2 |
|
|
|
|
|
- (1)
- Company
interest volumes.
- (2)
- Net
of transportation costs, but before royalties and the effects of commodity derivative instruments.
18 ENERPLUS 2014 Q3
REPORT
| |
|
Nine months ended September 30, 2014
|
|
Nine months ended September 30, 2013
|
| (millions, except per unit amounts) |
|
|
Canada |
|
|
U.S. |
|
|
Total |
|
|
|
|
Canada |
|
|
U.S. |
|
|
Total |
|
|
|
|
|
| Average Daily Production Volumes(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Crude oil (bbls/day) |
|
|
16,867 |
|
|
22,461 |
|
|
39,328 |
|
|
|
|
18,253 |
|
|
20,173 |
|
|
38,426 |
|
|
| |
Natural gas liquids (bbls/day) |
|
|
2,531 |
|
|
1,060 |
|
|
3,591 |
|
|
|
|
2,782 |
|
|
575 |
|
|
3,357 |
|
|
| |
Natural gas (Mcf/day) |
|
|
154,306 |
|
|
201,982 |
|
|
356,288 |
|
|
|
|
179,503 |
|
|
99,709 |
|
|
279,212 |
|
|
| |
|
|
|
|
| |
Total average daily production (BOE/day) |
|
|
45,116 |
|
|
57,184 |
|
|
102,300 |
|
|
|
|
50,952 |
|
|
37,366 |
|
|
88,318 |
|
|
| |
|
|
|
|
| Pricing(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Crude oil (per bbl) |
|
$ |
87.05 |
|
$ |
93.81 |
|
$ |
90.91 |
|
|
|
$ |
80.02 |
|
$ |
91.50 |
|
$ |
86.05 |
|
|
| |
Natural gas liquids (per bbl) |
|
|
57.37 |
|
|
42.60 |
|
|
53.01 |
|
|
|
|
56.59 |
|
|
26.77 |
|
|
51.48 |
|
|
| |
Natural gas (per Mcf) |
|
|
4.41 |
|
|
3.76 |
|
|
4.04 |
|
|
|
|
2.97 |
|
|
3.78 |
|
|
3.26 |
|
|
Capital Expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Capital spending |
|
$ |
243.2 |
|
$ |
386.8 |
|
$ |
630.0 |
|
|
|
$ |
184.4 |
|
$ |
274.0 |
|
$ |
458.4 |
|
|
| |
Acquisitions |
|
|
2.0 |
|
|
15.2 |
|
|
17.2 |
|
|
|
|
44.0 |
|
|
27.5 |
|
|
71.5 |
|
|
| |
Dispositions |
|
|
(136.6 |
) |
|
(49.0 |
) |
|
(185.6 |
) |
|
|
|
(154.5 |
) |
|
(42.6 |
) |
|
(197.1 |
) |
|
Netback Before Hedging |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Oil and natural gas sales |
|
$ |
645.3 |
|
$ |
810.5 |
|
$ |
1,455.8 |
|
|
|
$ |
606.7 |
|
$ |
613.1 |
|
$ |
1,219.8 |
|
|
| |
Royalties |
|
|
(96.2 |
) |
|
(158.6 |
) |
|
(254.8 |
) |
|
|
|
(82.1 |
) |
|
(117.6 |
) |
|
(199.7 |
) |
|
| |
Cash operating expense |
|
|
(189.1 |
) |
|
(97.8 |
) |
|
(286.9 |
) |
|
|
|
(193.6 |
) |
|
(60.0 |
) |
|
(253.6 |
) |
|
| |
Production taxes |
|
|
(6.4 |
) |
|
(54.7 |
) |
|
(61.1 |
) |
|
|
|
(7.8 |
) |
|
(44.7 |
) |
|
(52.5 |
) |
|
| |
Transportation expense |
|
|
(17.9 |
) |
|
(23.0 |
) |
|
(40.9 |
) |
|
|
|
(17.3 |
) |
|
(4.9 |
) |
|
(22.2 |
) |
|
| |
|
|
|
|
| |
Netback before hedging |
|
$ |
335.7 |
|
$ |
476.4 |
|
$ |
812.1 |
|
|
|
$ |
305.9 |
|
$ |
385.9 |
|
$ |
691.8 |
|
|
| |
|
|
|
|
Other Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Commodity derivative instruments loss/(gain) |
|
$ |
(14.6 |
) |
$ |
– |
|
$ |
(14.6 |
) |
|
|
$ |
52.1 |
|
$ |
– |
|
$ |
52.1 |
|
|
| |
General and administrative expense |
|
|
65.7 |
|
|
14.5 |
|
|
80.2 |
|
|
|
|
69.4 |
|
|
11.6 |
|
|
81.0 |
|
|
| |
Current income tax expense/(recovery) |
|
|
(0.5 |
) |
|
11.9 |
|
|
11.4 |
|
|
|
|
(0.3 |
) |
|
8.2 |
|
|
7.9 |
|
|
|
|
|
- (1)
- Company
interest volumes.
- (2)
- Net
of transportation costs, but before royalties and the effects of commodity derivative instruments.
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 |
|
|
|
| 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 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 |
|
$ |
1,200.9 |
|
$ |
147.4 |
|
$ |
0.73 |
|
$ |
0.70 |
|
|
|
| 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 |
|
$ |
1,352.5 |
|
$ |
48.0 |
|
$ |
0.24 |
|
$ |
0.24 |
|
|
|
| 2012 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Fourth Quarter |
|
$ |
310.2 |
|
$ |
34.6 |
|
$ |
0.18 |
|
$ |
0.18 |
|
|
| Third Quarter |
|
|
279.3 |
|
|
(88.6 |
) |
|
(0.45 |
) |
|
(0.45 |
) |
|
| Second Quarter |
|
|
274.3 |
|
|
(41.9 |
) |
|
(0.21 |
) |
|
(0.21 |
) |
|
| First Quarter |
|
|
289.5 |
|
|
(174.8 |
) |
|
(0.92 |
) |
|
(0.92 |
) |
|
|
|
|
|
|
|
|
|
|
| Total |
|
$ |
1,153.3 |
|
$ |
(270.7 |
) |
$ |
(1.38 |
) |
$ |
(1.38 |
) |
|
|
ENERPLUS 2014 Q3
REPORT 19
Oil and gas sales, net of royalties, increased in 2014 compared to 2013 primarily due to increased production and higher realized commodity prices. In the third quarter of 2014 lower realized
commodity prices resulted in lower oil and gas sales for the quarter. Throughout 2013 and 2012 oil and gas sales, net of royalties, generally increased with higher production although volatile
commodity prices caused some fluctuations.
Net
income for 2014 benefited from higher production and generally higher realized prices offset by fluctuating risk management costs and foreign exchange gains and losses. Net income for 2013 and
2012 was impacted by fluctuating risk management costs, asset impairment charges and gains on marketable security divestments.
LIQUIDITY AND CAPITAL RESOURCES
We continued to maintain a strong balance sheet and ample liquidity through the third quarter. At September 30, 2014 we had a conservative
trailing 12 month debt to cash flow ratio of 1.3x. On September 3, 2014 we closed a private placement of US$200.0 million of senior unsecured notes, with a twelve year
amortizing term, a ten year average life and a fixed interest rate of 3.79%. The proceeds were used to repay our short-term, floating interest rate bank debt, and as a result we had
$942.5 million of undrawn capacity on our $1 billion credit facility at quarter end.
Our
adjusted payout ratio, calculated as dividends (net of SDP proceeds) plus capital and office spending, divided by funds flow, increased to 122% and 120% for the three and nine months ended
September 30, 2014, respectively, compared to 97% and 103% for the same periods in 2013. Although funds flow increased by 8% and 13% for the three and nine months ended
September 30, 2014, respectively, compared to the same periods in 2013, we saw a proportionately larger increase in our capital spending program and a decrease in our SDP participation
over the same period. Despite the increase in adjusted payout ratio, the health of our balance sheet has been maintained in part due to the success of our non-core asset divestment program.
We
continue to hedge a portion of our commodity price risk and expect our risk management program to provide funds flow protection in the near term. At September 30, 2014 we had
approximately 64% of our anticipated remaining 2014 crude oil production hedged at a price of $95.29, and approximately 38% of our anticipated 2015 oil production hedged at $93.68.
Total
debt net of cash at September 30, 2014 was $1,091.1 million compared to $1,022.3 million at December 31, 2013. Total debt was comprised of
$57.5 million of bank indebtedness and $1,035.7 million of senior notes, less $2.1 million in cash. A significant portion of our senior notes are denominated in
U.S. dollars and given the weakening Canadian dollar our total reported debt has increased. Our working capital deficiency, excluding cash and current deferred financial and tax assets and
credits, increased slightly during the quarter to $252.5 million from $251.2 million in the second quarter. We expect to finance our working capital deficit through funds flow and our
bank credit facility.
Our
key leverage ratios are detailed below:
| Financial Leverage and Coverage |
|
September 30, 2014 |
|
|
December 31, 2013 |
|
|
|
|
| Long-term debt to funds flow (trailing 12-month)(1) |
|
1.3 x |
|
|
1.4 x |
|
| Funds flow to interest expense (trailing 12-month)(2) |
|
14.0 x |
|
|
13.3 x |
|
| Long-term debt to long-term debt plus equity(1) |
|
35% |
|
|
35% |
|
|
|
|
- (1)
- Long-term
debt is measured net of cash and includes the current portion of the senior notes.
