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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 AUGUST, 2016
COMMISSION FILE NUMBER 1-15150
The Dome Tower
Suite 3000, 333 7th Avenue S.W.
Calgary, Alberta
Canada T2P 2Z1
(403) 298-2200
Indicate
by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.
Form 20-F
o Form 40-F ý
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1)
Yes
o No ý
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7)
Yes
o No ý
Indicate by check mark whether, by furnishing the information contained in this Form, the registrant is also thereby furnishing the information to the Commission pursuant to
Rule 12g3-2(b) under the securities Exchange Act of 1934.
Yes
o No ý
EXHIBIT INDEX
EXHIBIT
99.1 Management's Discussion and Analysis for the Second Quarter ended June 30, 2016
EXHIBIT
99.2 Unaudited Consolidated Financial Statements for the Second Quarter ended June 30, 2016
EXHIBIT
99.3 Certification of the Chief Executive Officer
EXHIBIT
99.4 Certification of the Chief Financial Officer
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
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ENERPLUS CORPORATION |
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BY: |
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/s/ David A. McCoy
David A. McCoy
Vice President, General Counsel & Corporate Secretary |
DATE: August 5, 2016
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EXHIBIT INDEX
SIGNATURE
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Exhibit 99.1
MD&A
MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A")
The following discussion and analysis of financial results is dated August 4, 2016 and is to be read in conjunction with:
-
- the
unaudited interim consolidated financial statements of Enerplus Corporation ("Enerplus" or the "Company") as at and for the three and six months ended
June 30, 2016 and 2015 (the "Interim Financial Statements");
-
- the
audited consolidated financial statements of Enerplus as at December 31, 2015 and 2014 and for the years ended December 31, 2015, 2014
and 2013; and
-
- our
MD&A for the year ended December 31, 2015 (the "Annual MD&A").
The
following MD&A contains forward-looking information and statements. We refer you to the end of the MD&A under "Forward-Looking Information and Statements" for further information. The following
MD&A also contains financial measures that do not have a standardized meaning as prescribed by accounting principles generally accepted in the United States of America ("U.S. GAAP"). See
"Non-GAAP Measures" at the end of the MD&A for further information.
BASIS OF PRESENTATION
The Interim Financial Statements and notes have been prepared in accordance with U.S. GAAP including the prior period comparatives. All amounts are
stated in Canadian dollars unless otherwise specified and all note references relate to the notes included in the Interim Financial Statements.
Where
applicable, natural gas has been converted to barrels of oil equivalent ("BOE") based on 6 Mcf:1 BOE and oil and natural gas liquids ("NGL") have been converted to
thousand cubic feet of gas equivalent ("Mcfe") based on 0.167 bbl:1 Mcfe. BOE and Mcfe measures are based on an energy equivalent conversion method primarily applicable at the
burner tip and do not represent a value equivalent at the wellhead. Given that the value ratio based on the current price of natural gas as compared to crude oil is significantly different from the
energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. Use of BOE and Mcfe in isolation may be misleading. All production volumes are
presented on a Company interest basis, being the Company's working interest share before deduction of any royalties paid to others, plus the Company's royalty interests unless otherwise stated.
Company interest is not a term defined in Canadian National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and
may not be comparable to information produced by other entities.
In
accordance with U.S. GAAP, oil and gas sales are presented net of royalties in our Interim Financial Statements. Under International Financial Reporting Standards, industry standard is to
present oil and gas sales before deduction of royalties and as such this MD&A presents production, oil and gas sales, and BOE measures on this basis to remain comparable with our peers.
OVERVIEW
During the second quarter, we continued to position ourselves to deliver profitable growth in a low commodity price environment. The proceeds from our equity
issuance and the ongoing success of our non-core asset divestment program allowed us to significantly reduce our debt and strengthen our balance sheet. Operationally, our assets continue to deliver
strong results with improving cost structures.
On
May 31, 2016, we completed an equity financing for 33,350,000 common shares at a price of $6.90 per share for gross proceeds of $230.1 million ($220.4 million net
of issue costs). Our non-core asset divestment program continued to provide significant liquidity, with proceeds of $92.7 million during the second quarter and total proceeds of approximately
$280.5 million to date in 2016. These proceeds were used to fully repay our drawn credit facility and fund the repurchase of an additional US$95 million of our senior notes during the
quarter, for a total repurchase of US$267 million of senior notes to date, at prices ranging from 90% of par to par value. Through these steps we have reduced our total debt net of cash by 45%
to $674.1 million at June 30, 2016 from $1,216.2 million at December 31, 2015.
Average
daily production for the second quarter was 93,659 BOE/day, at the high end of our annual average production guidance range, and as a result we are increasing the low end of our annual
guidance range to 92,000 BOE/day, with the upper end remaining at 94,000 BOE/day. We continue to expect to produce approximately
43,000 45,000 bbls/day of crude oil and natural gas liquids. Production decreased approximately 4% from the first quarter of 2016 largely due to the
first quarter sale of our Canadian Deep Basin natural gas properties, along with overall
8 ENERPLUS 2016 Q2
REPORT
decline
in Canadian production volumes as a result of lower capital spending. Production volumes in the U.S. remained flat compared to the prior quarter, with the impact of lower capital
spending offset by strong performance in the Marcellus and Fort Berthold areas.
We
maintained a disciplined capital program, spending $48.1 million during the second quarter and $91.4 million year to date, with the majority directed to our Fort Berthold properties.
We are modestly increasing our spending in Fort Berthold during the second half of the year to position ourselves for growth in 2017. We plan to spend an additional $15 million on three gross
completions and pre-spending on facilities, and are projecting our fourth quarter production to increase by approximately 1,000 BOE/day. As a result, we are increasing our 2016 capital guidance
to $215 million from $200 million, which is expected to be funded through internally generated cash flow at current forward strip commodity prices.
Operating
expenses came in below guidance of $8.50/BOE, totaling $60.5 million or $7.10/BOE during the second quarter. The decrease in operating costs was mainly due to the ongoing success of
our cost savings initiatives, reduced activity levels and continued improvement in pricing for materials and services, along with the divestment of higher cost Canadian properties. As a result, we are
reducing our annual guidance for operating expenses to $7.90/BOE from $8.50/BOE. Cash G&A expenses were also below guidance, totaling $14.6 million or $1.71/BOE compared to guidance of
$2.00/BOE, primarily due to a reduction in staff levels. Accordingly, we are revising our annual cash G&A expense guidance to $1.95/BOE from $2.00/BOE.
Our
commodity hedging program continued to provide funds flow protection, contributing cash gains of $21.6 million in the second quarter. We added additional downside protection during the
second quarter, and as of July 22, 2016, we have approximately 39% of our forecasted 2016 crude oil production, net of royalties, hedged for the remainder of 2016 and 2017. We
have also hedged approximately 29% of our forecasted 2016 natural gas production, net of royalties, for the remainder of 2016 and approximately 20% for 2017.
We
recorded a net loss of $168.6 million and funds flow of $76.0 million for the quarter. Second quarter earnings included gains of $74.7 million on asset divestments and
$12.2 million on the repurchase of senior notes. These gains were offset by a non-cash impairment charge of $148.7 million and a non-cash valuation allowance on our deferred tax asset of
$105.0 million as a result of the decline in the twelve month trailing average commodity prices.
RESULTS OF OPERATIONS
Production
Production for the second quarter totaled 93,659 BOE/day, at the high end of our annual average guidance range of
90,000 94,000 BOE/day. Compared to production in the first quarter of 2016 of 97,860 BOE/day, production decreased 4% primarily due to the first
quarter sale of Canadian Deep Basin natural gas properties with production of approximately 5,400 BOE/day.
Production
in the second quarter of 2016 decreased 13% from production levels of 107,429 BOE/day in the same period of 2015 primarily due to the sale of non-core properties with production of
approximately 9,000 BOE/day during the second half of 2015 and the first quarter of 2016. This excludes the June sale of approximately 2,300 BOE/day of non-core Canadian assets.
Production volumes from our Canadian assets were further impacted by the reduction in capital spending in 2015 and 2016, while strong performance from our U.S. assets offset any decline due to
lower spending.
As
a result of the sale of the Deep Basin natural gas properties and other non-core Canadian shallow gas properties, our crude oil and natural gas liquids weighting increased to 47% of our total
average daily production in the second quarter of 2016, from 46% in the first quarter of 2016 and 43% in the second quarter of 2015.
Average
daily production volumes for the three and six months ended June 30, 2016 and 2015 are outlined below:
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Three months ended June 30,
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Six months ended June 30,
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Average Daily Production Volumes |
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2016 |
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2015 |
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% Change |
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2016 |
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2015 |
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% Change |
|
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Crude oil (bbls/day) |
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39,079 |
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|
41,122 |
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(5%) |
|
|
39,294 |
|
|
40,243 |
|
(2%) |
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Natural gas liquids (bbls/day) |
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4,829 |
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|
5,145 |
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(6%) |
|
|
5,161 |
|
|
4,444 |
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16% |
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Natural gas (Mcf/day) |
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298,503 |
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366,971 |
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(19%) |
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307,827 |
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356,836 |
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(14%) |
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Total daily sales (BOE/day) |
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93,659 |
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|
107,429 |
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(13%) |
|
|
95,759 |
|
|
104,160 |
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(8%) |
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ENERPLUS 2016 Q2
REPORT 9
As a result of strong performance and higher natural gas prices expected in the Marcellus, and despite the sale of approximately 2,300 BOE/day of
non-core assets in June, we are increasing the lower end of our average annual production guidance to 92,000 94,000 BOE/day from
90,000 94,000 BOE/day. We are maintaining our annual crude oil and natural gas liquids production guidance of
43,000 45,000 bbls/day. This guidance does not include any additional acquisitions or divestments.
Pricing
The prices received for our crude oil and natural gas production directly impact our earnings, funds flow and financial condition. The following table compares
average prices from the first half of 2016 to the first half of 2015 and other periods indicated:
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Six months ended
June 30,
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Pricing (average for the period) |
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2016 |
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2015 |
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Q2 2016 |
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Q1 2016 |
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Q4 2015 |
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Q3 2015 |
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Q2 2015 |
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Benchmarks |
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|
|
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|
|
WTI crude oil (US$/bbl) |
|
$ |
39.52 |
|
|
|
$ |
53.29 |
|
|
|
$ |
45.59 |
|
|
|
$ |
33.45 |
|
$ |
42.18 |
|
$ |
46.43 |
|
$ |
57.94 |
|
|
|
AECO natural gas monthly index ($/Mcf) |
|
|
1.68 |
|
|
|
|
2.81 |
|
|
|
|
1.25 |
|
|
|
|
2.11 |
|
|
2.65 |
|
|
2.80 |
|
|
2.67 |
|
|
|
AECO natural gas daily index ($/Mcf) |
|
|
1.62 |
|
|
|
|
2.70 |
|
|
|
|
1.40 |
|
|
|
|
1.83 |
|
|
2.47 |
|
|
2.90 |
|
|
2.64 |
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|
|
NYMEX natural gas last day (US$/Mcf) |
|
|
2.02 |
|
|
|
|
2.81 |
|
|
|
|
1.95 |
|
|
|
|
2.09 |
|
|
2.27 |
|
|
2.77 |
|
|
2.64 |
|
|
|
USD/CDN average exchange rate |
|
|
1.33 |
|
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|
|
1.24 |
|
|
|
|
1.29 |
|
|
|
|
1.37 |
|
|
1.34 |
|
|
1.31 |
|
|
1.23 |
|
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|
USD/CDN period end exchange rate |
|
|
1.30 |
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1.25 |
|
|
|
|
1.30 |
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1.30 |
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|
1.38 |
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|
1.34 |
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|
1.25 |
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|
Enerplus selling price(1) |
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Crude oil ($/bbl) |
|
$ |
39.00 |
|
|
|
$ |
51.35 |
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|
|
$ |
46.48 |
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|
|
$ |
31.59 |
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$ |
43.04 |
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$ |
48.22 |
|
$ |
58.26 |
|
|
|
Natural gas liquids ($/bbl) |
|
|
13.37 |
|
|
|
|
21.55 |
|
|
|
|
15.67 |
|
|
|
|
11.34 |
|
|
16.61 |
|
|
13.51 |
|
|
20.88 |
|
|
|
Natural gas ($/Mcf) |
|
|
1.64 |
|
|
|
|
2.32 |
|
|
|
|
1.49 |
|
|
|
|
1.77 |
|
|
1.89 |
|
|
2.08 |
|
|
2.09 |
|
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|
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|
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Average differentials |
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|
MSW Edmonton WTI (US$/bbl) |
|
$ |
(3.39 |
) |
|
|
$ |
(4.93 |
) |
|
|
$ |
(3.09 |
) |
|
|
$ |
(3.69 |
) |
$ |
(2.44 |
) |
$ |
(3.42 |
) |
$ |
(3.06 |
) |
|
|
WCS Hardisty WTI (US$/bbl) |
|
|
(13.77 |
) |
|
|
|
(13.16 |
) |
|
|
|
(13.30 |
) |
|
|
|
(14.24 |
) |
|
(14.50 |
) |
|
(13.27 |
) |
|
(11.59 |
) |
|
|
Transco Leidy monthly NYMEX (US$/Mcf) |
|
|
(0.84 |
) |
|
|
|
(1.63 |
) |
|
|
|
(0.70 |
) |
|
|
|
(0.99 |
) |
|
(1.15 |
) |
|
(1.66 |
) |
|
(1.50 |
) |
|
|
TGP Z4 300L monthly NYMEX (US$/Mcf) |
|
|
(0.90 |
) |
|
|
|
(1.67 |
) |
|
|
|
(0.73 |
) |
|
|
|
(1.07 |
) |
|
(1.23 |
) |
|
(1.75 |
) |
|
(1.57 |
) |
|
|
AECO monthly NYMEX (US$/Mcf) |
|
|
(0.76 |
) |
|
|
|
(0.54 |
) |
|
|
|
(0.99 |
) |
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|
|
(0.56 |
) |
|
(0.28 |
) |
|
(0.63 |
) |
|
(0.47 |
) |
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Enerplus realized differentials(1) |
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Canada crude oil WTI (US$/bbl) |
|
$ |
(13.46 |
) |
|
|
$ |
(14.13 |
) |
|
|
$ |
(12.01 |
) |
|
|
$ |
(14.14 |
) |
$ |
(13.63 |
) |
$ |
(11.82 |
) |
$ |
(12.50 |
) |
|
|
Canada natural gas NYMEX (US$/Mcf) |
|
|
(0.74 |
) |
|
|
|
(0.46 |
) |
|
|
|
(0.86 |
) |
|
|
|
(0.63 |
) |
|
(0.42 |
) |
|
(0.43 |
) |
|
(0.46 |
) |
|
|
Bakken crude oil WTI (US$/bbl) |
|
|
(8.29 |
) |
|
|
|
(10.05 |
) |
|
|
|
(8.23 |
) |
|
|
|
(8.38 |
) |
|
(7.93 |
) |
|
(8.52 |
) |
|
(9.30 |
) |
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|
Marcellus natural gas NYMEX (US$/Mcf) |
|
|
(0.83 |
) |
|
|
|
(1.35 |
) |
|
|
|
(0.76 |
) |
|
|
|
(0.91 |
) |
|
(1.13 |
) |
|
(1.64 |
) |
|
(1.39 |
) |
|
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|
|
|
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|
- (1)
- Before
transportation costs, royalties and commodity derivative instruments.