- (2)
- Interest
expense excluding non-cash items.
At September 30, 2014 we were in compliance with all covenants under our bank credit facility and senior notes. Our bank credit facility and
senior note purchase agreements have been filed as material documents on our SEDAR profile at www.sedar.com and on the EDGAR website at www.sec.gov.
20 ENERPLUS 2014 Q3
REPORT
Dividends
| |
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
| ($ millions, except per share amounts) |
|
|
2014 |
|
|
|
2013 |
|
|
|
2014 |
|
|
|
2013 |
|
|
|
|
|
|
|
|
| Cash dividends |
|
$ |
51.1 |
|
|
$ |
42.4 |
|
|
$ |
143.8 |
|
|
$ |
128.7 |
|
| Stock dividend plan |
|
|
4.3 |
|
|
|
12.0 |
|
|
|
21.8 |
|
|
|
33.5 |
|
|
|
|
|
|
|
|
| Total dividends to shareholders |
|
$ |
55.4 |
|
|
$ |
54.4 |
|
|
$ |
165.6 |
|
|
$ |
162.2 |
|
|
|
|
|
|
|
|
| Per weighted average share (Basic) |
|
$ |
0.27 |
|
|
$ |
0.27 |
|
|
$ |
0.81 |
|
|
$ |
0.81 |
|
|
|
|
|
|
|
|
During the three and nine months ended September 30, 2014 we maintained our monthly $0.09/share dividend, resulting in dividends to shareholders
of $55.4 million ($0.27/share) and $165.6 million ($0.81/share), respectively, compared to $54.5 million ($0.27/share) and $162.2 million ($0.81/share) for the same periods
in 2013. For the first nine months of 2014, dividend payments including SDP amounted to 26% of our funds flow of $646.5 million. We continue to monitor our dividend levels with respect to
anticipated funds flow, debt levels, capital spending plans and capital market conditions and do not anticipate any changes to our dividend at this time.
Effective
September 19, 2014 the Board of Directors elected to suspend the SDP in an effort to eliminate the dilution associated with the issuance of shares through the plan. Effective
with the October 2014 dividend, all dividends will be paid in cash on or about the 15th day of the month, approximately five days earlier than previously. All record dates and
ex-dividend dates will also be adjusted accordingly with future record dates being on or about the last business day of the previous calendar month.
Commitments
During the third quarter we acquired additional transportation commitments for 11.1 MMcf/day on various pipelines in the Marcellus region. These
contracts relate to the additional working interest acquisition at the end of 2013 and have various terms extending out to 2020, 2028 and 2033 and comprise a total commitment of approximately
US$54.3 million.
Shareholders' Capital
| |
|
Nine months ended September 30,
|
| |
|
|
2014 |
|
|
|
2013 |
|
|
|
|
| Share capital ($ millions) |
|
$ |
3,115.5 |
|
|
$ |
3,046.1 |
|
Common shares outstanding (thousands) |
|
|
205,423 |
|
|
|
201,873 |
|
| Weighted average shares outstanding – basic (thousands) |
|
|
204,174 |
|
|
|
200,002 |
|
| Weighted average shares outstanding – diluted (thousands) |
|
|
207,970 |
|
|
|
200,415 |
|
|
|
|
During the third quarter of 2014, a total of 655,000 shares (2013 – 1,605,000) and $12.2 million of
additional equity (2013 – $26.9 million) was issued pursuant to the SDP and the stock option plan. For the nine months ended
September 30, 2014, a total of 2,665,000 shares (2013 – 3,189,000) and $48.9 million of additional equity
(2013 – $48.4 million) was issued pursuant to the SDP and the stock option plan.
At
September 30, 2014 we had 205,423,000 shares outstanding (2013 – 201,874,000) and at November 6, 2014 we had 205,434,022
shares outstanding.
ENERPLUS 2014 Q3
REPORT 21
2014 GUIDANCE
A summary of our 2014 guidance is below.
| Summary of 2014 Expectations |
|
Target |
|
|
| Average annual production |
|
102,000 – 104,000 BOE/day (from 100,000 – 104,000 BOE/day) |
|
| Production mix (volumes) |
|
44,000 BOE/day crude oil and natural gas liquids
58,000-60,000 BOE/day natural gas (from 56,000-60,000 BOE/day) |
|
| Capital spending |
|
$830 million (from $800 million) |
|
| Average royalty rate (% of gross sales, net of transportation) |
|
23% |
|
| Operating costs |
|
$10.25/BOE (from $10.10/BOE) |
|
| Cash G&A expenses |
|
$2.30/BOE |
|
| Cash share-based compensation expenses |
|
$0.45/BOE (from $0.60/BOE) |
|
| U.S. Cash taxes (% of U.S. funds flow) |
|
2% (from 3%-5%) |
|
|
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 September 30, 2014, 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
July 1, 2014 and ending September 30, 2014 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.
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 2014 and 2015 average production volumes and the anticipated production mix; the proportion of our
anticipated oil and gas production that is hedged; the results from our drilling program and the timing of related production; future oil and natural gas prices and differentials and our commodity
risk management programs; 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 costs; capital spending levels in 2014 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 U.S. cash taxes; deferred income taxes, our tax pools and the time at which we may
pay Canadian cash taxes and regular U.S. 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; the amount and timing of future cash dividends that we may pay to our shareholders; and future dispositions, including expected
proceeds therefrom and production volumes associated therewith.
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; 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; commodity price and cost assumptions; the continued
availability of adequate debt and/or equity financing and funds flow to fund our capital, operating and working capital requirements,
22 ENERPLUS 2014 Q3
REPORT
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. 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
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; 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; a failure to complete planned asset dispositions on the terms anticipated or at
all; 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 this MD&A and in our other public filings).
The forward-looking information contained in this MD&A speaks only as of the date of this MD&A, and we do not assume any obligation to publicly update or revise such
forward-looking information to reflect new events or circumstances, except as may be required pursuant to applicable laws.
ENERPLUS 2014 Q3
REPORT 23
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Exhibit 99.2
STATEMENTS
Condensed Consolidated Balance Sheets
| (CDN$ thousands) unaudited |
|
Note |
|
|
|
September 30, 2014 |
|
|
|
|
December 31, 2013 |
|
|
|
|
|
| Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Current assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Cash |
|
|
|
|
$ |
2,104 |
|
|
|
$ |
2,990 |
|
|
| |
Accounts receivable |
|
3 |
|
|
|
197,576 |
|
|
|
|
165,091 |
|
|
| |
Deferred income tax asset |
|
|
|
|
|
– |
|
|
|
|
48,476 |
|
|
| |
Deferred financial assets |
|
15 |
|
|
|
40,906 |
|
|
|
|
9,198 |
|
|
| |
Other current assets |
|
|
|
|
|
12,651 |
|
|
|
|
7,641 |
|
|
|
|
|
| |
|
|
|
|
|
253,237 |
|
|
|
|
233,396 |
|
|
|
|
|
| Property, plant and equipment |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Oil and natural gas properties (full cost method) |
|
4 |
|
|
|
2,528,493 |
|
|
|
|
2,420,144 |
|
|
| |
Other capital assets, net |
|
4 |
|
|
|
18,862 |
|
|
|
|
21,210 |
|
|
|
|
|
| |
Property, plant and equipment |
|
|
|
|
|
2,547,355 |
|
|
|
|
2,441,354 |
|
|
|
|
|
| Goodwill |
|
|
|
|
|
618,521 |
|
|
|
|
609,975 |
|
|
| Deferred income tax asset |
|
|
|
|
|
356,955 |
|
|
|
|
364,411 |
|
|
| Deferred financial assets |
|
15 |
|
|
|
32,288 |
|
|
|
|
19,274 |
|
|
| Marketable securities |
|
5 |
|
|
|
– |
|
|
|
|
13,389 |
|
|
|
|
|
| Total Assets |
|
|
|
|
$ |
3,808,356 |
|
|
|
$ |
3,681,799 |
|
|
|
|
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
| Current liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Accounts payable |
|
6 |
|
|
$ |
347,268 |
|
|
|
$ |
377,157 |
|
|
| |
Dividends payable |
|
|
|
|
|
18,488 |
|
|
|
|
18,250 |
|
|
| |
Current portion of long-term debt |
|
7 |
|
|
|
96,937 |
|
|
|
|
48,713 |
|
|
| |
Deferred income tax liability |
|
|
|
|
|
6,640 |
|
|
|
|
– |
|
|
| |
Deferred financial credits |
|
15 |
|
|
|
– |
|
|
|
|
37,031 |
|
|
|
|
|
| |
|
|
|
|
|
469,333 |
|
|
|
|
481,151 |
|
|
|
|
|
| Long-term debt |
|
7 |
|
|
|
996,277 |
|
|
|
|
976,585 |
|
|
| Asset retirement obligation |
|
8 |
|
|
|
286,748 |
|
|
|
|
291,761 |
|
|
|
|
|
| |
|
|
|
|
|
1,283,025 |
|
|
|
|
1,268,346 |
|
|
|
|
|
| Total Liabilities |
|
|
|
|
|
1,752,358 |
|
|
|
|
1,749,497 |
|
|
|
|
|
Shareholders' Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
Share capital – authorized unlimited common shares, no par value
Issued and outstanding: September 30, 2014 – 205 million shares
December 31, 2013 – 203 million shares |
|
14 |
|
|
|
3,115,527 |
|
|
|
|
3,061,839 |
|
|
| Paid-in capital |
|
14 |
|
|
|
43,522 |
|
|
|
|
38,398 |
|
|
| Accumulated deficit |
|
|
|
|
|
(1,135,401 |
) |
|
|
|
(1,117,238 |
) |
|
| Accumulated other comprehensive income/(loss) |
|
|
|
|
|
32,350 |
|
|
|
|
(50,697 |
) |
|
|
|
|
| |
|
|
|
|
|
2,055,998 |
|
|
|
|
1,932,302 |
|
|
|
|
|
| Total Liabilities & Equity |
|
|
|
|
$ |
3,808,356 |
|
|
|
$ |
3,681,799 |
|
|
|
|
|
Contingencies and Commitments |
|
16 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to the Condensed Consolidated Financial Statements
24 ENERPLUS 2014 Q3
REPORT
Condensed Consolidated Statements of Income/(Loss) and
Comprehensive Income/(Loss)
| |
|
|
|
|
Three months ended
September 30,
|
|
|
|
Nine months ended
September 30,
|
|
|
| (CDN$ thousands, except per share amounts) unaudited |
|
Note |
|
|
|
2014 |
|
|
|
|
2013 |
|
|
|
|
2014 |
|
|
|
|
2013 |
|
|
|
|
|
|
|
|
|
| Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Oil and natural gas sales, net of royalties |
|
9 |
|
|
$ |
378,332 |
|
|
|
$ |
365,391 |
|
|
|
$ |
1,200,997 |
|
|
|
$ |
1,020,096 |
|
|
| Commodity derivative instruments gain/(loss) |
|
15 |
|
|
|
91,268 |
|
|
|
|
(55,674 |
) |
|
|
|
14,602 |
|
|
|
|
(52,107 |
) |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
469,600 |
|
|
|
|
309,717 |
|
|
|
|
1,215,599 |
|
|
|
|
967,989 |
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Operating |
|
|
|
|
|
102,093 |
|
|
|
|
85,548 |
|
|
|
|
286,683 |
|
|
|
|
252,262 |
|
|
| Production taxes |
|
|
|
|
|
21,270 |
|
|
|
|
20,004 |
|
|
|
|
61,116 |
|
|
|
|
52,486 |
|
|
| Transportation |
|
|
|
|
|
14,667 |
|
|
|
|
8,830 |
|
|
|
|
40,915 |
|
|
|
|
22,259 |
|
|
| General and administrative |
|
10 |
|
|
|
22,937 |
|
|
|
|
25,114 |
|
|
|
|
80,240 |
|
|
|
|
80,989 |
|
|
| Depletion, depreciation, amortization and accretion |
|
|
|
|
|
159,658 |
|
|
|
|
163,339 |
|
|
|
|
440,494 |
|
|
|
|
470,088 |
|
|
| Interest |
|
11 |
|
|
|
15,175 |
|
|
|
|
15,084 |
|
|
|
|
46,876 |
|
|
|
|
44,321 |
|
|
| Foreign exchange (gain)/loss |
|
12 |
|
|
|
30,498 |
|
|
|
|
(2,509 |
) |
|
|
|
24,742 |
|
|
|
|
4,027 |
|
|
| Other expense/(income) |
|
|
|
|
|
(953 |
) |
|
|
|
(548 |
) |
|
|
|
1,599 |
|
|
|
|
(264 |
) |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
365,345 |
|
|
|
|
314,862 |
|
|
|
|
982,665 |
|
|
|
|
926,168 |
|
|
|
|
|
|
|
|
|
| Income/(Loss) Before Taxes |
|
|
|
|
|
104,255 |
|
|
|
|
(5,145 |
) |
|
|
|
232,934 |
|
|
|
|
41,821 |
|
|
| Current income tax expense/(recovery) |
|
13 |
|
|
|
(28 |
) |
|
|
|
5,235 |
|
|
|
|
11,447 |
|
|
|
|
7,943 |
|
|
| Deferred income tax expense/(recovery) |
|
13 |
|
|
|
36,853 |
|
|
|
|
(6,660 |
) |
|
|
|
74,063 |
|
|
|
|
15,528 |
|
|
|
|
|
|
|
|
|
| Net Income/(Loss) |
|
|
|
|
$ |
67,430 |
|
|
|
$ |
(3,720 |
) |
|
|
$ |
147,424 |
|
|
|
$ |
18,350 |
|
|
|
|
|
|
|
|
|
Other Comprehensive Income/(Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Changes due to marketable securities (net of tax) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Unrealized gain/(loss) |
|
|
|
|
|
– |
|
|
|
|
2,244 |
|
|
|
|
(145 |
) |
|
|
|
5,104 |
|
|
| |
Realized (gain)/loss reclassified to net income |
|
|
|
|
|
– |
|
|
|
|
(125 |
) |
|
|
|
2,503 |
|
|
|
|
(315 |
) |
|
| Change in cumulative translation adjustment |
|
|
|
|
|
78,459 |
|
|
|
|
(24,307 |
) |
|
|
|
80,689 |
|
|
|
|
34,336 |
|
|
|
|
|
|
|
|
|
| Other Comprehensive Income/(Loss) |
|
|
|
|
|
78,459 |
|
|
|
|
(22,188 |
) |
|
|
|
83,047 |
|
|
|
|
39,125 |
|
|
|
|
|
|
|
|
|
| Total Comprehensive Income/(Loss) |
|
|
|
|
$ |
145,889 |
|
|
|
$ |
(25,908 |
) |
|
|
$ |
230,471 |
|
|
|
$ |
57,475 |
|
|
|
|
|
|
|
|
|
Net Income/(Loss) per Share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Basic |
|
14 |
|
|
$ |
0.33 |
|
|
|
$ |
(0.02 |
) |
|
|
$ |
0.72 |
|
|
|
$ |
0.09 |
|
|
| Diluted |
|
14 |
|
|
$ |
0.32 |
|
|
|
$ |
(0.02 |
) |
|
|
$ |
0.71 |
|
|
|
$ |
0.09 |
|
|
|
|
|
|
|
|
|
See accompanying notes to the Condensed Consolidated Financial Statements
ENERPLUS 2014 Q3
REPORT 25
Condensed Consolidated Statements of Changes
in Shareholders' Equity
| Nine months ended September 30, (CDN$ thousands) unaudited |
|
|
2014 |
|
|
|
|
2013 |
|
|
|
|
|
| Share Capital |
|
|
|
|
|
|
|
|
|
|
| Balance, beginning of year |
|
$ |
3,061,839 |
|
|
|
$ |
2,997,682 |
|
|
| Stock Option Plan – cash |
|
|
27,068 |
|
|
|
|
12,723 |
|
|
| Share-based compensation – non-cash |
|
|
4,783 |
|
|
|
|
2,222 |
|
|
| Stock Dividend Plan |
|
|
21,837 |
|
|
|
|
33,489 |
|
|
|
|
|
| Balance, end of period |
|
$ |
3,115,527 |
|
|
|
$ |
3,046,116 |
|
|
|
|
|
Paid-in Capital |
|
|
|
|
|
|
|
|
|
|
| Balance, beginning of year |
|
$ |
38,398 |
|
|
|
$ |
32,293 |
|
|
| Stock Option Plan – exercised |
|
|
(4,783 |
) |
|
|
|
(2,222 |
) |
|
| Share-based compensation – expensed |
|
|
9,907 |
|
|
|
|
7,164 |
|
|
|
| Balance, end of period |
|
$ |
43,522 |
|
|
|
$ |
37,235 |
|
|
|
|
|
Accumulated Deficit |
|
|
|
|
|
|
|
|
|
|
| Balance, beginning of year |
|
$ |
(1,117,238 |
) |
|
|
$ |
(948,350 |
) |
|
| Net income |
|
|
147,424 |
|
|
|
|
18,350 |
|
|
| Dividends |
|
|
(165,587 |
) |
|
|
|
(162,199 |
) |
|
|
| Balance, end of period |
|
$ |
(1,135,401 |
) |
|
|
$ |
(1,092,199 |
) |
|
|
|
|
Accumulated Other Comprehensive Income/(Loss) |
|
|
|
|
|
|
|
|
|
|
| Balance, beginning of year |
|
$ |
(50,697 |
) |
|
|
$ |
(130,385 |
) |
|
| Changes due to marketable securities (net of tax) |
|
|
|
|
|
|
|
|
|
|
| |
Unrealized gains/(losses) |
|
|
(145 |
) |
|
|
|
5,104 |
|
|
| |
Realized (gains)/losses reclassified to net income |
|
|
2,503 |
|
|
|
|
(315 |
) |
|
| Change in cumulative translation adjustment |
|
|
80,689 |
|