CRUDE OIL AND NATURAL GAS LIQUIDS
Our average realized crude oil price during the second quarter was $46.48/bbl, an increase of 47% compared to the prior quarter as a result of the higher
benchmark crude oil prices and narrowing Canadian differentials. WTI crude oil prices increased by 36% to average US$45.59/bbl in the quarter due to improving seasonal demand for crude oil in the
U.S. combined with lower overall U.S. production. Canadian light and heavy crude oil differentials improved by 16% and 7%, respectively, when compared to the previous quarter, due to
industry wide production outages resulting from the severe wildfires in northern Alberta. These outages also helped U.S. Bakken crude oil differentials to improve by 2%. In the second quarter
our realized natural gas liquids price increased by 38% compared to the first quarter, in-line with the increases in benchmark crude oil and liquids prices during the quarter.
NATURAL
GAS
Our average realized natural gas price during the second quarter was $1.49/Mcf, 16% lower when compared to the prior quarter. Benchmark NYMEX and AECO monthly
natural gas prices in the second quarter fell by 7% and 41%, respectively, compared to the previous quarter due to high inventory levels as a result of one of the warmest winters on record.
Approximately 33% of our second quarter Canadian gas production was sold under fixed basis contracts. As a result, our realized Canadian natural gas price differential significantly outperformed the
AECO benchmark price, averaging US$0.86/Mcf below NYMEX during the quarter compared to the benchmark AECO monthly differential of US$0.99/Mcf below NYMEX.
10 ENERPLUS 2016 Q2
REPORT
Industry rig counts in the Marcellus region have fallen dramatically over the past year, resulting in lower production growth in Northeast Pennsylvania and improved price differentials to NYMEX.
Monthly differentials at Transco Leidy and TGP Zone 4 300 Leg improved by 29% and 32%, respectively, compared to the prior quarter and 53% compared to the second quarter of 2015.
In comparison, our realized Marcellus differential improved by 16% during the second quarter, and 45% compared to the same period last year, to average US$0.76/Mcf below NYMEX. With a portion of our
second quarter natural gas sales exposed to other regional prices that were seasonally weaker, our Marcellus realized differential did not improve as much as the local Leidy and TGP benchmarks.
FOREIGN
EXCHANGE
The Canadian dollar strengthened throughout the second quarter as a result of higher crude oil prices. The USD/CDN exchange rate was 1.30 USD/CDN at
June 30, 2016, and averaged 1.29 USD/CDN during the second quarter compared to 1.37 USD/CDN during the first quarter. The majority of our oil and natural gas sales are
based on U.S. dollar denominated indices, and a stronger Canadian dollar relative to the U.S. dollar decreases the amount of our realized sales. Because we report in Canadian dollars,
the fluctuations in the Canadian dollar also impact our U.S. dollar denominated costs, capital spending and the reported value of our U.S. dollar denominated debt.
Price Risk Management
We have a price risk management program that considers our overall financial position, the economics of our capital program and potential acquisitions. Since
our first quarter, we have added additional floor protection on a portion of our oil and natural gas production for 2016 and 2017.
As
of July 22, 2016, we have hedged 12,000 bbls/day of our expected crude oil production for the remainder of 2016 and 2017, which represents approximately 39% of our forecasted
2016 net crude oil production, after royalties. Price protection levels are shown in the table below. For the second half of 2016 and the full year of 2017, we have floor protection at an effective
price of US$57.82/bbl and US$50.00/bbl, respectively. When WTI prices settle below the sold put strike price in any given month, the three way collars provide protection of approximately US$12.73/bbl
and US$11.41/bbl above the WTI index prices in 2016 and 2017, respectively. Overall, we expect our crude oil related hedge contracts to protect a significant portion of our funds flow.
As
of July 22, 2016, we have hedged approximately 66,700 Mcf/day of our expected natural gas production for the remainder of 2016 consisting of a combination of NYMEX swaps and
collars. This represents approximately 29% of our forecasted natural gas production, after royalties. For 2017 we have hedged 45,000 Mcf/day or approximately 20% of our forecasted 2016 natural
gas production, after royalties, using three way collars. Price protection levels are shown in the table below. With regards to the NYMEX three way collars, when NYMEX prices settle below the sold put
strike price in any given month, the three way collars provide protection of approximately US$0.50/Mcf and US$0.69/Mcf above the NYMEX index price in 2016 and 2017, respectively.
The
following is a summary of our financial contracts in place at July 22, 2016, expressed as a percentage of our anticipated net 2016 production volumes:
|
|
WTI Crude Oil (US$/bbl)(1)
|
|
NYMEX Natural Gas (US$/Mcf)(1)
|
|
|
|
|
Jul 1, 2016
Dec 31, 2016 |
|
|
Jan 1, 2017
Dec 31, 2017 |
|
|
Jul 1, 2016
Oct 31, 2016 |
|
|
Nov 1, 2016
Dec 31, 2016 |
|
|
Jan 1, 2017
Dec 31, 2017 |
|
|
Sold Swaps |
|
|
|
|
|
|
|
$ |
2.53 |
|
$ |
2.48 |
|
|
|
|
% |
|
|
|
|
|
|
|
|
22% |
|
|
11% |
|
|
|
|
Three Way Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sold Puts |
|
$ |
45.09 |
|
$ |
38.59 |
|
$ |
2.50 |
|
$ |
2.50 |
|
$ |
2.03 |
|
% |
|
|
39% |
|
|
39% |
|
|
11% |
|
|
11% |
|
|
20% |
|
Purchased Puts |
|
$ |
57.82 |
|
$ |
50.00 |
|
$ |
3.00 |
|
$ |
3.00 |
|
$ |
2.72 |
|
% |
|
|
39% |
|
|
39% |
|
|
11% |
|
|
11% |
|
|
20% |
|
Sold Calls |
|
$ |
71.75 |
|
$ |
60.50 |
|
$ |
3.75 |
|
$ |
3.75 |
|
$ |
3.37 |
|
% |
|
|
39% |
|
|
39% |
|
|
11% |
|
|
11% |
|
|
20% |
|
|
- (1)
- Based
on weighted average price (before premiums), assuming average annual production of 93,000 BOE/day for 2016 and 2017 less royalties and production taxes of 22%
in aggregate.
ENERPLUS 2016 Q2
REPORT 11
ACCOUNTING FOR PRICE RISK MANAGEMENT
Commodity Risk Management Gains/(Losses) |
|
Three months ended June 30,
|
|
Six months ended June 30,
|
($ millions) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
|
|
|
|
Cash gains/(losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil |
|
$ |
16.4 |
|
|
|
$ |
56.7 |
|
|
|
$ |
52.9 |
|
|
|
$ |
127.2 |
|
|
|
Natural gas |
|
|
5.2 |
|
|
|
|
16.4 |
|
|
|
|
8.3 |
|
|
|
|
32.7 |
|
|
|
|
|
|
|
|
|
Total cash gains/(losses) |
|
$ |
21.6 |
|
|
|
$ |
73.1 |
|
|
|
$ |
61.2 |
|
|
|
$ |
159.9 |
|
|
Non-cash gains/(losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil |
|
$ |
(27.2 |
) |
|
|
$ |
(71.1 |
) |
|
|
$ |
(58.4 |
) |
|
|
$ |
(107.1 |
) |
|
|
Natural gas |
|
|
(16.3 |
) |
|
|
|
(21.8 |
) |
|
|
|
(11.2 |
) |
|
|
|
(22.2 |
) |
|
|
|
|
|
|
|
|
Total non-cash gains/(losses) |
|
$ |
(43.5 |
) |
|
|
$ |
(92.9 |
) |
|
|
$ |
(69.6 |
) |
|
|
$ |
(129.3 |
) |
|
|
|
|
|
|
|
|
Total gains/(losses) |
|
$ |
(21.9 |
) |
|
|
$ |
(19.8 |
) |
|
|
$ |
(8.4 |
) |
|
|
$ |
30.6 |
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
(Per BOE) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
|
|
|
|
Total cash gains/(losses) |
|
$ |
2.53 |
|
|
|
$ |
7.47 |
|
|
|
$ |
3.51 |
|
|
|
$ |
8.48 |
|
|
Total non-cash gains/(losses) |
|
|
(5.10 |
) |
|
|
|
(9.49 |
) |
|
|
|
(3.99 |
) |
|
|
|
(6.85 |
) |
|
|
|
|
|
|
|
|
Total gains/(losses) |
|
$ |
(2.57 |
) |
|
|
$ |
(2.02 |
) |
|
|
$ |
(0.48 |
) |
|
|
$ |
1.63 |
|
|
|
|
|
|
|
|
|
During the second quarter of 2016 we realized cash gains of $16.4 million on our crude oil contracts and $5.2 million on our natural gas
contracts. In comparison, during the second quarter of 2015 we realized cash gains of $56.7 million on our crude oil contracts and $16.4 million on our natural gas contracts. The cash
gains were due to contracts which provided floor protection above market prices.
As
the forward markets for crude oil and natural gas fluctuate and new contracts are executed and existing contracts are realized, changes in fair value are reflected as either a non-cash charge or
gain to earnings. At the end of the second quarter of 2016 the fair value of our crude oil contracts represented a net gain position of $9.0 million, while our natural gas contracts represented
a net loss position of $7.2 million. For the three and six months ended June 30, 2016, the change in the fair value of our crude oil contracts represented losses of
$27.2 million and $58.4 million, respectively, and our natural gas contracts represented losses of $16.3 million and $11.2 million, respectively.
Revenues
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
($ millions) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
|
|
|
|
Oil and natural gas sales |
|
$ |
212.7 |
|
|
|
$ |
298.4 |
|
|
|
$ |
383.2 |
|
|
|
$ |
542.5 |
|
|
Royalties |
|
|
(38.4 |
) |
|
|
|
(46.7 |
) |
|
|
|
(66.2 |
) |
|
|
|
(85.8 |
) |
|
|
|
|
|
|
|
|
Oil and natural gas sales, net of royalties |
|
$ |
174.3 |
|
|
|
$ |
251.7 |
|
|
|
$ |
317.0 |
|
|
|
$ |
456.7 |
|
|
|
|
|
|
|
|
|
Oil and natural gas revenues for the three and six months ended June 30, 2016 were $212.7 million and $383.2 million, respectively,
a decrease of 31% from the same periods in 2015. The decrease in revenue was a result of the decline in oil and natural gas prices over the respective periods, as well as the impact of lower
production volumes.
12 ENERPLUS 2016 Q2
REPORT
Royalties and Production Taxes
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
($ millions, except per BOE amounts) |
|
|
2016 |
|
|
|
2015 |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
|
|
|
|
|
Royalties |
|
$ |
38.4 |
|
|
$ |
46.7 |
|
|
$ |
66.2 |
|
|
$ |
85.8 |
|
Per BOE |
|
$ |
4.51 |
|
|
$ |
4.78 |
|
|
$ |
3.80 |
|
|
$ |
4.55 |
|
Production taxes |
|
$ |
8.6 |
|
|
$ |
14.2 |
|
|
$ |
16.0 |
|
|
$ |
25.0 |
|
Per BOE |
|
$ |
1.00 |
|
|
$ |
1.45 |
|
|
$ |
0.92 |
|
|
$ |
1.33 |
|
|
|
|
|
|
|
|
Royalties and production taxes |
|
$ |
47.0 |
|
|
$ |
60.9 |
|
|
$ |
82.2 |
|
|
$ |
110.8 |
|
Per BOE |
|
$ |
5.51 |
|
|
$ |
6.23 |
|
|
$ |
4.72 |
|
|
$ |
5.88 |
|
Royalties and production taxes (% of oil and natural gas sales) |
|
|
22% |
|
|
|
20% |
|
|
|
21% |
|
|
|
20% |
|
|
|
|
|
|
|
|
Royalties are paid to government entities, land owners and mineral rights owners. Production taxes include state production taxes, Pennsylvania impact fees,
freehold mineral taxes and Saskatchewan resource surcharges. A large percentage of our production is from U.S. properties where royalty rates are generally not as sensitive to commodity price
levels. During the three and six months ended June 30, 2016, royalties and production taxes decreased to $47.0 million and $82.2 million, respectively, from
$60.9 million and $110.8 million for the same periods in 2015, primarily due to lower realized prices and lower production volumes. Royalties and production taxes averaged 21% of oil and
natural gas sales before transportation costs in the first half of 2016 compared to 20% for the same period in 2015 due to increased production from our U.S. properties.