|
|
|
34,336 |
|
|
|
|
|
| Balance, end of period |
|
$ |
32,350 |
|
|
|
$ |
(91,260 |
) |
|
|
|
|
| Total Shareholders' Equity |
|
$ |
2,055,998 |
|
|
|
$ |
1,899,892 |
|
|
|
|
|
See accompanying notes to the Condensed Consolidated Financial Statements
26 ENERPLUS 2014 Q3
REPORT
Condensed Consolidated Statements of Cash Flows
| |
|
|
|
|
Three months ended
September 30,
|
|
|
|
Nine months ended
September 30,
|
|
|
| (CDN$ thousands) unaudited |
|
Note |
|
|
|
2014 |
|
|
|
|
2013 |
|
|
|
|
2014 |
|
|
|
|
2013 |
|
|
|
|
|
|
|
|
|
| Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net income/(loss) |
|
|
|
|
$ |
67,430 |
|
|
|
$ |
(3,720 |
) |
|
|
$ |
147,424 |
|
|
|
$ |
18,350 |
|
|
| Non-cash items add/(deduct): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Depletion, depreciation, amortization and accretion |
|
|
|
|
|
159,658 |
|
|
|
|
163,339 |
|
|
|
|
440,494 |
|
|
|
|
470,088 |
|
|
| |
Changes in fair value of derivative instruments |
|
15 |
|
|
|
(88,689 |
) |
|
|
|
48,950 |
|
|
|
|
(81,750 |
) |
|
|
|
35,061 |
|
|
| |
Deferred income tax expense/(recovery) |
|
13 |
|
|
|
36,853 |
|
|
|
|
(6,660 |
) |
|
|
|
74,063 |
|
|
|
|
15,528 |
|
|
| |
Foreign exchange (gain)/loss on debt and working capital |
|
12 |
|
|
|
33,863 |
|
|
|
|
(7,446 |
) |
|
|
|
35,798 |
|
|
|
|
9,092 |
|
|
| |
Share-based compensation |
|
14 |
|
|
|
3,413 |
|
|
|
|
1,686 |
|
|
|
|
9,907 |
|
|
|
|
7,164 |
|
|
| |
Amortization of debt issue costs |
|
|
|
|
|
251 |
|
|
|
|
188 |
|
|
|
|
744 |
|
|
|
|
565 |
|
|
| Derivative settlement on senior notes |
|
|
|
|
|
– |
|
|
|
|
– |
|
|
|
|
17,024 |
|
|
|
|
18,011 |
|
|
| Asset disposition (gain)/loss |
|
|
|
|
|
– |
|
|
|
|
(150 |
) |
|
|
|
2,798 |
|
|
|
|
(367 |
) |
|
| Asset retirement obligation expenditures |
|
8 |
|
|
|
(3,299 |
) |
|
|
|
(3,701 |
) |
|
|
|
(11,831 |
) |
|
|
|
(10,036 |
) |
|
| Changes in non-cash operating working capital |
|
17 |
|
|
|
(10,435 |
) |
|
|
|
25,684 |
|
|
|
|
(66,710 |
) |
|
|
|
11,372 |
|
|
|
|
|
|
|
|
|
| Cash flow from operating activities |
|
|
|
|
|
199,045 |
|
|
|
|
218,170 |
|
|
|
|
567,961 |
|
|
|
|
574,828 |
|
|
|
|
|
|
|
|
|
Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Proceeds from the issuance of shares |
|
|
|
|
|
7,875 |
|
|
|
|
12,694 |
|
|
|
|
27,068 |
|
|
|
|
12,723 |
|
|
| Cash dividends |
|
14 |
|
|
|
(51,088 |
) |
|
|
|
(42,411 |
) |
|
|
|
(143,750 |
) |
|
|
|
(128,710 |
) |
|
| Change in bank debt |
|
|
|
|
|
(236,013 |
) |
|
|
|
(144,858 |
) |
|
|
|
(159,303 |
) |
|
|
|
(74,769 |
) |
|
| Issuance (repayment) of senior notes |
|
|
|
|
|
217,460 |
|
|
|
|
– |
|
|
|
|
179,562 |
|
|
|
|
(35,655 |
) |
|
| Derivative settlement on senior notes |
|
|
|
|
|
– |
|
|
|
|
– |
|
|
|
|
(17,024 |
) |
|
|
|
(18,011 |
) |
|
| Changes in non-cash financing working capital |
|
|
|
|
|
34 |
|
|
|
|
137 |
|
|
|
|
238 |
|
|
|
|
288 |
|
|
|
|
|
|
|
|
|
| Cash flow from financing activities |
|
|
|
|
|
(61,732 |
) |
|
|
|
(174,438 |
) |
|
|
|
(113,209 |
) |
|
|
|
(244,134 |
) |
|
|
|
|
|
|
|
|
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Capital expenditures |
|
|
|
|
|
(209,197 |
) |
|
|
|
(146,997 |
) |
|
|
|
(633,013 |
) |
|
|
|
(461,838 |
) |
|
| Property and land acquisitions |
|
|
|
|
|
(3,986 |
) |
|
|
|
(15,792 |
) |
|
|
|
(17,186 |
) |
|
|
|
(71,451 |
) |
|
| Property dispositions |
|
|
|
|
|
68,931 |
|
|
|
|
124,462 |
|
|
|
|
185,631 |
|
|
|
|
197,086 |
|
|
| Sale of marketable securities |
|
5 |
|
|
|
– |
|
|
|
|
599 |
|
|
|
|
13,300 |
|
|
|
|
2,482 |
|
|
| Changes in non-cash investing working capital |
|
|
|
|
|
5,116 |
|
|
|
|
(145 |
) |
|
|
|
(5,689 |
) |
|
|
|
20,590 |
|
|
|
|
|
|
|
|
|
| Cash flow from investing activities |
|
|
|
|
|
(139,136 |
) |
|
|
|
(37,873 |
) |
|
|
|
(456,957 |
) |
|
|
|
(313,131 |
) |
|
|
|
|
|
|
|
|
| Effect of exchange rate changes on cash |
|
|
|
|
|
1,929 |
|
|
|
|
1,696 |
|
|
|
|
1,319 |
|
|
|
|
(4,452 |
) |
|
|
|
|
|
|
|
|
| Change in cash |
|
|
|
|
|
106 |
|
|
|
|
7,555 |
|
|
|
|
(886 |
) |
|
|
|
13,111 |
|
|
| Cash, beginning of period |
|
|
|
|
|
1,998 |
|
|
|
|
10,756 |
|
|
|
|
2,990 |
|
|
|
|
5,200 |
|
|
|
|
|
|
|
|
|
| Cash, end of period |
|
|
|
|
$ |
2,104 |
|
|
|
$ |
18,311 |
|
|
|
$ |
2,104 |
|
|
|
$ |
18,311 |
|
|
|
|
|
|
|
|
|
See accompanying notes to the Condensed Consolidated Financial Statements
ENERPLUS 2014 Q3
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 November 6, 2014.
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") as at September 30, 2014 and for the three and nine months ended September 30, 2014, and the 2013 comparative
periods. These interim Consolidated Financial Statements do not include all the necessary annual disclosures as prescribed under U.S. GAAP and should be read in conjunction with Enerplus'
audited Consolidated Financial Statements
as of December 31, 2013. 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, 2013.
Recent Accounting Pronouncements
Enerplus will adopt the following Accounting Standards Updates ("ASU") issued by the Financial Accounting Standards Board, which have been issued but are not
yet effective. The adoption of these standards is not expected to have a material impact on Enerplus' financial statements.
- •
- ASU
2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an
Entity – effective January 1, 2015
- •
- ASU
2014-09, Revenue from Contracts with Customers – effective
January 1, 2017
- •
- ASU
2014-12, Compensation – Stock Compensation: Accounting for Share-Based Payments When the Terms of an Award
Provide That a Performance Target Could Be Achieved after the Requisite Service Period – effective January 1, 2016
3) ACCOUNTS RECEIVABLE
| ($ thousands) |
|
|
September 30, 2014 |
|
|
|
|
December 31, 2013 |
|
|
|
|
|
| Accrued receivables |
|
$ |
140,394 |
|
|
|
$ |
122,482 |
|
|
| Accounts receivable – trade |
|
|
43,613 |
|
|
|
|
36,034 |
|
|
| Current income tax receivable |
|
|
16,424 |
|
|
|
|
9,371 |
|
|
| Allowance for doubtful accounts |
|
|
(2,855 |
) |
|
|
|
(2,796 |
) |
|
|
|
|
| Total accounts receivable |
|
$ |
197,576 |
|
|
|
$ |
165,091 |
|
|
|
|
|
28 ENERPLUS 2014 Q3
REPORT
4) PROPERTY, PLANT AND EQUIPMENT ("PP&E")
As at September 30, 2014
($ thousands) |
|
|
Cost |
|
|
Accumulated
Depletion and
Depreciation |
|
|
Net Book Value |
|
|
| Oil and natural gas properties |
|
$ |
12,152,423 |
|
$ |
9,623,930 |
|
$ |
2,528,493 |
|
| Other capital assets |
|
|
93,474 |
|
|
74,612 |
|
|
18,862 |
|
|
| Total PP&E |
|
$ |
12,245,897 |
|
$ |
9,698,542 |
|
$ |
2,547,355 |
|
|
As at December 31, 2013
($ thousands) |
|
|
Cost |
|
|
Accumulated
Depletion and
Depreciation |
|
|
Net Book Value |
|
|
| Oil and natural gas properties |
|
$ |
11,481,207 |
|
$ |
9,061,063 |
|
$ |
2,420,144 |
|
| Other capital assets |
|
|
89,818 |
|
|
68,608 |
|
|
21,210 |
|
|
| Total PP&E |
|
$ |
11,571,025 |
|
$ |
9,129,671 |
|
$ |
2,441,354 |
|
|
5) MARKETABLE SECURITIES
During the nine months ended September 30, 2014 Enerplus sold the balance of its publicly listed investments for proceeds of $13.3 million
recognizing a loss of $2.8 million. In connection with these sales, realized losses of $2.5 million net of tax ($2.8 million before tax) were reclassified from accumulated other
comprehensive income to net income.
6) ACCOUNTS PAYABLE
| ($ thousands) |
|
|
September 30, 2014 |
|
|
|
December 31, 2013 |
|
|
|
|
| Accrued payables |
|
$ |
266,120 |
|
|
$ |
262,117 |
|
| Accounts payable – trade |
|
|
81,148 |
|
|
|
115,040 |
|
|
|
|
| Total accounts payable |
|
$ |
347,268 |
|
|
$ |
377,157 |
|
|
|
|
7) DEBT
| ($ thousands) |
|
|
September 30, 2014 |
|
|
|
December 31, 2013 |
|
|
|
|
| Current: |
|
|
|
|
|
|
|
|
| |
Senior notes |
|
$ |
96,937 |
|
|
$ |
48,713 |
|
|
|
|
| |
|
$ |
96,937 |
|
|
$ |
48,713 |
|
|
|
|
| Long term: |
|
|
|
|
|
|
|
|
| |
Bank credit facility |
|
$ |
57,532 |
|
|
$ |
214,394 |
|
| |
Senior notes |
|
|
938,745 |
|
|
|
762,191 |
|
|
|
|
| |
|
$ |
996,277 |
|
|
$ |
976,585 |
|
|
|
|
| Total debt |
|
$ |
1,093,214 |
|
|
$ |
1,025,298 |
|
|
|
|
On September 3, 2014 Enerplus closed a private placement of senior unsecured notes raising gross proceeds of US$200,000,000. The notes rank
equally with the bank credit facility and other outstanding senior notes. The notes have a twelve year amortizing term and a ten year average life with a fixed coupon rate of 3.79%.
ENERPLUS 2014 Q3
REPORT 29
8) ASSET RETIREMENT OBLIGATION
Enerplus has estimated the present value of its asset retirement obligation to be $286.7 million at September 30, 2014 compared to
$291.8 million at December 31, 2013, based on a total undiscounted liability of $707.2 million and $720.6 million, respectively. The asset retirement obligation was
calculated using a weighted credit-adjusted risk-free rate of 5.92% at September 30, 2014 (December 31, 2013 – 5.96%).
| ($ thousands) |
|
|
Nine months ended
September 30, 2014 |
|
|
|
|
Year ended
December 31, 2013 |
|
|
|
|
|
| Balance, beginning of year |
|
$ |
291,761 |
|
|
|
$ |
256,102 |
|
|
| Change in estimates |
|
|
(1,725 |
) |
|
|
|
44,217 |
|
|
| Property acquisition and development activity |
|
|
1,372 |
|
|
|
|
1,454 |
|
|
| Dispositions |
|
|
(3,990 |
) |
|
|
|
(8,362 |
) |
|
| Settlements |
|
|
(11,831 |
) |
|
|
|
(16,606 |
) |
|
| Accretion Expense |
|
|
11,161 |
|
|
|
|
14,956 |
|
|
|
|
|
| Balance, end of period |
|
$ |
286,748 |
|
|
|
$ |
291,761 |
|
|
|
|
|
9) OIL AND NATURAL GAS SALES
| |
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
| ($ thousands) |
|
|
2014 |
|
|
2013 |
|
|
|
|
2014 |
|
|
2013 |
|
|
|
|
|
| |
Oil and natural gas sales |
|
$ |
456,215 |
|
$ |
441,503 |
|
|
|
$ |
1,455,790 |
|
$ |
1,219,755 |
|
|
| |
Royalties(1) |
|
|
(77,883 |
) |
|
(76,112 |
) |
|
|
|
(254,793 |
) |
|
(199,659 |
) |
|
|
|
|
| Oil and natural gas sales, net of royalties |
|
$ |
378,332 |
|
$ |
365,391 |
|
|
|
$ |
1,200,997 |
|
$ |
1,020,096 |
|
|
|
|
|
- (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 September 30,
|
|
Nine months ended September 30,
|
| ($ thousands) |
|
|
2014 |
|
|
2013 |
|
|
|
2014 |
|
|
2013 |
|
|
|
|
| General and administrative expense |
|
$ |
18,854 |
|
$ |
20,031 |
|
|
$ |
58,055 |
|
$ |
63,514 |
|
| Share-based compensation expense(1) |
|
|
4,083 |
|
|
5,083 |
|
|
|
22,185 |
|
|
17,475 |
|
|
|
|
| General and administrative expense |
|
$ |
22,937 |
|
$ |
25,114 |
|
|
$ |
80,240 |
|
$ |
80,989 |
|
|
|
|
- (1)
- Share-based
compensation relates to the cash and equity-settled Long-term Incentive Plans and the Stock Option Plan. Refer to Note 14(c) for further discussion.
11) INTEREST EXPENSE
| |
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
| ($ thousands) |
|
|
2014 |
|
|
2013 |
|
|
|
|
2014 |
|
|
2013 |
|
|
|
|
|
Realized:
Interest on bank debt and senior notes |
|
$ |
14,924 |
|
$ |
14,665 |
|
|
|
$ |
45,552 |
|
$ |
43,141 |
|
|
| Unrealized: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Cross currency interest rate swap (gain)/loss |
|
|
– |
|
|
273 |
|
|
|
|
580 |
|
|
1,093 |
|
|
| |
Interest rate swap (gain)/loss |
|
|
– |
|
|
(42 |
) |
|
|
|
– |
|
|
(478 |
) |
|
| |
Amortization of debt issue costs |
|
|
251 |
|
|
188 |
|
|
|
|
744 |
|
|
565 |
|
|
|
|
|
| Interest expense |
|
$ |
15,175 |
|
$ |
15,084 |
|
|
|
$ |
46,876 |
|
$ |
44,321 |
|
|
|
|
|
30 ENERPLUS 2014 Q3
REPORT
12) FOREIGN EXCHANGE
| |
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
| ($ thousands) |
|
|
2014 |
|
|
2013 |
|
|
|
|
2014 |
|
|
2013 |
|
|
|
|
|
| Realized: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Foreign exchange (gain)/loss |
|
$ |
(2,607 |
) |
$ |
59 |
|
|
|
$ |
14,069 |
|
$ |
17,658 |
|
|
| Unrealized: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Translation of U.S. dollar debt and working capital (gain)/loss |
|
|
33,863 |
|
|
(7,446 |
) |
|
|
|
35,798 |
|
|
9,092 |
|
|
| |
Cross currency interest rate swap (gain)/loss |
|
|
– |
|
|
939 |
|
|
|
|
(16,130 |
) |
|
(19,043 |
) |
|
| |
Foreign exchange derivative (gain)/loss |
|
|
(758 |
) |
|
3,939 |
|
|
|
|
(8,995 |
) |
|
(3,680 |
) |
|
|
|
|
| Foreign exchange (gain)/loss |
|
$ |
30,498 |
|
$ |
(2,509 |
) |
|
|
$ |
24,742 |
|
$ |
4,027 |
|
|
|
|
|
13) INCOME TAXES
| |
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
| ($ thousands) |
|
|
2014 |
|
|
2013 |
|
|
|
|
2014 |
|
|
2013 |
|
|
|
|
|
| Current tax expense/(recovery) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Canada |
|
$ |
(79 |
) |
$ |
(339 |
) |
|
|
$ |
(453 |
) |
$ |
(258 |
) |
|
| |
U.S. |
|
|
51 |
|
|
5,574 |
|
|
|
|
11,900 |
|
|
8,201 |
|
|
|
|
|
| Current tax expense/(recovery) |
|
|
(28 |
) |
|
5,235 |
|
|
|
|
11,447 |
|
|
7,943 |
|
|
|
|
|
| Deferred tax expense/(recovery) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Canada |
|
$ |
24,530 |
|
$ |
(17,561 |
) |
|
|
$ |
19,212 |
|
$ |
(20,073 |
) |
|
| |
U.S. |
|
|
12,323 |
|
|
10,901 |
|
|
|
|
54,851 |
|
|
35,601 |
|
|
|
|
|
| Deferred tax expense/(recovery) |
|
$ |
36,853 |
|
$ |
(6,660 |
) |
|
|
$ |
74,063 |
|
$ |
15,528 |
|
|
|
|
|
| Income tax expense/(recovery) |
|
$ |
36,825 |
|
$ |
(1,425 |
) |
|
|
$ |
85,510 |
|
$ |
23,471 |
|
|
|
|
|
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
| |
|
Nine months ended September 30, |
|
Year ended December 31, |
| |
|
|
|
|
| |
|
2014 |
|
2013 |
|
|
|
Authorized unlimited number of common shares
Issued: (thousands) |
|
Shares |
|
|
Amount |
|
|
Shares |
|
|
Amount |
|
|
|
|
| Balance, beginning of year |
|
202,758 |
|
$ |
3,061,839 |
|
|
198,684 |
|
$ |
2,997,682 |
|
| Issued for cash: |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Stock Option Plan |
|
1,635 |
|
|
27,068 |
|
|
1,042 |
|
|
14,838 |
|
| Non-cash: |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Stock Option Plan |
|
– |
|
|
4,783 |
|
|
– |
|
|
3,108 |
|
| |
Stock Dividend Plan |
|
1,030 |
|
|
21,837 |
|
|
3,032 |
|
|
46,211 |
|
|
|
|
| Balance, end of period |
|
205,423 |
|
$ |
3,115,527 |
|
|
202,758 |
|
$ |
3,061,839 |
|
|
|
|
ENERPLUS 2014 Q3
REPORT 31
b) Dividends
| |
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
| ($ thousands) |
|
|
2014 |
|
|
2013 |
|
|
|
2014 |
|
|
2013 |
|
|
|
|
| Cash dividends |
|
$ |
51,088 |
|
$ |
42,411 |
|
|
$ |
143,750 |
|
$ |
128,710 |
|
| Stock dividends |
|
|
4,350 |
|
|
11,994 |
|
|
|
21,837 |
|
|
33,489 |
|
|
|
|
| Dividends to shareholders |
|
$ |
55,438 |
|
$ |
54,405 |
|
|
$ |
165,587 |
|
$ |
162,199 |
|
|
|
|
c) Share-Based Compensation ("SBC")
The following table summarizes Enerplus' SBC expense, which is included in General and Administrative expense on the Consolidated Statements of Income/(Loss):
| |
|
Three months ended September 30,
|
|
Nine months ended September 30,
|