We
have revised our average royalty and production tax rate guidance to 22% of oil and gas sales for 2016 from 23%. We do not expect the recently announced Alberta modernized royalty framework to have
a significant impact on our Canadian royalties.
Operating Expenses
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
($ millions, except per BOE amounts) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
|
|
|
|
Cash operating expenses |
|
$ |
61.4 |
|
|
|
$ |
79.3 |
|
|
|
$ |
133.7 |
|
|
|
$ |
166.2 |
|
|
Non-cash (gains)/losses(1) |
|
|
(0.9 |
) |
|
|
|
(2.6 |
) |
|
|
|
(0.6 |
) |
|
|
|
(1.7 |
) |
|
|
Total operating expenses |
|
$ |
60.5 |
|
|
|
$ |
76.7 |
|
|
|
$ |
133.1 |
|
|
|
$ |
164.5 |
|
|
Per BOE |
|
$ |
7.10 |
|
|
|
$ |
7.85 |
|
|
|
$ |
7.64 |
|
|
|
$ |
8.72 |
|
|
|
|
|
|
|
|
|
- (1)
- Non-cash
(gains)/losses on fixed price electricity swaps.
For the three and six months ended June 30, 2016, operating expenses were $60.5 million and $133.1 million, respectively, a decrease
of 21% and 19% compared to the same periods in 2015. On a per BOE basis, operating costs for the three and six months ended June 30, 2016 were $7.10/BOE and $7.64/BOE, outperforming our
annual guidance of $8.50/BOE. The decrease in operating costs was mainly a result of our continued cost saving initiatives and the divestment of higher operating cost Canadian properties over the
last year.
Based
on cost savings to date, we are reducing our 2016 guidance for operating expenses to $7.90/BOE from $8.50/BOE.
Transportation Costs
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
($ millions, except per BOE amounts) |
|
|
2016 |
|
|
|
2015 |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
|
|
|
|
|
Transportation costs |
|
$ |
24.5 |
|
|
$ |
28.0 |
|
|
$ |
50.2 |
|
|
$ |
54.5 |
|
Per BOE |
|
$ |
2.87 |
|
|
$ |
2.87 |
|
|
$ |
2.88 |
|
|
$ |
2.89 |
|
|
|
|
|
|
|
|
For the three and six months ended June 30, 2016, transportation costs were $24.5 million ($2.87/BOE) and $50.2 million ($2.88/BOE),
respectively, compared to $28.0 million ($2.87/BOE) and $54.5 million ($2.89/BOE) for the same periods in 2015. The decrease in transportation costs was primarily due to lower
production.
We
are maintaining our 2016 guidance for transportation costs of $3.10/BOE. Although year to date transportation costs are below our annual guidance, effective August 2016 we have firm
transportation commitments for 30,000 Mcf/day of additional interstate pipeline capacity from the Marcellus region to downstream connections at pricing of US$0.71/Mcf.
ENERPLUS 2016 Q2
REPORT 13
Netbacks
The crude oil and natural gas classifications below contain properties according to their dominant production category. These properties may include associated
crude oil, natural gas or natural gas liquids volumes which have been converted to the equivalent BOE/day or Mcfe/day and as such, the revenue per BOE or per Mcfe may not correspond with the average
selling price under the "Pricing" section of this MD&A.
|
|
Three months ended June 30, 2016
|
Netbacks by Property Type |
|
|
Crude Oil |
|
|
Natural Gas |
|
|
Total |
|
|
|
Average Daily Production |
|
|
46,972 BOE/day |
|
|
280,122 Mcfe/day |
|
|
93,659 BOE/day |
|
|
|
|
Netback(1) $ per BOE or Mcfe |
|
|
(per BOE |
) |
|
(per Mcfe |
) |
|
(Per BOE |
) |
|
|
|
Oil and natural gas sales |
|
$ |
40.57 |
|
$ |
1.54 |
|
$ |
24.96 |
|
|
|
Royalties and production taxes |
|
|
(9.57 |
) |
|
(0.24 |
) |
|
(5.51 |
) |
|
|
Cash operating expenses |
|
|
(10.04 |
) |
|
(0.73 |
) |
|
(7.20 |
) |
|
|
Transportation costs |
|
|
(1.85 |
) |
|
(0.64 |
) |
|
(2.87 |
) |
|
|
|
Netback before hedging |
|
$ |
19.11 |
|
$ |
(0.07 |
) |
$ |
9.38 |
|
|
|
|
Cash gains/(losses) |
|
|
3.83 |
|
|
0.20 |
|
|
2.53 |
|
|
|
|
Netback after hedging |
|
$ |
22.94 |
|
$ |
0.13 |
|
$ |
11.91 |
|
|
|
|
Netback before hedging ($ millions) |
|
$ |
81.6 |
|
$ |
(1.8 |
) |
$ |
79.8 |
|
|
|
|
Netback after hedging ($ millions) |
|
$ |
98.0 |
|
$ |
3.4 |
|
$ |
101.4 |
|
|
|
|
|
Three months ended June 30, 2015
|
Netbacks by Property Type |
|
|
Crude Oil |
|
|
Natural Gas |
|
|
Total |
|
|
|
Average Daily Production |
|
|
49,058 BOE/day |
|
|
350,226 Mcfe/day |
|
|
107,429 BOE/day |
|
|
|
|
Netback(1) $ per BOE or Mcfe |
|
|
(per BOE |
) |
|
(per Mcfe |
) |
|
(Per BOE |
) |
|
|
|
Oil and natural gas sales |
|
$ |
52.17 |
|
$ |
2.06 |
|
$ |
30.53 |
|
|
|
Royalties and production taxes |
|
|
(12.15 |
) |
|
(0.21 |
) |
|
(6.23 |
) |
|
|
Cash operating expenses |
|
|
(11.27 |
) |
|
(0.91 |
) |
|
(8.12 |
) |
|
|
Transportation costs |
|
|
(1.68 |
) |
|
(0.64 |
) |
|
(2.87 |
) |
|
|
|
Netback before hedging |
|
$ |
27.07 |
|
$ |
0.30 |
|
$ |
13.31 |
|
|
|
|
Cash gains/(losses) |
|
|
12.69 |
|
|
0.52 |
|
|
7.47 |
|
|
|
|
Netback after hedging |
|
$ |
39.76 |
|
$ |
0.82 |
|
$ |
20.78 |
|
|
|
|
Netback before hedging ($ millions) |
|
$ |
121.0 |
|
$ |
9.2 |
|
$ |
130.2 |
|
|
|
|
Netback after hedging ($ millions) |
|
$ |
177.6 |
|
$ |
25.7 |
|
$ |
203.3 |
|
|
|
|
|
Six months ended June 30, 2016
|
Netbacks by Property Type |
|
|
Crude Oil |
|
|
Natural Gas |
|
|
Total |
|
|
|
Average Daily Production |
|
|
47,836 BOE/day |
|
|
287,538 Mcfe/day |
|
|
95,759 BOE/day |
|
|
|
|
Netback(1) $ per BOE or Mcfe |
|
|
(per BOE |
) |
|
(per Mcfe |
) |
|
(Per BOE |
) |
|
|
|
Oil and natural gas sales |
|
$ |
33.82 |
|
$ |
1.70 |
|
$ |
21.99 |
|
|
|
Royalties and production taxes |
|
|
(7.95 |
) |
|
(0.25 |
) |
|
(4.72 |
) |
|
|
Cash operating expenses |
|
|
(10.06 |
) |
|
(0.88 |
) |
|
(7.67 |
) |
|
|
Transportation costs |
|
|
(1.85 |
) |
|
(0.65 |
) |
|
(2.88 |
) |
|
|
|
Netback before hedging |
|
$ |
13.96 |
|
$ |
(0.08 |
) |
$ |
6.72 |
|
|
|
|
Cash gains/(losses) |
|
|
6.08 |
|
|
0.16 |
|
|
3.51 |
|
|
|
|
Netback after hedging |
|
$ |
20.04 |
|
$ |
0.08 |
|
$ |
10.23 |
|
|
|
|
Netback before hedging ($ millions) |
|
$ |
121.5 |
|
$ |
(4.4 |
) |
$ |
117.1 |
|
|
|
|
Netback after hedging ($ millions) |
|
$ |
174.5 |
|
$ |
3.8 |
|
$ |
178.3 |
|
|
|
14 ENERPLUS 2016 Q2
REPORT
|
|
Six months ended June 30, 2015
|
Netbacks by Property Type |
|
|
Crude Oil |
|
|
Natural Gas |
|
|
Total |
|
|
|
Average Daily Production |
|
|
46,916 BOE/day |
|
|
343,464 Mcfe/day |
|
|
104,160 BOE/day |
|
|
|
|
Netback(1) $ per BOE or Mcfe |
|
|
(per BOE |
) |
|
(per Mcfe |
) |
|
(Per BOE |
) |
|
|
|
Oil and natural gas sales |
|
$ |
46.98 |
|
$ |
2.31 |
|
$ |
28.78 |
|
|
|
Royalties and production taxes |
|
|
(10.99 |
) |
|
(0.28 |
) |
|
(5.88 |
) |
|
|
Cash operating expenses |
|
|
(12.31 |
) |
|
(0.99 |
) |
|
(8.81 |
) |
|
|
Transportation costs |
|
|
(1.82 |
) |
|
(0.63 |
) |
|
(2.89 |
) |
|
|
|
Netback before hedging |
|
$ |
21.86 |
|
$ |
0.41 |
|
$ |
11.20 |
|
|
|
|
Cash gains/(losses) |
|
|
14.98 |
|
|
0.53 |
|
|
8.48 |
|
|
|
|
Netback after hedging |
|
$ |
36.84 |
|
$ |
0.94 |
|
$ |
19.68 |
|
|
|
|
Netback before hedging ($ millions) |
|
$ |
185.6 |
|
$ |
25.4 |
|
$ |
211.0 |
|
|
|
|
Netback after hedging ($ millions) |
|
$ |
312.9 |
|
$ |
58.0 |
|
$ |
370.9 |
|
|
|
- (1)
- See
"Non-GAAP Measures" in this MD&A.
Crude oil and natural gas netbacks per BOE decreased for the three and six months ended June 30, 2016 compared to the same periods in 2015
primarily due to lower commodity prices and lower realized hedging gains. Our crude oil properties accounted for substantially all of our netback, both before and after hedging.
General and Administrative Expenses
Total G&A expenses include cash G&A expenses and share-based compensation ("SBC") charges related to our long-term incentive plans ("LTI plans") and our
stock option plan. See Note 10 and Note 14 to the Interim Financial Statements for further details.
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
($ millions) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
|
|
|
|
Cash: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
G&A expense |
|
$ |
14.6 |
|
|
|
$ |
19.9 |
|
|
|
$ |
33.0 |
|
|
|
$ |
41.3 |
|
|
|
Share-based compensation expense |
|
|
0.8 |
|
|
|
|
(1.2 |
) |
|
|
|
1.5 |
|
|
|
|
6.0 |
|
|
Non-Cash: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share-based compensation expense |
|
|
5.4 |
|
|
|
|
4.6 |
|
|
|
|
8.9 |
|
|
|
|
9.6 |
|
|
|
Equity swap loss/(gain) |
|
|
(1.6 |
) |
|
|
|
1.0 |
|
|
|
|
(1.7 |
) |
|
|
|
(0.6 |
) |
|
|
|
|
|
|
|
|
Total G&A expenses |
|
$ |
19.2 |
|
|
|
$ |
24.3 |
|
|
|
$ |
41.7 |
|
|
|
$ |
56.3 |
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
(Per BOE) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
|
|
|
|
Cash: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
G&A expense |
|
$ |
1.71 |
|
|
|
$ |
2.03 |
|
|
|
$ |
1.89 |
|
|
|
$ |
2.19 |
|
|
|
Share-based compensation expense |
|
|
0.09 |
|
|
|
|
(0.13 |
) |
|
|
|
0.09 |
|
|
|
|
0.32 |
|
|
Non-Cash: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share-based compensation expense |
|
|
0.63 |
|
|
|
|
0.47 |
|
|
|
|
0.51 |
|
|
|
|
0.51 |
|
|
|
Equity swap loss/(gain) |
|
|
(0.18 |
) |
|
|
|
0.11 |
|
|
|
|
(0.10 |
) |
|
|
|
(0.03 |
) |
|
|
|
|
|
|
|
|
Total G&A expenses |
|
$ |
2.25 |
|
|
|
$ |
2.48 |
|
|
|
$ |
2.39 |
|
|
|
$ |
2.99 |
|
|
|
|
|
|
|
|
|
For the three and six months ended June 30, 2016, cash G&A expenses were $14.6 million ($1.71/BOE) and $33.0 million ($1.89/BOE),
respectively, compared to $19.9 million ($2.03/BOE) and $41.3 million ($2.19/BOE) for the same periods in 2015. The decrease in cash G&A expenses from the prior year was primarily due to
a 30% reduction in staff levels throughout 2015 and to date in 2016, offset by one-time severance payments, as we continue to respond to the current commodity price environment.
ENERPLUS 2016 Q2
REPORT 15
During
the quarter, our share price increased by 67% resulting in a cash SBC expense of $0.8 million ($0.09/BOE) compared to a recovery of $1.2 million ($0.13/BOE) in the same period of
2015. We recorded non-cash SBC of $5.4 million ($0.63/BOE) in the second quarter compared to $4.6 million ($0.47/BOE) during the same period in 2015. The increase in non-cash SBC was due
to the additional expense related to the 2016 grant.