| ($ thousands) |
|
|
2014 |
|
|
2013 |
|
|
|
|
2014 |
|
|
2013 |
|
|
|
|
|
| Cash: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Long-term incentive plans expense/(recovery) |
|
$ |
(5,174 |
) |
$ |
4,869 |
|
|
|
$ |
12,338 |
|
$ |
14,074 |
|
|
| Non-Cash: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Long-term incentive plans expense |
|
|
2,815 |
|
|
– |
|
|
|
|
6,506 |
|
|
– |
|
|
| |
Stock option plan expense |
|
|
598 |
|
|
1,686 |
|
|
|
|
3,401 |
|
|
7,164 |
|
|
| |
Equity swap (gain)/loss |
|
|
5,844 |
|
|
(1,472 |
) |
|
|
|
(60 |
) |
|
(3,763 |
) |
|
|
|
|
| Share-based compensation expense |
|
$ |
4,083 |
|
$ |
5,083 |
|
|
|
$ |
22,185 |
|
$ |
17,475 |
|
|
|
|
|
(i) Long-Term Incentive ("LTI") Plans
In 2014, the Performance Share Unit and Restricted Share Unit 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 Performance Share Unit ("PSU"), Restricted Share Unit ("RSU") and Director Share Unit ("DSU") activity for the nine months ended September 30, 2014:
| For the nine months ended September 30, 2014 (thousands of units) |
|
PSU |
|
RSU |
|
DSU |
|
Total |
|
|
|
| Balance, beginning of year |
|
650 |
|
821 |
|
99 |
|
1,570 |
|
|
| Granted |
|
550 |
|
832 |
|
47 |
|
1,429 |
|
|
| Vested |
|
– |
|
(375 |
) |
– |
|
(375 |
) |
|
| Forfeited |
|
(30 |
) |
(93 |
) |
– |
|
(123 |
) |
|
|
| Balance, end of period |
|
1,170 |
|
1,185 |
|
146 |
|
2,501 |
|
|
|
| End of period balances, by grant settlement type: |
|
|
|
|
|
|
|
|
|
|
| |
Cash-settled units |
|
630 |
|
409 |
|
146 |
|
1,185 |
|
|
| |
Equity-settled units |
|
540 |
|
776 |
|
– |
|
1,316 |
|
|
|
| Balance, end of period |
|
1,170 |
|
1,185 |
|
146 |
|
2,501 |
|
|
|
32 ENERPLUS 2014 Q3
REPORT
Cash-settled LTI Plans
For the three months ended September 30, 2014 the Company recorded a recovery for cash SBC expense of $5.2 million and for the nine months
ended September 30, 2014 recorded a charge of $12.3 million (September 30, 2013 – charges of $4.9 million and
$14.1 million). For the three and nine months ended September 30, 2014, the Company made cash payments of $2.0 million and $13.8 million, respectively, related to
its cash-settled plans (September 30, 2013 – $4.2 million and $11.1 million).
The
following table summarizes the cumulative SBC expense recognized to-date, which has been recorded to Accounts Payable on the Consolidated Balance Sheets. Unrecognized amounts will be recorded to
cash SBC expense over the remaining vesting terms.
| At September 30, 2014 ($ thousands, except for years) |
|
|
PSU(1) |
|
|
RSU |
|
|
DSU |
|
|
Total |
|
|
| Cumulative recognized SBC expense |
|
$ |
19,412 |
|
$ |
7,450 |
|
$ |
3,380 |
|
$ |
30,242 |
|
| Unrecognized SBC expense |
|
|
6,910 |
|
|
2,280 |
|
|
– |
|
|
9,190 |
|
|
| Intrinsic value |
|
$ |
26,322 |
|
$ |
9,730 |
|
$ |
3,380 |
|
$ |
39,432 |
|
|
| Weighted-average remaining contractual term (years) |
|
|
0.8 |
|
|
0.8 |
|
|
– |
|
|
|
|
|
- (1)
- Includes
estimated performance multipliers.
Equity-settled LTI Plans
Equity-settled LTI awards are settled through the issuance of treasury shares and the related SBC expense is recorded as a non-cash amount on the Consolidated
Statements of Income/(Loss), with an offset recorded to Paid-in Capital. On settlement, the amount previously recorded to Paid-in Capital is reclassified to Share Capital.
For
the three and nine months ended September 30, 2014 the Company recorded non-cash SBC expense of $2.8 million and $6.5 million, respectively. No non-cash amounts were
recognized for the three and nine months ended September 30, 2013 with respect to equity-settled grants.
The
following table summarizes the cumulative SBC expense recognized to-date which is recorded to Paid-in Capital on the Consolidated Balance Sheets. Unrecognized amounts will be recorded to non-cash
SBC expense over the remaining vesting terms.
| At September 30, 2014 ($ thousands, except for years) |
|
|
PSU(1) |
|
|
RSU |
|
|
Total |
|
|
| Cumulative recognized SBC expense |
|
$ |
1,592 |
|
$ |
4,914 |
|
$ |
6,506 |
|
| Unrecognized SBC expense |
|
|
6,252 |
|
|
8,561 |
|
|
14,813 |
|
|
| |
|
$ |
7,844 |
|
$ |
13,475 |
|
$ |
21,319 |
|
|
| Weighted-average remaining contractual term (years) |
|
|
2.3 |
|
|
1.6 |
|
|
|
|
|
- (1)
- Includes
estimated performance multipliers.
ENERPLUS 2014 Q3
REPORT 33
(ii) Stock Option Plan
The Company did not grant any stock options during the nine months ended September 30, 2014. Activity for the respective reporting periods is
as follows:
| |
|
Nine months ended September 30, 2014 |
| |
|
|
| |
|
Number of
Options
(thousands) |
|
|
Weighted
Average
Exercise Price |
|
|
| Options outstanding |
|
|
|
|
|
|
| Beginning of year |
|
13,414 |
|
$ |
18.65 |
|
| |
Granted |
|
– |
|
|
– |
|
| |
Exercised |
|
(1,635 |
) |
|
16.56 |
|
| |
Forfeited |
|
(555 |
) |
|
19.49 |
|
| |
Expired |
|
– |
|
|
– |
|
|
| Options outstanding, end of period |
|
11,224 |
|
$ |
18.91 |
|
|
| Options exercisable at the end of period |
|
6,247 |
|
$ |
21.48 |
|
|
At September 30, 2014, 6,247,000 options were exercisable at a weighted average reduced exercise price of $21.48 with a weighted average
remaining contractual term of 4.0 years, giving an intrinsic value of $17.4 million (September 30, 2013 – $2.6 million). The
intrinsic value of options exercised during the three and nine months ended September 30, 2014 was $4.3 million and $12.4 million, respectively
(September 30, 2013 – $2.2 million and $2.2 million).
At
September 30, 2014 the unrecognized SBC expense related to non-vested options was $1.8 million
(September 30, 2013 – $6.3 million). The expense is expected to be fully recognized over a weighted-average period of 0.9 years.
d) Paid-in Capital
The following table summarizes the paid-in capital activity for the nine months ended September 30, 2014 and the year ended
December 31, 2013:
| ($ thousands) |
|
|
Nine months ended
September 30, 2014 |
|
|
|
|
Year ended
December 31, 2013 |
|
|
|
|
|
| Balance, beginning of year |
|
$ |
38,398 |
|
|
|
$ |
32,293 |
|
|
| Stock Option Plan – exercised |
|
|
(4,783 |
) |
|
|
|
(3,108 |
) |
|
| Share-based compensation – non-cash |
|
|
9,907 |
|
|
|
|
9,213 |
|
|
|
|
|
| Balance, end of period |
|
$ |
43,522 |
|
|
|
$ |
38,398 |
|
|
|
|
|
e) Basic and Diluted Earnings Per Share
Net income/(loss) per share has been determined as follows:
| |
|
Three months ended September 30,
|
|
|
|
Nine months ended September 30,
|
|
| (thousands, except per share amounts) |
|
|
2014 |
|
|
|
2013 |
|
|
|
|
2014 |
|
|
|
2013 |
|
|
|
|
| Net income/(loss) |
|
$ |
67,430 |
|
|
$ |
(3,720 |
) |
|
|
$ |
147,424 |
|
|
$ |
18,350 |
|
| Weighted average shares outstanding – Basic |
|
|
205,164 |
|
|
|
201,117 |
|
|
|
|
204,174 |
|
|
|
200,002 |
|
| Dilutive impact of share-based compensation(1) |
|
|
3,933 |
|
|
|
– |
|
|
|
|
3,796 |
|
|
|
413 |
|
|
|
|
| Weighted average shares outstanding – Diluted |
|
|
209,097 |
|
|
|
201,117 |
|
|
|
|
207,970 |
|
|
|
200,415 |
|
|
|
|
| Net income/(loss) per share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Basic |
|
|
0.33 |
|
|
|
(0.02 |
) |
|
|
|
0.72 |
|
|
|
0.09 |
|
| |
Diluted |
|
|
0.32 |
|
|
|
(0.02 |
) |
|
|
|
0.71 |
|
|
|
0.09 |
|
|
|
|
- (1)
- For
the three months ended September 30, 2013, the impact of share-based compensation was anti-dilutive as a conversion to shares would not increase the loss per share.