We
have hedged a portion of the outstanding cash settled grants under our LTI plans. As a result of the increase in our share price during the quarter we recorded a non-cash mark-to-market gain of
$1.6 million on these hedges. As of June 30, 2016 we had 470,000 units hedged at a weighted average price of $16.89 per share.
Based
on our continued focus on costs, we are reducing our 2016 guidance for cash G&A expenses to $1.95/BOE from $2.00/BOE.
Interest Expense
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
($ millions) |
|
|
2016 |
|
|
|
2015 |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
|
|
|
|
|
Interest on senior notes and bank facility |
|
$ |
10.0 |
|
|
$ |
15.9 |
|
|
$ |
24.6 |
|
|
$ |
32.7 |
|
Non-cash interest expense |
|
|
0.6 |
|
|
|
0.2 |
|
|
|
0.8 |
|
|
|
0.5 |
|
|
|
|
|
|
|
|
Total interest expense |
|
$ |
10.6 |
|
|
$ |
16.1 |
|
|
$ |
25.4 |
|
|
$ |
33.2 |
|
|
|
|
|
|
|
|
For the three and six months ended June 30, 2016, we recorded total interest expense of $10.6 million and $25.4 million,
respectively, compared to $16.1 million and $33.2 million for the same periods in 2015. The decrease in interest expense corresponds to a decrease in the
aggregate principal amount of our outstanding senior notes following our repurchase of US$267 million of senior notes during the first half of 2016. The repurchase of senior notes was funded by
asset divestment proceeds and lower interest rate bank debt, which was repaid in full following our May 31, 2016 equity financing and the closing of our previously announced Canadian
non-core asset divestment.
At
June 30, 2016, our bank credit facility was undrawn, and our debt balance consisted solely of fixed interest rate senior notes with a weighted average interest rate of 5.0%.
Foreign Exchange
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
($ millions) |
|
|
2016 |
|
|
|
2015 |
|
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
|
|
|
|
Realized loss/(gain) |
|
$ |
0.3 |
|
|
$ |
8.4 |
|
|
|
$ |
2.0 |
|
|
|
$ |
(27.2 |
) |
|
Unrealized loss/(gain) |
|
|
0.1 |
|
|
|
(36.1 |
) |
|
|
|
(56.0 |
) |
|
|
|
103.7 |
|
|
|
|
|
|
|
|
|
Total foreign exchange loss/(gain) |
|
$ |
0.4 |
|
|
$ |
(27.7 |
) |
|
|
$ |
(54.0 |
) |
|
|
$ |
76.5 |
|
|
|
USD/CDN average exchange rate |
|
|
1.29 |
|
|
|
1.23 |
|
|
|
|
1.33 |
|
|
|
|
1.24 |
|
|
|
|
|
|
|
|
|
For the three and six months ended June 30, 2016, we recorded a net foreign exchange loss of $0.4 million and a net foreign exchange gain
of $54.0 million, respectively, compared to a gain of $27.7 million and a loss of $76.5 million for the same periods in 2015. Realized losses related to day-to-day transactions
recorded in foreign currencies. During the six months ended June 30, 2015 we recorded realized gains of $27.2 million primarily due to a $39.9 million gain on the unwind of
certain foreign exchange swaps offset by losses on our foreign exchange collars.
Unrealized
foreign exchange gains and losses are recorded on the translation of our U.S. dollar denominated debt and working capital at each period end. Comparing June 30, 2016 to
December 31, 2015, the Canadian dollar strengthened relative to the U.S. dollar resulting in unrealized gains of $56.0 million. See Note 12 to the Interim
Financial Statements for further details.
16 ENERPLUS 2016 Q2
REPORT
Capital Investment
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
($ millions) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
|
|
|
|
Capital spending |
|
$ |
48.1 |
|
|
|
$ |
148.0 |
|
|
|
$ |
91.4 |
|
|
|
$ |
315.0 |
|
|
Office capital |
|
|
0.1 |
|
|
|
|
1.4 |
|
|
|
|
0.1 |
|
|
|
|
2.3 |
|
|
|
|
|
|
|
|
|
Sub-total |
|
|
48.2 |
|
|
|
|
149.4 |
|
|
|
|
91.5 |
|
|
|
|
317.3 |
|
|
|
|
|
|
|
|
|
Property and land acquisitions |
|
$ |
0.3 |
|
|
|
$ |
(1.0 |
) |
|
|
$ |
3.9 |
|
|
|
$ |
(1.2 |
) |
|
Property divestments |
|
|
(92.7 |
) |
|
|
|
(187.8 |
) |
|
|
|
(280.5 |
) |
|
|
|
(191.5 |
) |
|
|
|
|
|
|
|
|
Sub-total |
|
|
(92.4 |
) |
|
|
|
(188.8 |
) |
|
|
|
(276.6 |
) |
|
|
|
(192.7 |
) |
|
|
|
|
|
|
|
|
Total |
|
$ |
(44.2 |
) |
|
|
$ |
(39.4 |
) |
|
|
$ |
(185.1 |
) |
|
|
$ |
124.6 |
|
|
|
|
|
|
|
|
|
Capital spending for the three and six months ended June 30, 2016, totaled $48.1 million and $91.4 million, respectively, compared
to $148.0 million and $315.0 million for the same periods in 2015. The decrease is in-line with our reduced spending program for 2016, as we continue to invest modestly in our core
areas. During the second quarter we spent $30.4 million on our Fort Berthold crude oil properties, $7.1 million on our Canadian crude properties and $9.4 million on our Marcellus
assets.
In
June 2016, we completed the previously announced sale of non-core properties in northwest Alberta for proceeds of $92.7 million, net of closing costs, with estimated 2016 production
of approximately 2,300 BOE/day. In comparison, during the second quarter of 2015, we sold non-core assets with proceeds of $187.8 million, including our Pembina waterflood assets. Year
to date, we have recorded total proceeds on asset divestments of $280.5 million, compared to $191.5 million in the same period of 2015.
We
are increasing our 2016 capital guidance by $15 million to $215 million to begin to position ourselves for growth in 2017. The incremental capital will be directed to Fort Berthold,
and includes the addition of three gross completions as well as pre-spending on our facilities during the second half of the year. We expect the additional spending to increase our fourth quarter
production by approximately 1,000 BOE/day and to be funded through internally generated cash flow at current forward strip commodity prices.
Gain on Asset Sales and Note Repurchases
We recorded a gain of $74.7 million on the sale of non-core Canadian properties during the second quarter of 2016, bringing our year to date gain on
asset divestments to $219.8 million. Under full cost accounting rules, divestitures of oil and natural gas properties are generally accounted for as adjustments to the full cost pool with no
recognition of a gain or loss. However, if not recognizing a gain or loss on the transaction would significantly alter the relationship between a cost centre's capitalized costs and proved reserves,
then a gain or loss must be recognized. Gains and losses are evaluated on a case by case basis for each asset sale, and future sales may or may not result in such treatment.
During
the second quarter of 2016, we recorded a gain of $12.2 million on the repurchase of US$95 million of outstanding senior notes at a discount to par value. Year to date, we have
repurchased a total of US$267 million of senior notes at prices between 90% of par and par value, resulting in a total gain of $19.3 million.
Depletion, Depreciation and Accretion ("DD&A")
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
($ millions, except per BOE amounts) |
|
|
2016 |
|
|
|
2015 |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
|
|
|
|
|
DD&A expense |
|
$ |
82.3 |
|
|
$ |
137.4 |
|
|
$ |
173.5 |
|
|
$ |
269.8 |
|
Per BOE |
|
$ |
9.66 |
|
|
$ |
14.06 |
|
|
$ |
9.95 |
|
|
$ |
14.31 |
|
|
|
|
|
|
|
|
DD&A of property, plant and equipment ("PP&E") is recognized using the unit-of-production method based on proved reserves. For the three and six months ended
June 30, 2016, DD&A decreased when compared the same periods of 2015 primarily due to the cumulative effects of asset impairments recorded during 2015 and the first quarter
of 2016.
ENERPLUS 2016 Q2
REPORT 17
Impairment
Under U.S. GAAP, the full cost ceiling test is performed on a country-by-country basis using estimated after-tax future net cash flows discounted at
10 percent from proved reserves using SEC constant prices ("Standardized Measure"). SEC prices are calculated as the unweighted average of the trailing twelve first-day-of-the-month commodity
prices. The Standardized Measure is not related to Enerplus' investment criteria and is not a fair value based measurement, but rather a prescribed accounting calculation. Under U.S. GAAP,
impairments are not reversed in future periods.
The
trailing twelve month average crude oil and natural gas prices continued to decline in the first half of 2016 but less significantly than in 2015. Non-cash impairments of $148.7 million and
$194.9 million were recorded for the three and six months ended June 30, 2016, respectively, compared to $497.2 million and $764.9 million in the same periods
of 2015.
Many
factors influence the allowed ceiling value versus our net capitalized cost base, making it difficult to predict with reasonable certainty the value of impairment losses from future ceiling
tests. For the remainder of this year, the primary factors include future first-day-of-the-month commodity prices, reserves revisions, our capital expenditure levels and timing, acquisition and
divestment activity, as well as production levels, which affect DD&A expense. Although the trailing twelve month average commodity prices are near current levels, there is the potential for prices to
decline further during 2016, impacting the ceiling value and resulting in further non-cash impairments. See Note 5 to the Interim Financial Statements for trailing twelve
month prices.
Asset Retirement Obligation
In connection with our operations we incur abandonment and reclamation costs related to assets such as surface leases, wells, facilities and pipelines. Total
asset retirement obligations included on our balance sheet are based on our net ownership interest and management's estimate of costs to abandon and reclaim and the timing of the costs to be incurred
in future periods. We have estimated the net present value of our asset retirement obligation to be $188.2 million at June 30, 2016, compared to $206.4 million at
December 31, 2015. For the three and six months ended June 30, 2016, asset retirement obligation settlements were $0.8 million and $3.2 million, respectively,
compared to $2.6 million and $6.5 million during the same periods in 2015. As a result of our divestments to date in 2016, we have reduced our asset retirement obligation by
$22.6 million.
Income Taxes
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
($ millions) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
|
|
|
|
Current tax expense/(recovery) |
|
$ |
(0.2 |
) |
|
|
$ |
(0.1 |
) |
|
|
$ |
(0.4 |
) |
|
|
$ |
|
|
|
Deferred tax expenses/(recovery) |
|
|
53.3 |
|
|
|
|
(221.7 |
) |
|
|
|
309.8 |
|
|
|
|
(360.1 |
) |
|
|
|
|
|
|
|
|
Total tax expense/(recovery) |
|
$ |
53.1 |
|
|
|
$ |
(221.8 |
) |
|
|
$ |
309.4 |
|
|
|
$ |
(360.1 |
) |
|
|
|
|
|
|
|
|
For the three and six months ended June 30, 2016 we recorded total tax expense of $53.1 million and $309.4 million, respectively,
compared to a tax recovery of $221.8 million and $360.1 million for the same periods in 2015. The current quarter expense includes an additional valuation
allowance of $105.0 million recorded against our deferred income tax asset, partially offset by a recovery due to the non-cash asset impairment expense recorded in the U.S. and Canada. We
assess the recoverability of our deferred income tax assets each period to determine whether it is more likely than not that all or a portion of our deferred income tax assets will be realized. Our
assessment is primarily based on a projection of undiscounted future taxable income using historical trailing twelve month benchmark prices. After recording the valuation allowance, our overall net
deferred income tax asset was $186.7 million at June 30, 2016 compared to $516.1 million at December 31, 2015.
18 ENERPLUS 2016 Q2
REPORT
LIQUIDITY AND CAPITAL RESOURCES
There are numerous factors that influence how we assess our liquidity and leverage including commodity price cycles, capital spending levels, acquisition and
divestment plans, hedging and dividend levels. We also assess our leverage relative to our most restrictive debt covenant under our bank credit facility and senior notes, which is a maximum senior
debt to earnings before interest, taxes, depreciation, amortization, impairment and other non-cash charges ("adjusted EBITDA") ratio of 3.5x for a period of up to six months, after which it drops to
3.0x. At June 30, 2016, our senior debt to adjusted EBITDA ratio was 1.2x and our debt to funds flow ratio was 2.0x. Although it is not included in our debt covenants, the debt to funds
flow ratio is often used by investors and analysts to evaluate our liquidity.
We
have continued to be diligent in managing and preserving our financial position. On May 31, 2016 we completed an equity financing for 33,350,000 common shares at a price of
$6.90 per share for gross proceeds of $230.1 million ($220.4 million net of issue costs). Our non-core asset divestment program continued to provide significant liquidity, with proceeds
of $92.7 million during the second quarter and total proceeds of approximately $280.5 million to date in 2016. These proceeds were used to fully repay our drawn credit facility and fund
the repurchase of US$95 million of our senior notes during the quarter, and a total of US$267 million of senior notes to date. The senior note repurchases were completed at prices
ranging from 90% of par to par value, resulting in a total gain of $19.3 million for the six months ended June 30, 2016. Furthermore, as a result of the note repurchases we expect
to save approximately US$13 million in interest expense on an annualized basis.
Following
the equity financing and non-core asset divestments, total debt net of cash at June 30, 2016 was $674.1 million, a decrease of 45% compared to $1,216.2 million at
December 31, 2015. At June 30, 2016, we had $723.3 million of senior notes outstanding less $49.2 million in cash and our $800 million bank credit
facility was undrawn.
We
continued to maintain our financial flexibility through an ongoing focus on cost efficiencies and disciplined capital spending. Our adjusted payout ratio, which is calculated as cash dividends plus
capital and office expenditures divided by funds flow, was 72% and 96% for the three and six months ended June 30, 2016, compared to 112% and 147% for the same periods in 2015. After
adjusting for net acquisition and divestment proceeds, we had a funding surplus of $282.0 million for the six months ended June 30, 2016.
Our
working capital deficiency, excluding cash and current deferred financial assets and liabilities, decreased to $88.5 million at June 30, 2016 from $104.0 million at
December 31, 2015. We expect to finance our working capital deficit and our ongoing working capital requirements through cash, funds flow and our bank credit facility. We have sufficient
liquidity to meet our financial commitments, as disclosed under "Commitments" in the Annual MD&A.
At
June 30, 2016, we were in compliance with all covenants under our bank credit facility and outstanding senior notes. Based on our current guidance, we expect to manage our business
within these financial ratios; however, current oil and gas prices have created a significant level of uncertainty which may challenge the assumptions and estimates used in management's forecast. If
we exceed any of the covenants, we may be required to repay, refinance or renegotiate the terms of the debt. If we reach or exceed these covenant thresholds, there are a number of steps that may be
taken to improve them, including asset divestments, a reduction to capital spending and equity issuances.
Our
bank credit facility and senior note purchase agreements have been filed as material documents on our SEDAR profile at www.sedar.com.
The
following table lists our financial covenants as at June 30, 2016:
Covenant Description |
|
|
|
|
June 30, 2016 |
|
|
|
|
Bank Credit Facility: |
|
Maximum Ratio |
|
|
|
|
Senior debt to adjusted EBITDA(1) |
|
3.5 x |
|
|
1.2 x |
|
Total debt to adjusted EBITDA |
|
4.0 x |
|
|
1.2 x |
|
Total debt to capitalization |
|
50% |
|
|
29% |
|
Senior Notes: |
|
Maximum Ratio |
|
|
|
|
Senior debt to adjusted EBITDA(2) |
|
3.0 x 3.5 x |
|
|
1.2 x |
|
Senior debt to consolidated present value of total proved reserves(3) |
|
60% |
|
|
32% |
|
|
|
Minimum Ratio |
|
|
|
|
Adjusted EBITDA to interest |
|
4.0 x |
|
|
10.3 x |
|
|
|
|
ENERPLUS 2016 Q2
REPORT 19
Definitions
"Senior debt" is calculated as the sum of drawn amounts on our bank credit facility, outstanding letters of credit and the principal amount of
senior notes.
"Adjusted EBITDA" is calculated as net income less interest, taxes, depletion, depreciation, amortization, impairment and
other non-cash gains and losses. Adjusted EBITDA is calculated on a trailing twelve month basis and is adjusted for material acquisitions and divestments. Adjusted EBITDA for the three months and the
trailing twelve months ended June 30, 2016 were $170.7 million and $603.2 million, respectively.
"Total debt" is calculated as the sum of senior debt plus subordinated debt. Enerplus currently does not have any
subordinated debt.
"Capitalization" is calculated as the sum of total debt and shareholder's equity plus a $1.1 billion adjustment
related to our adoption of U.S. GAAP.
Footnotes
- (1)
- See "Non-GAAP Measures" in this MD&A for a reconciliation of adjusted EBITDA to net income.
- (2)
- Senior
debt to adjusted EBITDA may increase to 3.5x for a period of 6 months for the senior notes, after which the ratio decreases to 3.0x.
- (3)
- Senior
debt to consolidated present value of total proved reserves is calculated annually on December 31 based on before tax reserves at forecast prices discounted
at 10%.
Dividends
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
($ millions, except per share amounts) |
|
|
2016 |
|
|
|
2015 |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
|
|
|
|
|
Dividends to shareholders |
|
$ |
6.5 |
|
|
$ |
30.9 |
|
|
$ |
21.0 |
|
|
$ |
78.3 |
|
Per weighted average share (Basic) |
|
$ |
0.03 |
|
|
$ |
0.15 |
|
|
$ |
0.10 |
|
|
$ |
0.38 |
|
|
|
|
|
|
|
|
During the three and six months ended June 30, 2016, we reported total dividends of $6.5 million or $0.03 per share and
$21.0 million or $0.10 per share, respectively, compared to $30.9 million or $0.15 per share and $78.3 million or $0.38 per share for the same periods in 2015.
Effective
with the April 2016 payment, we reduced the monthly dividend by 67% from $0.03 per share to $0.01 per share to provide additional financial flexibility and to balance funds flow with
capital and dividends. The dividend is an important part of our strategy to create shareholder value and we will continue to monitor commodity prices and economic conditions and are prepared to make
adjustments as necessary.
Shareholders' Capital
|
|
Six months ended June 30,
|
|
|
|
2016 |
|
|
|
2015 |
|
|
|
|
Share capital ($ millions) |
|
$ |
3,366.0 |
|
|
$ |
3,126.6 |
|
Common shares outstanding (thousands) |
|
|
240,483 |
|
|
|
206,224 |
|
Weighted average shares outstanding basic (thousands) |
|
|
212,420 |
|
|
|
206,028 |
|
Weighted average shares outstanding diluted (thousands) |
|
|
212,420 |
|
|
|
206,028 |
|
|
|
|
On May 31, 2016, 33,350,000 common shares were issued at a price of $6.90 per share for gross proceeds of $230.1 million
($220.4 million net of issue costs).
During
the second quarter no shares were issued pursuant to the stock option plan and the treasury settled LTI plans, resulting in no additional equity for the company
(2015 45,000; $0.6 million). For the six months ended June 30, 2016 a total of 594,000 shares were issued pursuant to the treasury
settled Restricted Share Unit plan resulting in $9.4 million of additional equity (2015 492,000; $6.3 million). For further details see
Note 14 to the Interim Financial Statements.
At
August 4, 2016 we had 240,483,000 shares outstanding.
20 ENERPLUS 2016 Q2
REPORT
SELECTED CANADIAN AND U.S. FINANCIAL RESULTS
|
|
Three months ended June 30, 2016
|
|
Three months ended June 30, 2015
|
($ millions, except per unit amounts) |
|
|
Canada |
|
|
U.S. |
|
|
Total |
|
|
|
|
Canada |
|
|
U.S. |
|
|
Total |
|
|
|
|
|
Average Daily Production Volumes(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/day) |
|
|
13,497 |
|
|
25,582 |
|
|
39,079 |
|
|
|
|
15,462 |
|
|
25,660 |
|
|
41,122 |
|
|
|
Natural gas liquids (bbls/day) |
|
|
1,418 |
|
|
3,411 |
|
|
4,829 |
|
|
|
|
2,136 |
|
|
3,009 |
|
|
5,145 |
|
|
|
Natural gas (Mcf/day) |
|
|
79,878 |
|
|
218,625 |
|
|
298,503 |
|
|
|
|
144,788 |
|
|
222,183 |
|
|
366,971 |
|
|
|
|
|
|
|
|
Total average daily production (BOE/day) |
|
|
28,228 |
|
|
65,431 |
|
|
93,659 |
|
|
|
|
41,730 |
|
|
65,699 |
|
|
107,429 |
|
|
|
|
|
|
|
Pricing(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (per bbl) |
|
$ |
43.27 |
|
$ |
48.18 |
|
$ |
46.48 |
|
|
|
$ |
55.86 |
|
$ |
59.71 |
|
$ |
58.26 |
|
|
|
Natural gas liquids (per bbl) |
|
|
25.14 |
|
|
11.74 |
|
|
15.67 |
|
|
|
|
33.58 |
|
|
11.87 |
|
|
20.88 |
|
|
|
Natural gas (per Mcf) |
|
|
1.41 |
|
|
1.52 |
|
|
1.49 |
|
|
|
|
2.68 |
|
|
1.70 |
|
|
2.09 |
|
|
Capital Expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital spending |
|
$ |
7.2 |
|
$ |
40.9 |
|
$ |
48.1 |
|
|
|
$ |
24.6 |
|
$ |
123.4 |
|
$ |
148.0 |
|
|
|
Acquisitions |
|
|
1.0 |
|
|
(0.7 |
) |
|
0.3 |
|
|
|
|
0.8 |
|
|
(1.8 |
) |
|
(1.0 |
) |
|
|
Divestments |
|
|
(91.1 |
) |
|
(1.6 |
) |
|
(92.7 |
) |
|
|
|
(187.1 |
) |
|
(0.7 |
) |
|
(187.8 |
) |
|
Netback(3) Before Hedging |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales |
|
$ |
66.6 |
|
$ |
146.1 |
|
$ |
212.7 |
|
|
|
$ |
120.7 |
|
$ |
177.7 |
|
$ |
298.4 |
|
|
|
Royalties |
|
|
(9.7 |
) |
|
(28.7 |
) |
|
(38.4 |
) |
|
|
|
(11.7 |
) |
|
(35.0 |
) |
|
(46.7 |
) |
|
|
Production taxes |
|
|
(0.1 |
) |
|
(8.5 |
) |
|
(8.6 |
) |
|
|
|
(0.9 |
) |
|
(13.3 |
) |
|
(14.2 |
) |
|
|
Cash operating expenses |
|
|
(31.4 |
) |
|
(30.0 |
) |
|
(61.4 |
) |
|
|
|
(49.3 |
) |
|
(30.0 |
) |
|
(79.3 |
) |
|
|
Transportation costs |
|
|
(3.9 |
) |
|
(20.6 |
) |
|
(24.5 |
) |
|
|
|
(5.8 |
) |
|
(22.2 |
) |
|
(28.0 |
) |
|
|
|
|
|
|
|
Netback before hedging |
|
$ |
21.5 |
|
$ |
58.3 |
|
$ |
79.8 |
|
|
|
$ |
53.0 |
|
$ |
77.2 |
|
$ |
130.2 |
|
|
|
|
|
|
|
Other Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments loss/(gain) |
|
$ |
21.9 |
|
$ |
|
|
$ |
21.9 |
|
|
|
$ |
19.8 |
|
$ |
|
|
$ |
19.8 |
|
|
|
General and administrative expense(4) |
|
|
14.7 |
|
|
4.5 |
|
|
19.2 |
|
|
|
|
19.2 |
|
|
5.1 |
|
|
24.3 |
|
|
|
Current income tax expense/(recovery) |
|
|
(0.4 |
) |
|
0.2 |
|
|
(0.2 |
) |
|
|
|
(0.4 |
) |
|
0.3 |
|
|
(0.1 |
) |
|
|
|
|
ENERPLUS 2016 Q2
REPORT 21
|
|
Six months ended June 30, 2016
|
|
Six months ended June 30, 2015
|
($ millions, except per unit amounts) |
|
|
Canada |
|
|
U.S. |
|
|
Total |
|
|
|
|
Canada |
|
|
U.S. |
|
|
Total |
|
|
|
|
|
Average Daily Production Volumes(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/day) |
|
|
13,841 |
|
|
25,453 |
|
|
39,294 |
|
|
|
|
16,213 |
|
|
24,030 |
|
|
40,243 |
|
|
|
Natural gas liquids (bbls/day) |
|
|
1,612 |
|
|
3,549 |
|
|
5,161 |
|
|
|
|
2,247 |
|
|
2,197 |
|
|
4,444 |
|
|
|
Natural gas (Mcf/day) |
|
|
89,708 |
|
|
218,119 |
|
|
307,827 |
|
|
|
|
140,129 |
|
|
216,707 |
|
|
356,836 |
|
|
|
|
|
|
|
|
Total average daily production (BOE/day) |
|
|
30,404 |
|
|
65,355 |
|
|
95,759 |
|
|
|
|
41,816 |
|
|
62,345 |
|
|
104,160 |
|
|
|
|
|
|
|
Pricing(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (per bbl) |
|
$ |
34.70 |
|
$ |
41.33 |
|
$ |
39.00 |
|
|
|
$ |
48.37 |
|
$ |
53.56 |
|
$ |
51.35 |
|
|
|
Natural gas liquids (per bbl) |
|
|
25.05 |
|
|
8.07 |
|
|
13.37 |
|
|
|
|
31.26 |
|
|
11.62 |
|
|
21.55 |
|
|
|
Natural gas (per Mcf) |
|
|
1.74 |
|
|
1.59 |
|
|
1.64 |
|
|
|
|
2.90 |
|
|
1.95 |
|
|
2.32 |
|
|
Capital Expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital spending |
|
$ |
26.3 |
|
$ |
65.1 |
|
$ |
91.4 |
|
|
|
$ |
101.5 |
|
$ |
213.5 |
|
$ |
315.0 |
|
|
|
Acquisitions |
|
|
2.0 |
|
|
1.9 |
|
|
3.9 |
|
|
|
|
2.0 |
|
|
(3.2 |
) |
|
(1.2 |
) |
|
|
Divestments |
|
|
(279.4 |
) |
|
(1.1 |
) |
|
(280.5 |
) |
|
|
|
(188.0 |
) |
|
(3.5 |
) |
|
(191.5 |
) |
|
Netback(3) Before Hedging |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales |
|
$ |
123.3 |
|
$ |
259.9 |
|
$ |
383.2 |
|
|
|
$ |
228.6 |
|
$ |
313.9 |
|
$ |
542.5 |
|
|
|
Royalties |
|
|
(15.1 |
) |
|
(51.1 |
) |
|
(66.2 |
) |
|
|
|
(24.0 |
) |
|
(61.8 |
) |
|
(85.8 |
) |
|
|
Production taxes |
|
|
(0.9 |
) |
|
(15.1 |
) |
|
(16.0 |
) |
|
|
|
(2.7 |
) |
|
(22.3 |
) |
|
(25.0 |
) |
|
|
Cash operating expenses |
|
|
(74.9 |
) |
|
(58.8 |
) |
|
(133.7 |
) |
|
|
|
(106.4 |
) |
|
(59.8 |
) |
|
(166.2 |
) |
|
|
Transportation costs |
|
|
(7.5 |
) |
|
(42.7 |
) |
|
(50.2 |
) |
|
|
|
(12.0 |
) |
|
(42.5 |
) |
|
(54.5 |
) |
|
|
|
|
|
|
|
Netback before hedging |
|
$ |
24.9 |
|
$ |
92.2 |
|
$ |
117.1 |
|
|
|
$ |
83.5 |
|
$ |
127.5 |
|
$ |
211.0 |
|
|
|
|
|
|
|
Other Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative instruments loss/(gain) |
|
$ |
8.4 |
|
$ |
|
|
$ |
8.4 |
|
|
|
$ |
(30.6 |
) |
$ |
|
|
$ |
(30.6 |
) |
|
|
General and administrative expense(4) |
|
|
33.1 |
|
|
8.6 |
|
|
41.7 |
|
|
|
|
42.7 |
|
|
13.6 |
|
|
56.3 |
|
|
|
Current income tax expense/(recovery) |
|
|
(0.7 |
) |
|
0.3 |
|
|
(0.4 |
) |
|
|
|
(0.4 |
) |
|
0.4 |
|
|
|
|
|
|
|
|
- (1)
- Company
interest volumes.