34 ENERPLUS 2014 Q3
REPORT
15) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
a) Fair Value Measurements
At September 30, 2014, 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
September 30, 2014 senior notes included in long-term debt had a carrying value of $1,035.7 million and a fair value of $1,118.7 million
(December 31, 2013 – $810.9 million and $837.8 million, respectively).
Enerplus'
derivative financial instruments are classified as Level 2. A Level 2 classification is appropriate where observable inputs other than quoted market prices are used in the fair
value determination.
There
were no transfers between fair value hierarchy levels during the period.
b) Derivative Financial Instruments
The deferred financial assets and credits on the Consolidated Balance Sheets result from recording derivative financial instruments at fair value.
The
following table summarizes the change in fair value for the three and nine months ended September 30, 2014 and 2013:
| |
|
Three months ended September 30,
|
|
|
|
Nine months ended September 30,
|
|
|
|
| Gain/(Loss) ($ thousands) |
|
|
2014 |
|
|
|
|
2013 |
|
|
|
|
2014 |
|
|
|
|
2013 |
|
Income Statement
Presentation |
|
|
|
|
| Interest Rate Swaps |
|
$ |
– |
|
|
|
$ |
42 |
|
|
|
$ |
– |
|
|
|
$ |
478 |
|
Interest |
|
| Cross Currency Interest Rate Swap: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Interest |
|
|
– |
|
|
|
|
(273 |
) |
|
|
|
(580 |
) |
|
|
|
(1,093 |
) |
Interest |
|
| |
Foreign Exchange |
|
|
– |
|
|
|
|
(939 |
) |
|
|
|
16,130 |
|
|
|
|
19,043 |
|
Foreign Exchange |
|
| Foreign Exchange Derivatives |
|
|
758 |
|
|
|
|
(3,939 |
) |
|
|
|
8,995 |
|
|
|
|
3,680 |
|
Foreign Exchange |
|
| Electricity Swaps |
|
|
22 |
|
|
|
|
(156 |
) |
|
|
|
204 |
|
|
|
|
1,314 |
|
Operating |
|
| Equity Swaps |
|
|
(5,844 |
) |
|
|
|
1,472 |
|
|
|
|
60 |
|
|
|
|
3,763 |
|
General and Administrative |
|
| Commodity Derivative Instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Oil |
|
|
82,874 |
|
|
|
|
(45,609 |
) |
|
|
|
48,671 |
|
|
|
|
(66,501 |
) |
Commodity derivative |
|
| |
|
Gas |
|
|
10,879 |
|
|
|
|
452 |
|
|
|
|
8,270 |
|
|
|
|
4,255 |
|
instruments Gain/(loss) |
|
|
|
|
| Total |
|
$ |
88,689 |
|
|
|
$ |
(48,950 |
) |
|
|
$ |
81,750 |
|
|
|
$ |
(35,061 |
) |
|
|
|
|
|
The following table summarizes the income statement effects of Enerplus' commodity derivative instruments:
| |
|
Three months ended September 30,
|
|
|
|
Nine months ended September 30,
|
|
|
| ($ thousands) |
|
|
2014 |
|
|
|
|
2013 |
|
|
|
|
2014 |
|
|
|
|
2013 |
|
|
|
|
|
| Change in fair value gain/(loss) |
|
$ |
93,753 |
|
|
|
$ |
(45,157 |
) |
|
|
$ |
56,941 |
|
|
|
$ |
(62,246 |
) |
|
| Net realized cash gain/(loss) |
|
|
(2,485 |
) |
|
|
|
(10,517 |
) |
|
|
|
(42,339 |
) |
|
|
|
10,139 |
|
|
|
|
|
| Commodity derivative instruments gain/(loss) |
|
$ |
91,268 |
|
|
|
$ |
(55,674 |
) |
|
|
$ |
14,602 |
|
|
|
$ |
(52,107 |
) |
|
|
|
|
ENERPLUS 2014 Q3
REPORT 35
The following table summarizes the fair values at the respective period ends:
| |
|
September 30, 2014
|
|
December 31, 2013
|
| |
|
Assets
|
|
Liabilities
|
|
Assets
|
|
Liabilities
|
| ($ thousands) |
|
|
Current |
|
|
Long-term |
|
|
Current |
|
|
|
Current |
|
|
Long-term |
|
|
Current |
|
|
|
|
| Cross Currency Interest Rate Swap |
|
$ |
– |
|
$ |
– |
|
$ |
– |
|
|
$ |
– |
|
$ |
– |
|
$ |
15,548 |
|
| Foreign Exchange Derivatives |
|
|
758 |
|
|
23,937 |
|
|
– |
|
|
|
564 |
|
|
15,135 |
|
|
– |
|
| Electricity Swaps |
|
|
113 |
|
|
– |
|
|
– |
|
|
|
– |
|
|
– |
|
|
95 |
|
| Equity Swaps |
|
|
4,196 |
|
|
1,726 |
|
|
– |
|
|
|
1,723 |
|
|
4,139 |
|
|
– |
|
| Commodity Derivative Instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Oil |
|
|
28,251 |
|
|
5,588 |
|
|
– |
|
|
|
4,138 |
|
|
– |
|
|
18,970 |
|
| |
Gas |
|
|
7,588 |
|
|
1,037 |
|
|
– |
|
|
|
2,773 |
|
|
– |
|
|
2,418 |
|
|
|
|
| Total |
|
$ |
40,906 |
|
$ |
32,288 |
|
$ |
– |
|
|
$ |
9,198 |
|
$ |
19,274 |
|
$ |
37,031 |
|
|
|
|
c) Risk Management
(i) Market Risk
Market risk is comprised of commodity price, foreign exchange, interest rate and equity price risk.
(ii) Commodity Price Risk:
Enerplus manages a portion of commodity price risk through a combination of financial derivative and physical delivery sales contracts. Enerplus' policy is to
enter into commodity contracts subject to a maximum of 80% of forecasted production volumes net of royalties and production taxes.
The
following tables summarize Enerplus' price risk management positions at October 22, 2014:
Crude Oil Instruments:
| Instrument Type |
|
bbls/day |
|
US$/bbl(1) |
|
|
|
| Oct 1, 2014 – Oct 31, 2014 |
|
|
|
|
|
|
| WTI Swap |
|
20,000 |
|
95.29 |
|
|
| WCS Differential Swap |
|
4,500 |
|
-20.76 |
|
|
| Brent – WTI Ratio Spread (% of Brent Price) |
|
4,000 |
|
92.72% |
|
|
Nov 1, 2014 – Dec 31, 2014 |
|
|
|
|
|
|
| WTI Swap |
|
20,000 |
|
95.29 |
|
|
| WCS Differential Swap |
|
4,000 |
|
-21.00 |
|
|
| MSW Differential Swap |
|
1,000 |
|
-5.90 |
|
|
| Brent – WTI Ratio Spread (% of Brent Price) |
|
4,000 |
|
92.72% |
|
|
Jan 1, 2015 – Jun 30, 2015 |
|
|
|
|
|
|
| WTI Swap |
|
15,500 |
|
93.58 |
|
|
| WCS Differential Swap |
|
3,000 |
|
-18.62 |
|
|
| WTI Purchased Call |
|
2,000 |
|
94.00 |
|
|
| WTI Sold Put |
|
2,000 |
|
63.00 |
|
|
Jul 1, 2015 – Dec 31, 2015 |
|
|
|
|
|
|
| WTI Swap |
|
8,000 |
|
93.86 |
|
|
| WCS Differential Swap |
|
2,000 |
|
-18.23 |
|
|
| WTI Purchased Call |
|
2,000 |
|
94.00 |
|
|
| WTI Sold Put |
|
2,000 |
|
63.00 |
|
|
|
- (1)
- Transactions
with a common term have been aggregated and presented as the weighted average price/bbl.