- (2)
- Before
transportation costs, royalties and the effects of commodity derivative instruments.
- (3)
- See
"Non-GAAP Measures" section in this MD&A.
- (4)
- Includes
share-based compensation.
QUARTERLY FINANCIAL INFORMATION
|
|
|
Oil and
Natural Gas
Sales, Net of |
|
|
Net |
|
Net Income/(Loss) Per Share
|
($ millions, except per share amounts) |
|
|
Royalties |
|
|
Income/(Loss) |
|
|
Basic |
|
|
Diluted |
|
|
|
2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter |
|
$ |
174.3 |
|
$ |
(168.5 |
) |
$ |
(0.77 |
) |
$ |
(0.77 |
) |
|
First Quarter |
|
|
142.7 |
|
|
(173.7 |
) |
|
(0.84 |
) |
|
(0.84 |
) |
|
|
|
|
|
|
|
|
|
|
Total 2016 |
|
$ |
317.0 |
|
$ |
(342.2 |
) |
$ |
(1.61 |
) |
$ |
(1.61 |
) |
|
|
2015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fourth Quarter |
|
$ |
199.4 |
|
$ |
(625.0 |
) |
$ |
(3.03 |
) |
$ |
(3.03 |
) |
|
Third Quarter |
|
|
228.3 |
|
|
(292.7 |
) |
|
(1.42 |
) |
|
(1.42 |
) |
|
Second Quarter |
|
|
251.7 |
|
|
(312.5 |
) |
|
(1.52 |
) |
|
(1.52 |
) |
|
First Quarter |
|
|
205.0 |
|
|
(293.2 |
) |
|
(1.42 |
) |
|
(1.42 |
) |
|
|
|
|
|
|
|
|
|
|
Total 2015 |
|
$ |
884.4 |
|
$ |
(1,523.4 |
) |
$ |
(7.39 |
) |
$ |
(7.39 |
) |
|
|
2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fourth Quarter |
|
$ |
325.3 |
|
$ |
151.7 |
|
$ |
0.74 |
|
$ |
0.73 |
|
|
Third Quarter |
|
|
378.3 |
|
|
67.4 |
|
|
0.33 |
|
|
0.32 |
|
|
Second Quarter |
|
|
414.9 |
|
|
40.0 |
|
|
0.20 |
|
|
0.19 |
|
|
First Quarter |
|
|
407.7 |
|
|
40.0 |
|
|
0.20 |
|
|
0.19 |
|
|
|
|
|
|
|
|
|
|
|
Total 2014 |
|
$ |
1,526.2 |
|
$ |
299.1 |
|
$ |
1.46 |
|
$ |
1.44 |
|
|
|
22 ENERPLUS 2016 Q2
REPORT
Oil and gas sales, net of royalties, increased in the second quarter compared to the first quarter of 2016 due to higher realized crude oil prices partially
offset by lower natural gas prices and lower oil and gas production volumes. Oil and gas sales, net of royalties, increased during the first half of 2014, then decreased throughout 2015 and 2016 as
commodity prices declined. During 2015, the impact of weak commodity prices was somewhat offset by increasing production. Net losses reported in 2015 and 2016 were primarily due to non-cash asset
impairments and valuation allowances on our deferred tax asset related to the decrease in the trailing twelve month average commodity prices, along with reduced revenues.
U.S. Filing Status
Pursuant to U.S. securities regulations, we are required to reassess our U.S. securities filing status annually at June 30. As at
June 30, 2016, we continued to qualify as a foreign private issuer for the purposes of U.S. reporting requirements.
2016 UPDATED GUIDANCE
We have revised our full year 2016 guidance to reflect a modest increase in capital spend to support 2017 growth, stronger natural gas production from the
Marcellus, a lower expected overall royalty expense and reduced operating and G&A expenses. All other guidance has been maintained and is summarized below. This guidance includes the second quarter
sale of non-core natural gas properties located in northwest Alberta, but does not include any additional acquisitions or divestments.
Summary of 2016 Expectations |
|
Target |
|
|
Capital spending |
|
$215 million (from $200 million) |
|
Average annual production |
|
92,000 94,000 BOE/day (from 90,000 94,000 BOE/day) |
|
Crude oil and natural gas liquids volumes |
|
43,000 45,000 bbls/day |
|
Average royalty and production tax rate (% of oil and natural gas sales) |
|
22% (from 23%) |
|
Operating expenses |
|
$7.90/BOE (from $8.50/BOE) |
|
Transportation costs |
|
$3.10/BOE |
|
Cash G&A expenses |
|
$1.95/BOE (from $2.00/BOE) |
|
|
NON-GAAP MEASURES
The Company utilizes the following terms for measurement within the MD&A that do not have a standardized meaning or definition as prescribed by U.S. GAAP
and therefore may not be comparable with the calculation of similar measures by other entities:
"Netback" is used by Enerplus and is useful to investors and securities analysts in evaluating operating performance of our crude oil and natural gas
assets. Netback is calculated as oil and natural gas sales less royalties, production taxes, cash operating expenses and transportation costs.
Calculation of Netback |
|
Three months ended June 30,
|
|
Six months ended June 30,
|
($ millions) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
|
|
|
|
Oil and natural gas sales |
|
$ |
212.7 |
|
|
|
$ |
298.4 |
|
|
|
$ |
383.2 |
|
|
|
$ |
542.5 |
|
|
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalties |
|
|
(38.4 |
) |
|
|
|
(46.7 |
) |
|
|
|
(66.2 |
) |
|
|
|
(85.8 |
) |
|
|
Production taxes |
|
|
(8.6 |
) |
|
|
|
(14.2 |
) |
|
|
|
(16.0 |
) |
|
|
|
(25.0 |
) |
|
|
Cash operating expenses(1) |
|
|
(61.4 |
) |
|
|
|
(79.3 |
) |
|
|
|
(133.7 |
) |
|
|
|
(166.2 |
) |
|
|
Transportation costs |
|
|
(24.5 |
) |
|
|
|
(28.0 |
) |
|
|
|
(50.2 |
) |
|
|
|
(54.5 |
) |
|
|
|
|
|
|
|
|
Netback before hedging |
|
$ |
79.8 |
|
|
|
$ |
130.2 |
|
|
|
$ |
117.1 |
|
|
|
$ |
211.0 |
|
|
|
Cash gains/(losses) on derivative instruments |
|
|
21.6 |
|
|
|
|
73.1 |
|
|
|
|
61.2 |
|
|
|
|
159.9 |
|
|
|
|
|
|
|
|
|
Netback after hedging |
|
$ |
101.4 |
|
|
|
$ |
203.3 |
|
|
|
$ |
178.3 |
|
|
|
$ |
370.9 |
|
|
|
|
|
|
|
|
|
- (1)
- Total
operating expenses adjusted to exclude non-cash gains on fixed price electricity swaps of $0.9 million and $0.6 million in the three and six months ended
June 30, 2016 and $2.6 million and $1.7 million in the three and six months ended June 30, 2015.
ENERPLUS 2016 Q2
REPORT 23
"Funds Flow" is used by Enerplus and is useful to investors and securities analysts in analyzing operating
performance, leverage and liquidity. Funds flow is calculated as net cash from operating activities before asset retirement obligation expenditures and changes in non-cash operating working capital.
Reconciliation of Cash Flow from Operating Activities to Funds Flow |
|
Three months ended June 30,
|
|
Six months ended June 30,
|
($ millions) |
|
|
2016 |
|
|
|
2015 |
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
|
|
|
|
Cash flow from operating activities |
|
$ |
61.9 |
|
|
$ |
135.0 |
|
|
$ |
131.6 |
|
|
|
$ |
266.2 |
|
|
Asset retirement obligation expenditures |
|
|
0.7 |
|
|
|
2.6 |
|
|
|
3.2 |
|
|
|
|
6.5 |
|
|
Changes in non-cash operating working capital |
|
|
13.4 |
|
|
|
22.8 |
|
|
|
(17.0 |
) |
|
|
|
(3.1 |
) |
|
|
|
|
|
|
|
|
Funds flow |
|
$ |
76.0 |
|
|
$ |
160.4 |
|
|
$ |
117.8 |
|
|
|
$ |
269.6 |
|
|
|
|
|
|
|
|
|
"Debt to Funds Flow Ratio" is used by Enerplus and is useful to investors and securities analysts in analyzing
leverage and liquidity. The debt to funds flow ratio is calculated as total debt net of cash divided by a trailing twelve months of funds flow. This measure is not equivalent to debt to earnings
before interest, taxes, depreciation, amortization and other non-cash charges ("adjusted EBITDA") and is not a debt covenant.
"Adjusted Payout Ratio" is used by Enerplus and is useful to investors and securities analysts in analyzing operating performance, leverage and
liquidity. We calculate our adjusted payout ratio as cash dividends plus capital and office expenditures divided by funds flow.
Calculation of Adjusted Payout Ratio |
|
Three months ended June 30,
|
|
Six months ended June 30,
|
($ millions) |
|
|
2016 |
|
|
|
2015 |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
|
|
|
|
|
Dividends |
|
$ |
6.5 |
|
|
$ |
30.9 |
|
|
$ |
21.0 |
|
|
$ |
78.3 |
|
Capital and office expenditures |
|
|
48.2 |
|
|
|
149.4 |
|
|
|
91.5 |
|
|
|
317.3 |
|
|
|
|
|
|
|
|
Sub-total |
|
$ |
54.7 |
|
|
$ |
180.3 |
|
|
$ |
112.5 |
|
|
$ |
395.6 |
|
Funds flow |
|
$ |
76.0 |
|
|
$ |
160.4 |
|
|
$ |
117.8 |
|
|
$ |
269.6 |
|
|
Adjusted payout ratio (%) |
|
|
72% |
|
|
|
112% |
|
|
|
96% |
|
|
|
147% |
|
|
|
|
|
|
|
|
In addition, the Company uses certain financial measures within the "Liquidity and Capital Resources" section of this MD&A that do not have a standardized
meaning or definition as prescribed by U.S. GAAP and, therefore, may not be comparable with the calculation of similar measures by other entities. Such measures include "senior debt to adjusted
EBITDA", "total debt to adjusted EBITDA", "total debt to capitalization", "senior debt to consolidated present value of total proven reserves" and "adjusted EBITDA to interest" and are used to
determine the Company's compliance with financial covenants under its bank credit facility and outstanding senior notes. Calculation of such terms is described under the "Liquidity and Capital
Resources" section of this MD&A.
Reconciliation of Net Income to Adjusted EBITDA(1) ($ millions) |
|
|
June 30, 2016 |
|
|
|
Net income/(loss) |
|
$ |
(1,259.9 |
) |
|
Add: |
|
|
|
|
|
|
Interest |
|
|
59.6 |
|
|
|
Current and deferred tax expense/(recovery) |
|
|
502.0 |
|
|
|
DD&A and asset impairment |
|
|
1,193.4 |
|
|
|
Other non-cash charges(2) |
|
|
129.7 |
|
|
|
Sub-total |
|
$ |
624.8 |
|
|
Adjustment for material acquisitions and divestments(3) |
|
|
(21.6 |
) |
|
|
Adjusted EBITDA |
|
$ |
603.2 |
|
|
|
- (1)
- Adjusted
EBITDA is calculated based on the trailing four quarters. Balances above at June 30, 2016 include the six months ended June 30, 2016 and the third
and fourth quarters of 2015.
- (2)
- Includes
the change in fair value of commodity derivatives, fixed price electricity swaps and equity swaps, non-cash SBC, and unrealized foreign exchange gains/losses.
- (3)
- EBITDA
is adjusted for material acquisitions or divestments during the period with net proceeds greater than $50 million as if that acquisition or disposition had been made at
the beginning of the period.
24 ENERPLUS 2016 Q2
REPORT
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 Issuer's Annual and Interim Filings. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of Enerplus Corporation
have concluded that, as at June 30, 2016, our disclosure controls and procedures and internal control over financial reporting were effective. There were no changes in our internal
control over financial reporting during the period beginning on April 1, 2016 and ended June 30, 2016 that have materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting.
ADDITIONAL INFORMATION
Additional information relating to Enerplus, including our current Annual Information Form, is available under our profile on the SEDAR website at
www.sedar.com, on the EDGAR website at www.sec.gov and at www.enerplus.com.
FORWARD-LOOKING INFORMATION AND STATEMENTS
This MD&A contains certain forward-looking information and forward-looking statements within the meaning of applicable securities laws
("forward-looking information"). The use of any of the words "expect", "anticipate", "continue", "estimate", "guidance", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans",
"intends", "budget", "strategy" and similar expressions are intended to identify forward-looking information. In particular, but without limiting the foregoing, this MD&A contains forward-looking
information pertaining to the following: expected 2016 average production volumes and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged and the
effectiveness of such hedges in protecting our funds flow; the results from our drilling program and the timing of related production; oil and natural gas prices and differentials and our commodity
risk management programs in 2016 and 2017; expectations regarding our realized oil and natural gas prices; future royalty rates on our production and future
production taxes; anticipated cash and non-cash G&A, share-based compensation and financing expenses; operating and transportation costs; capital spending levels in 2016 and its impact on our
production level and land holdings; potential future asset and goodwill impairments, as well as the relevant factors that may affect such impairments; the amount of our future abandonment and
reclamation costs and asset retirement obligations; future environmental expenses; our future royalty and production and cash taxes; our deferred income taxes; future debt and working capital levels
and debt to funds flow ratio and adjusted payout ratio, financial capacity, liquidity and capital resources to fund capital spending and working capital requirements; expectations regarding our
ability to comply with debt covenants under our bank credit facility and outstanding senior notes, and to negotiate relief if required; our future acquisitions and divestments, expected timing
thereof, production and reductions in asset retirement obligations associated therewith and use of proceeds therefrom; expected gains for accounting purposes in respect to our repurchase of senior
notes and our asset divestments; anticipated amount of interest expense savings in respect to our repurchase of senior notes; and the amount of future cash dividends that we may pay to our
shareholders.
The forward-looking information contained in this MD&A reflects several material factors, expectations and assumptions including, without limitation: that we will conduct our
operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; that lack of adequate infrastructure will not result in curtailment of
production and/or reduced realized prices; current commodity price, differentials and cost assumptions; the general continuance of current or, where applicable, assumed industry conditions; the
continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve and contingent resource volumes; the continued availability of adequate debt and/or equity
financing and funds flow to fund our capital, operating and working capital requirements, and dividend payments as needed; the continued availability and sufficiency of our funds flow and availability
under our bank credit facility to fund our working capital deficiency; our ability to negotiate debt covenant relief under our bank credit facility and outstanding senior notes if required; the
availability of third party services; and the extent of our liabilities. In addition, our 2016 guidance contained in this MD&A is based on the following: a WTI price of US$42.61/bbl, a NYMEX price of
US$2.46/Mcf, an AECO price of $2.00/GJ and a USD/CDN exchange rate of 1.32. 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
ENERPLUS 2016 Q2
REPORT 25
those anticipated in such forward-looking information including, without limitation: continued low commodity prices environment or further decline of commodity prices; changes in realized prices of
Enerplus' products; changes in the demand for or supply of our products; unanticipated operating results, results from our capital spending activities or production declines; curtailment of our
production due to low realized prices or lack of adequate infrastructure; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in our capital plans or by third
party operators of our properties; increased debt levels or debt service requirements; inability to comply with debt covenants under our bank credit facility and outstanding senior notes; inaccurate
estimation of our oil and gas reserve and contingent resource volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact
of competitors; reliance on industry partners and third party service providers; and certain other risks detailed from time to time in our public disclosure documents (including, without limitation,
those risks and contingencies described under "Risk Factors and Risk Management" in the annual MD&A and in our other public filings).
The forward-looking information contained in this MD&A speaks only as of the date of this MD&A, and we do not assume any obligation to publicly update or revise such
forward-looking information to reflect new events or circumstances, except as may be required pursuant to applicable laws.
26 ENERPLUS 2016 Q2
REPORT
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Exhibit 99.2
STATEMENTS
Condensed Consolidated Balance Sheets
(CDN$ thousands) unaudited |
|
Note |
|
|
|
June 30, 2016 |
|
|
|
|
December 31, 2015 |
|
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash |
|
|
|
|
$ |
49,172 |
|
|
|
$ |
7,498 |
|
|
|
Accounts receivable |
|
3 |
|
|
|
102,990 |
|
|
|
|
132,156 |
|
|
|
Deferred financial assets |
|
15 |
|
|
|
14,228 |
|
|
|
|
71,438 |
|
|
|
Other current assets |
|
|
|
|
|
9,297 |
|
|
|
|
9,953 |
|
|
|
|
|
|
|
|
|
|
|
175,687 |
|
|
|
|
221,045 |
|
|
|
|
|
Property, plant and equipment: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties (full cost method) |
|
4 |
|
|
|
780,053 |
|
|
|
|
1,166,587 |
|
|
|
Other capital assets, net |
|
4 |
|
|
|
14,996 |
|
|
|
|
19,686 |
|
|
|
|
|
|
Property, plant and equipment |
|
|
|
|
|
795,049 |
|
|
|
|
1,186,273 |
|
|
|
|
|
Goodwill |
|
|
|
|
|
645,420 |
|
|
|
|
657,831 |
|
|
Deferred income tax asset |
|
13 |
|
|
|
186,667 |
|
|
|
|
516,085 |
|
|
|
|
|
Total Assets |
|
|
|
|
$ |
1,802,823 |
|
|
|
$ |
2,581,234 |
|
|
|
|
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
6 |
|
|
$ |
169,754 |
|
|
|
$ |
239,950 |
|
|
|
Dividends payable |
|
|
|
|
|
2,405 |
|
|
|
|
6,196 |
|
|
|
Current portion of long-term debt |
|
7 |
|
|
|
28,620 |
|
|
|
|
|
|
|
|
Deferred financial liabilities |
|
15 |
|
|
|
9,610 |
|
|
|
|
4,100 |
|
|
|
|
|
|
|
|
|
|
|
210,389 |
|
|
|
|
250,246 |
|
|
|
|
|
Deferred financial liabilities |
|
15 |
|
|
|
7,868 |
|
|
|
|
3,193 |
|
|
Long-term debt |
|
7 |
|
|
|
694,699 |
|
|
|
|
1,223,682 |
|
|
Asset retirement obligation |
|
8 |
|
|
|
188,207 |
|
|
|
|
206,359 |
|
|
|
|
|
|
|
|
|
|
|
890,774 |
|
|
|
|
1,433,234 |
|
|
|
|
|
Total Liabilities |
|
|
|
|
|
1,101,163 |
|
|
|
|
1,683,480 |
|
|
|
|
|
Shareholders' Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share capital authorized unlimited common shares, no par value
Issued and outstanding: June 30, 2016 240 million shares
December 31, 2015 206 million shares |
|
14 |
|
|
|
3,365,962 |
|
|
|
|
3,133,524 |
|
|
|
Paid-in capital |
|
|
|
|
|
55,589 |
|
|
|
|
56,176 |
|
|
|
Accumulated deficit |
|
|
|
|
|
(3,057,849 |
) |
|
|
|
(2,694,618 |
) |
|
|
Accumulated other comprehensive income/(loss) |
|
|
|
|
|
337,958 |
|
|
|
|
402,672 |
|
|
|
|
|
|
|
|
|
|
|
701,660 |
|
|
|
|
897,754 |
|
|
|
|
|
Total Liabilities & Equity |
|
|
|
|
$ |
1,802,823 |
|
|
|
$ |
2,581,234 |
|
|
|
|
|
Contingencies |
|
16 |
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes to the Condensed Consolidated Financial Statements are an integral part of these statements.
ENERPLUS 2016 Q2
REPORT 27
Condensed Consolidated Statements of Income/(Loss) and Comprehensive Income/(Loss)
|
|
|
|
|
Three months ended June 30,
|
|
|
|
Six months ended June 30,
|
|
|
(CDN$ thousands) unaudited |
|
Note |
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales, net of royalties |
|
9 |
|
|
$ |
174,330 |
|
|
|
$ |
251,730 |
|
|
|
$ |
316,991 |
|
|
|
$ |
456,690 |
|
|
Commodity derivative instruments gain/(loss) |
|
15 |
|
|
|
(21,907 |
) |
|
|
|
(19,751 |
) |
|
|
|
(8,443 |
) |
|
|
|
30,647 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
152,423 |
|
|
|
|
231,979 |
|
|
|
|
308,548 |
|
|
|
|
487,337 |
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
|
|
|
60,540 |
|
|
|
|
76,744 |
|
|
|
|
133,130 |
|
|
|
|
164,471 |
|
|
Transportation |
|
|
|
|
|
24,495 |
|
|
|
|
28,018 |
|
|
|
|
50,213 |
|
|
|
|
54,501 |
|
|
Production taxes |
|
|
|
|
|
8,541 |
|
|
|
|
14,220 |
|
|
|
|
15,977 |
|
|
|
|
25,033 |
|
|
General and administrative |
|
10 |
|
|
|
19,244 |
|
|
|
|
24,262 |
|
|
|
|
41,697 |
|
|
|
|
56,342 |
|
|
Depletion, depreciation and accretion |
|
|
|
|
|
82,322 |
|
|
|
|
137,403 |
|
|
|
|
173,483 |
|
|
|
|
269,753 |
|
|
Asset impairment |
|
5 |
|
|
|
148,679 |
|
|
|
|
497,247 |
|
|
|
|
194,856 |
|
|
|
|
764,858 |
|
|
Interest |
|
11 |
|
|
|
10,634 |
|
|
|
|
16,121 |
|
|
|
|
25,350 |
|
|
|
|
33,154 |
|
|
Foreign exchange (gain)/loss |
|
12 |
|
|
|
383 |
|
|
|
|
(27,656 |
) |
|
|
|
(54,025 |
) |
|
|
|
76,546 |
|
|
Gain on divestment of assets |
|
4 |
|
|
|
(74,700 |
) |
|
|
|
|
|
|
|
|
(219,800 |
) |
|
|
|
|
|
|
Gain on prepayment of senior notes |
|
7 |
|
|
|
(12,152 |
) |
|
|
|
|
|
|
|
|
(19,270 |
) |
|
|
|
|
|
|
Other expense/(income) |
|
|
|
|
|
(82 |
) |
|
|
|
(85 |
) |
|
|
|
(242 |
) |
|
|
|
8,527 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
267,904 |
|
|
|
|
766,274 |
|
|
|
|
341,369 |
|
|
|
|
1,453,185 |
|
|
|
|
|
|
|
|
|
Income/(Loss) before taxes |
|
|
|
|
|
(115,481 |
) |
|
|
|
(534,295 |
) |
|
|
|
(32,821 |
) |
|
|
|
(965,848 |
) |
|
Current income tax expense/(recovery) |
|
13 |
|
|
|
(227 |
) |
|
|
|
(102 |
) |
|
|
|
(386 |
) |
|
|
|
(39 |
) |
|
Deferred income tax expense/(recovery) |
|
13 |
|
|
|
53,300 |
|
|
|
|
(221,649 |
) |
|
|
|
309,785 |
|
|
|
|
(360,059 |
) |
|
|
|
|
|
|
|
|
Net Income/(Loss) |
|
|
|
|
$ |
(168,554 |
) |
|
|
$ |
(312,544 |
) |
|
|
$ |
(342,220 |
) |
|
|
$ |
(605,750 |
) |
|
|
|
|
|
|
|
|
Other Comprehensive Income/(Loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in cumulative translation adjustment |
|
|
|
|
|
1,654 |
|
|
|
|
(30,490 |
) |
|
|
|
(64,714 |
) |
|
|
|
146,269 |
|
|
|
|
|
|
|
|
|
Other Comprehensive Income/(Loss) |
|
|
|
|
|
1,654 |
|
|
|
|
(30,490 |
) |
|
|
|
(64,714 |
) |
|
|
|
146,269 |
|
|
|
|
|
|
|
|
|
Total Comprehensive Income/(Loss) |
|
|
|
|
$ |
(166,900 |
) |
|
|
$ |
(343,034 |
) |
|
|
$ |
(406,934 |
) |
|
|
$ |
(459,481 |
) |
|
|
|
|
|
|
|
|
Net income/(Loss) per share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
14 |
|
|
$ |
(0.77 |
) |
|
|
$ |
(1.52 |
) |
|
|
$ |
(1.61 |
) |
|
|
$ |
(2.94 |
) |
|
Diluted |
|
14 |
|
|
$ |
(0.77 |
) |
|
|
$ |
(1.52 |
) |
|
|
$ |
(1.61 |
) |
|
|
$ |
(2.94 |
) |
|
|
|
|
|
|
|
|
The accompanying notes to the Condensed Consolidated Financial Statements are an integral part of these statements.