36 ENERPLUS 2014 Q3
REPORT
Natural Gas Instruments:
| Instrument Type |
|
MMcf/day |
|
CDN$/Mcf |
|
US$/Mcf |
|
|
| Oct 1, 2014 – Dec 31, 2014 |
|
|
|
|
|
|
|
| AECO Swap |
|
28.4 |
|
4.25 |
|
|
|
Oct 1, 2014 – Dec 31, 2014 |
|
|
|
|
|
|
|
| NYMEX Swap |
|
75.0 |
|
|
|
4.14 |
|
| NYMEX Collar – Purchased Put |
|
30.0 |
|
|
|
4.30 |
|
| NYMEX Collar – Sold Call |
|
30.0 |
|
|
|
5.08 |
|
| NYMEX Purchased Call |
|
25.0 |
|
|
|
4.17 |
|
| NYMEX Sold Put |
|
25.0 |
|
|
|
3.23 |
|
| NYMEX Sold Call |
|
25.0 |
|
|
|
5.00 |
|
Jan 1, 2015 – Mar 31, 2015 |
|
|
|
|
|
|
|
| NYMEX Swap |
|
80.0 |
|
|
|
4.25 |
|
| NYMEX Collar – Purchased Put |
|
30.0 |
|
|
|
4.53 |
|
| NYMEX Collar – Sold Call |
|
30.0 |
|
|
|
5.53 |
|
| NYMEX Purchased Call |
|
5.0 |
|
|
|
4.29 |
|
| NYMEX Sold Put |
|
5.0 |
|
|
|
3.25 |
|
| NYMEX Sold Call |
|
5.0 |
|
|
|
5.00 |
|
Apr 1, 2015 – Jun 30, 2015 |
|
|
|
|
|
|
|
| NYMEX Swap |
|
80.0 |
|
|
|
4.25 |
|
| NYMEX Purchased Call |
|
5.0 |
|
|
|
4.29 |
|
| NYMEX Sold Put |
|
5.0 |
|
|
|
3.25 |
|
| NYMEX Sold Call |
|
5.0 |
|
|
|
5.00 |
|
Jul 1, 2015 – Dec 31, 2015 |
|
|
|
|
|
|
|
| NYMEX Swap |
|
60.0 |
|
|
|
4.16 |
|
| NYMEX Purchased Call |
|
5.0 |
|
|
|
4.29 |
|
| NYMEX Sold Put |
|
5.0 |
|
|
|
3.25 |
|
| NYMEX Sold Call |
|
5.0 |
|
|
|
5.00 |
|
Jan 1, 2016 – Dec 31, 2016 |
|
|
|
|
|
|
|
| NYMEX Swap |
|
10.0 |
|
|
|
4.03 |
|
|
Electricity Instruments:
| Instrument Type |
|
MWh |
|
CDN$/MWh |
|
|
| Oct 1, 2014 – Dec 31, 2014 |
|
|
|
|
|
| AESO Power Swap |
|
16.0 |
|
53.33 |
|
Jan 1, 2015 – Dec 31, 2015 |
|
|
|
|
|
| AESO Power Swap |
|
16.0 |
|
50.80 |
|
Jan 1, 2016 – Dec 31, 2016 |
|
|
|
|
|
| AESO Power Swap |
|
6.0 |
|
50.25 |
|
|
ENERPLUS 2014 Q3
REPORT 37
Physical Contracts:
| Instrument Type |
|
MMcf/day |
|
US$/Mcf |
|
|
|
| Oct 1, 2014 – Oct 31, 2014 |
|
|
|
|
|
|
| AECO-NYMEX Basis |
|
60.0 |
|
(0.61 |
) |
|
Nov 1, 2014 – Oct 31, 2015 |
|
|
|
|
|
|
| AECO-NYMEX Basis |
|
50.0 |
|
(0.66 |
) |
|
Nov 1, 2015 – Oct 31, 2016 |
|
|
|
|
|
|
| AECO-NYMEX Basis |
|
60.0 |
|
(0.67 |
) |
|
Nov 1, 2016 – Oct 31, 2017 |
|
|
|
|
|
|
| AECO-NYMEX Basis |
|
70.0 |
|
(0.64 |
) |
|
Nov 1, 2017 – Oct 31, 2018 |
|
|
|
|
|
|
| AECO-NYMEX Basis |
|
70.0 |
|
(0.64 |
) |
|
|
Foreign Exchange Risk:
Enerplus is exposed to foreign exchange risk in relation to its U.S. operations, and U.S. dollar denominated senior notes and working capital.
Additionally, Enerplus' crude oil sales and a portion of its natural gas sales are based on U.S. dollar indices. Enerplus manages currency through the derivative instruments
detailed below.
Foreign Exchange Derivatives:
During 2014, Enerplus entered into foreign exchange collars to hedge a portion of its foreign exchange exposure on U.S. dollar denominated oil and gas
sales. The following contracts are outstanding at October 22, 2014:
| Instrument Type(1) |
|
Monthly Notional Amount (US$ millions) |
|
Floor |
|
Ceiling |
|
Conditional
Ceiling(2) |
|
|
| Oct 1, 2014 – Dec 31, 2014 |
|
26.0 |
|
1.1064 |
|
1.1500 |
|
1.1212 |
|
| Jan 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. At
September 30, 2014, following the third settlement, Enerplus had US$21.6 million of remaining notional debt swapped. These foreign exchange swaps mature between
October 2014 and October 2015 in conjunction with the remaining principal repayments 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. These foreign exchange swaps mature between June 2017 and
June 2021 in conjunction with the principal repayments on the US$225.0 million senior notes.
Interest Rate Risk:
At September 30, 2014, approximately 95% of Enerplus' debt was based on fixed interest rates and 5% was based on floating interest rates. The
percentage of fixed interest rate debt has increased from prior periods due to the closing of US$200 million in additional senior notes at a fixed rate 3.79% rate of interest, with the proceeds
being used to pay down floating interest rate bank debt. At September 30, 2014 Enerplus did not have any interest rate derivatives outstanding.
Equity Price Risk:
Enerplus is exposed to equity price risk in relation to its cash settled long-term incentive plans detailed in Note 14.
Enerplus
has entered into various equity swaps maturing between 2014 and 2016 and has effectively fixed the future settlement cost on 950,000 shares at a weighted average price of
$14.92 per share.
38 ENERPLUS 2014 Q3
REPORT
(iii) Credit Risk
Credit risk represents the financial loss Enerplus would experience due to the potential non-performance of counterparties to its financial instruments.
Enerplus is exposed to credit risk mainly through its joint venture, marketing and financial counterparty receivables.
Enerplus
mitigates credit risk through credit management techniques, including conducting financial assessments to establish and monitor counterparties' credit worthiness, setting exposure limits,
monitoring exposures against these limits and obtaining financial assurances such as letters of credit, parental guarantees, or third party credit insurance where warranted. Enerplus monitors and
manages its concentration of counterparty credit risk on an ongoing basis.
Enerplus'
maximum credit exposure at the balance sheet date consists of the carrying amount of its non-derivative financial assets and the fair value of its derivative financial assets. At
September 30, 2014 approximately 70% of Enerplus' marketing receivables were with companies considered investment grade.
At
September 30, 2014 approximately $4.7 million or 2% 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 September 30, 2014 was $2.9 million
(December 31, 2013 – $2.8 million).
(iv) 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.
16) CONTINGENCIES AND COMMITMENTS
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 interim 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.
The
Company has entered into an additional transportation commitment for various pipelines in the Marcellus region. These contracts have varied terms, extend out as far as 2033, and comprise a total
commitment of approximately US$54.3 million.
ENERPLUS 2014 Q3
REPORT 39
17) SUPPLEMENTAL CASH FLOW INFORMATION
a) Changes in Non-Cash Operating Working Capital
| |
|
Three months ended September 30,
|
|
|
|
Nine months ended September 30,
|
|
|
| ($ thousands) |
|
|
2014 |
|
|
|
|
2013 |
|
|
|
|
2014 |
|
|
|
|
2013 |
|
|
|
|
|
| Accounts receivable |
|
$ |
6,858 |
|
|
|
$ |
17,522 |
|
|
|
$ |
(13,019 |
) |
|
|
$ |
2,325 |
|
|
| Other current assets |
|
|
(5,754 |
) |
|
|
|
(1,755 |
) |
|
|
|
(5,210 |
) |
|
|
|
(2,944 |
) |
|
| Accounts payable |
|
|
(11,539 |
) |
|
|
|
9,917 |
|
|
|
|
(48,481 |
) |
|
|
|
11,991 |
|
|
|
|
|
| |
|
$ |
(10,435 |
) |
|
|
$ |
25,684 |
|
|
|
$ |
(66,710 |
) |
|
|
$ |
11,372 |
|
|
|
|
|
b) Other
| |
|
Three months ended September 30,
|
|
|
Nine months ended September 30,
|
|
|
| ($ thousands) |
|
|
2014 |
|
|
|
|
2013 |
|
|
|
2014 |
|
|
|
2013 |
|
|
|
|
|
| Income taxes paid/(received) |
|
$ |
(254 |
) |
|
|
$ |
3,487 |
|
|
$ |
18,133 |
|
|
$ |
(1,403 |
) |
|
| Interest paid |
|
$ |
4,138 |
|
|
|
$ |
2,630 |
|
|
$ |
32,826 |
|
|
$ |
31,851 |
|
|
|
|
|
40 ENERPLUS 2014 Q3
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 September 30, 2014.
- 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 (1992 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 July 1, 2014 and ended on September 30, 2014 that has materially affected, or is reasonably likely to materially affect, the
issuer's ICFR.
Date:
November 7, 2014
|
|
|
(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 September 30, 2014.
- 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 (1992 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 July 1, 2014 and ended on September 30, 2014 that has materially affected, or is reasonably likely to materially affect, the
issuer's ICFR.
Date:
November 7, 2014
|
|
|
(signed by)
Robert J. Waters
Senior Vice President and Chief Financial Officer
Enerplus Corporation |
|
|
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FORM 52-109F2 CERTIFICATION OF INTERIM FILINGS FULL CERTIFICATE
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