28 ENERPLUS 2016 Q2
REPORT
Condensed Consolidated Statements of Changes
in Shareholders' Equity
Six months ended June 30 (CDN$ thousands) unaudited |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
Share Capital |
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year |
|
$ |
3,133,524 |
|
|
|
$ |
3,120,002 |
|
|
Issue of shares (net of issue costs) |
|
|
223,031 |
|
|
|
|
|
|
|
Stock Option Plan cash |
|
|
|
|
|
|
|
3,205 |
|
|
Share-based compensation settled |
|
|
9,407 |
|
|
|
|
3,094 |
|
|
Stock Option Plan exercised |
|
|
|
|
|
|
|
267 |
|
|
|
|
|
Balance, end of period |
|
$ |
3,365,962 |
|
|
|
$ |
3,126,568 |
|
|
|
|
|
Paid-in Capital |
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year |
|
$ |
56,176 |
|
|
|
$ |
46,906 |
|
|
Share-based compensation settled |
|
|
(9,407 |
) |
|
|
|
(3,094 |
) |
|
Stock Option Plan exercised |
|
|
|
|
|
|
|
(267 |
) |
|
Share-based compensation non-cash |
|
|
8,820 |
|
|
|
|
9,561 |
|
|
|
|
|
Balance, end of period |
|
$ |
55,589 |
|
|
|
$ |
53,106 |
|
|
|
|
|
Accumulated Deficit |
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year |
|
$ |
(2,694,618 |
) |
|
|
$ |
(1,039,260 |
) |
|
Net income/(loss) |
|
|
(342,220 |
) |
|
|
|
(605,750 |
) |
|
Dividends |
|
|
(21,011 |
) |
|
|
|
(78,294 |
) |
|
|
|
|
Balance, end of period |
|
$ |
(3,057,849 |
) |
|
|
$ |
(1,723,304 |
) |
|
|
|
|
Accumulated Other Comprehensive Income/(Loss) |
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year |
|
$ |
402,672 |
|
|
|
$ |
95,478 |
|
|
Change in cumulative translation adjustment |
|
|
(64,714 |
) |
|
|
|
146,269 |
|
|
|
|
|
Balance, end of period |
|
$ |
337,958 |
|
|
|
$ |
241,747 |
|
|
|
|
|
Total Shareholders' Equity |
|
$ |
701,660 |
|
|
|
$ |
1,698,117 |
|
|
|
|
|
The accompanying notes to the Condensed Consolidated Financial Statements are an integral part of these statements.
ENERPLUS 2016 Q2
REPORT 29
Condensed Consolidated Statements of Cash Flows
|
|
|
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
(CDN$ thousands) unaudited |
|
Note |
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
|
|
|
|
Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(loss) |
|
|
|
|
$ |
(168,554 |
) |
|
|
$ |
(312,544 |
) |
|
|
$ |
(342,220 |
) |
|
|
$ |
(605,750 |
) |
|
Non-cash items add/(deduct): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and accretion |
|
|
|
|
|
82,322 |
|
|
|
|
137,403 |
|
|
|
|
173,483 |
|
|
|
|
269,753 |
|
|
|
Asset impairment |
|
5 |
|
|
|
148,679 |
|
|
|
|
497,247 |
|
|
|
|
194,856 |
|
|
|
|
764,858 |
|
|
|
Changes in fair value of derivative instruments |
|
15 |
|
|
|
41,060 |
|
|
|
|
73,738 |
|
|
|
|
67,395 |
|
|
|
|
161,237 |
|
|
|
Deferred income tax expense/(recovery) |
|
13 |
|
|
|
53,300 |
|
|
|
|
(221,649 |
) |
|
|
|
309,785 |
|
|
|
|
(360,059 |
) |
|
|
Foreign exchange (gain)/loss on debt and working capital |
|
12 |
|
|
|
131 |
|
|
|
|
(18,590 |
) |
|
|
|
(56,027 |
) |
|
|
|
69,424 |
|
|
|
Share-based compensation |
|
14 |
|
|
|
5,391 |
|
|
|
|
4,591 |
|
|
|
|
8,820 |
|
|
|
|
9,561 |
|
|
|
Amortization of debt issue costs |
|
11 |
|
|
|
570 |
|
|
|
|
240 |
|
|
|
|
752 |
|
|
|
|
480 |
|
|
Gain on divestment of assets |
|
4 |
|
|
|
(74,700 |
) |
|
|
|
|
|
|
|
|
(219,800 |
) |
|
|
|
|
|
|
Gain on prepayment of senior notes |
|
7 |
|
|
|
(12,152 |
) |
|
|
|
|
|
|
|
|
(19,270 |
) |
|
|
|
|
|
|
Derivative settlement of foreign exchange swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(39,904 |
) |
|
Asset retirement obligation expenditures |
|
8 |
|
|
|
(750 |
) |
|
|
|
(2,569 |
) |
|
|
|
(3,204 |
) |
|
|
|
(6,459 |
) |
|
Changes in non-cash operating working capital |
|
17 |
|
|
|
(13,410 |
) |
|
|
|
(22,771 |
) |
|
|
|
17,064 |
|
|
|
|
3,051 |
|
|
|
|
|
|
|
|
|
Cash flow from/(used in) operating activities |
|
|
|
|
|
61,887 |
|
|
|
|
135,096 |
|
|
|
|
131,634 |
|
|
|
|
266,192 |
|
|
|
|
|
|
|
|
|
Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from the issuance of shares |
|
14 |
|
|
|
220,410 |
|
|
|
|
634 |
|
|
|
|
220,410 |
|
|
|
|
3,205 |
|
|
Cash dividends |
|
14 |
|
|
|
(6,547 |
) |
|
|
|
(30,935 |
) |
|
|
|
(21,011 |
) |
|
|
|
(78,294 |
) |
|
Increase/(decrease) in bank credit facility |
|
|
|
|
|
(150,073 |
) |
|
|
|
(45,386 |
) |
|
|
|
(79,223 |
) |
|
|
|
434 |
|
|
Proceeds/(repayment) of senior notes |
|
7 |
|
|
|
(109,371 |
) |
|
|
|
(88,897 |
) |
|
|
|
(335,400 |
) |
|
|
|
(88,897 |
) |
|
Derivative settlement of foreign exchange swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
39,904 |
|
|
Changes in non-cash financing working capital |
|
|
|
|
|
334 |
|
|
|
|
(15 |
) |
|
|
|
(3,791 |
) |
|
|
|
(8,222 |
) |
|
|
|
|
|
|
|
|
Cash flow from/(used in) financing activities |
|
|
|
|
|
(45,247 |
) |
|
|
|
(164,599 |
) |
|
|
|
(219,015 |
) |
|
|
|
(131,870 |
) |
|
|
|
|
|
|
|
|
Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital and office expenditures |
|
|
|
|
|
(48,206 |
) |
|
|
|
(149,439 |
) |
|
|
|
(91,498 |
) |
|
|
|
(317,327 |
) |
|
Property and land acquisitions |
|
|
|
|
|
(343 |
) |
|
|
|
1,011 |
|
|
|
|
(3,897 |
) |
|
|
|
1,247 |
|
|
Property divestments |
|
4 |
|
|
|
92,735 |
|
|
|
|
187,801 |
|
|
|
|
280,503 |
|
|
|
|
191,513 |
|
|
Changes in non-cash investing working capital |
|
|
|
|
|
(11,909 |
) |
|
|
|
(12,148 |
) |
|
|
|
(54,035 |
) |
|
|
|
(11,217 |
) |
|
|
|
|
|
|
|
|
Cash flow from/(used in) investing activities |
|
|
|
|
|
32,277 |
|
|
|
|
27,225 |
|
|
|
|
131,073 |
|
|
|
|
(135,784 |
) |
|
|
|
|
|
|
|
|
Effect of exchange rate changes on cash |
|
|
|
|
|
(1,026 |
) |
|
|
|
677 |
|
|
|
|
(2,018 |
) |
|
|
|
428 |
|
|
|
|
|
|
|
|
|
Change in cash |
|
|
|
|
|
47,891 |
|
|
|
|
(1,601 |
) |
|
|
|
41,674 |
|
|
|
|
(1,034 |
) |
|
Cash, beginning of period |
|
|
|
|
|
1,281 |
|
|
|
|
2,603 |
|
|
|
|
7,498 |
|
|
|
|
2,036 |
|
|
|
|
|
|
|
|
|
Cash, end of period |
|
|
|
|
$ |
49,172 |
|
|
|
$ |
1,002 |
|
|
|
$ |
49,172 |
|
|
|
$ |
1,002 |
|
|
|
|
|
|
|
|
|
The accompanying notes to the Condensed Consolidated Financial Statements are an integral part of these statements.
30 ENERPLUS 2016 Q2
REPORT
NOTES
Notes to Condensed Consolidated Financial Statements
(unaudited)
1) REPORTING ENTITY
These interim Condensed Consolidated Financial Statements ("interim Consolidated Financial Statements") and notes present the financial position and results of
Enerplus Corporation ("The Company" or "Enerplus") including its Canadian and U.S. subsidiaries. Enerplus is a North American crude oil and natural gas exploration and development
company. Enerplus is publicly traded on the Toronto and New York stock exchanges under the ticker symbol ERF. Enerplus' head office is located in Calgary, Alberta, Canada. The interim
Consolidated Financial Statements were authorized for issue by the Board of Directors on August 4, 2016.
2) BASIS OF PREPARATION
Enerplus' interim Consolidated Financial Statements present its results of operations and financial position under accounting principles generally accepted in
the United States of America ("U.S. GAAP") for the three and six months ended June 30, 2016 and the 2015 comparative periods. Certain information and notes normally
included with the annual audited Consolidated Financial Statements have been condensed or have been disclosed on an annual basis only. Accordingly, these interim Consolidated Financial Statements
should be read in conjunction with Enerplus' audited Consolidated Financial Statements as of December 31, 2015. There are no differences in the use of estimates or
judgments between these interim Consolidated Financial Statements and the audited Consolidated Financial Statements and notes thereto for the year ended December 31, 2015.
These
unaudited interim Consolidated Financial Statements reflect, in the opinion of Management, all normal and recurring adjustments necessary to present fairly the financial position and results of
the Company as at and for the periods presented.
3) ACCOUNTS RECEIVABLE
($ thousands) |
|
|
June 30, 2016 |
|
|
|
|
December 31, 2015 |
|
|
|
|
|
Accrued receivables |
|
$ |
85,367 |
|
|
|
$ |
91,378 |
|
|
Accounts receivable trade |
|
|
19,523 |
|
|
|
|
22,615 |
|
|
Current income tax receivable |
|
|
1,488 |
|
|
|
|
21,410 |
|
|
Allowance for doubtful accounts |
|
|
(3,388 |
) |
|
|
|
(3,247 |
) |
|
|
|
|
Total accounts receivable |
|
$ |
102,990 |
|
|
|
$ |
132,156 |
|
|
|
|
|
4) PROPERTY, PLANT AND EQUIPMENT ("PP&E")
As at June 30, 2016 ($ thousands) |
|
|
Cost |
|
|
Accumulated
Depletion,
Depreciation, and
Impairment |
|
|
Net Book Value |
|
|
Oil and natural gas properties |
|
$ |
13,204,112 |
|
$ |
(12,424,059 |
) |
$ |
780,053 |
|
Other capital assets |
|
|
104,155 |
|
|
(89,159 |
) |
|
14,996 |
|
|
Total PP&E |
|
$ |
13,308,267 |
|
$ |
(12,513,218 |
) |
$ |
795,049 |
|
|
As at December 31, 2015 ($ thousands) |
|
|
Cost |
|
|
Accumulated
Depletion,
Depreciation, and
Impairment |
|
|
Net Book Value |
|
|
Oil and natural gas properties |
|
$ |
13,541,670 |
|
$ |
(12,375,083 |
) |
$ |
1,166,587 |
|
Other capital assets |
|
|
105,124 |
|
|
(85,438 |
) |
|
19,686 |
|
|
Total PP&E |
|
$ |
13,646,794 |
|
$ |
(12,460,521 |
) |
$ |
1,186,273 |
|
|
ENERPLUS 2016 Q2
REPORT 31
During the three and six months ended June 30, 2016, Enerplus disposed of certain Canadian properties for proceeds of $92.7 million and
$280.5 million, respectively, which resulted in gains on asset divestments of $74.7 million and $219.8 million, respectively (2015 nil and
nil, respectively).
Under
full cost accounting rules, divestitures of oil and gas properties are generally accounted for as adjustments to capitalized costs, with no recognition of a gain or loss. However, if not
recognizing a gain or loss on the transaction would have otherwise significantly altered the relationship between a cost centre's capitalized costs and proved reserves, then a gain or loss must
be recognized.
5) ASSET IMPAIRMENT
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
($ thousands) |
|
|
2016 |
|
|
|
2015 |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
|
|
|
|
|
Oil and natural gas properties: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada cost centre |
|
$ |
34,200 |
|
|
$ |
28,100 |
|
|
$ |
34,200 |
|
|
$ |
28,100 |
|
|
U.S. cost centre |
|
|
114,479 |
|
|
|
469,147 |
|
|
|
160,656 |
|
|
|
736,758 |
|
|
|
|
|
|
|
|
Impairment expense |
|
$ |
148,679 |
|
|
$ |
497,247 |
|
|
$ |
194,856 |
|
|
$ |
764,858 |
|
|
|
|
|
|
|
|
The impairments for the three and six months ended June 30, 2016 were due to lower 12-month average trailing crude oil and natural
gas prices.
The
following table outlines the 12-month average trailing benchmark prices and exchange rates used in Enerplus' ceiling tests from June 30, 2015 through June 30, 2016:
Period |
|
|
WTI Crude Oil
US$/bbl |
|
Exchange Rate
US$/CDN$ |
|
|
Edm Light
Crude
CDN$/bbl |
|
|
U.S. Henry Hub
Gas
US$/Mcf |
|
|
AECO Natural
Gas Spot
CDN$/Mcf |
|
|
Q2 2016 |
|
$ |
43.12 |
|
1.32 |
|
$ |
53.16 |
|
$ |
2.25 |
|
$ |
2.14 |
|
Q1 2016 |
|
|
46.26 |
|
1.32 |
|
|
56.97 |
|
|
2.41 |
|
|
2.47 |
|
Q4 2015 |
|
|
50.28 |
|
1.27 |
|
|
59.38 |
|
|
2.58 |
|
|
2.69 |
|
Q3 2015 |
|
|
59.21 |
|
1.22 |
|
|
66.51 |
|
|
3.08 |
|
|
3.00 |
|
Q2 2015 |
|
|
71.75 |
|
1.16 |
|
|
75.83 |
|
|
3.42 |
|
|
3.33 |
|
|
6) ACCOUNTS PAYABLE
($ thousands) |
|
|
June 30, 2016 |
|
|
|
December 31, 2015 |
|
|
|
|
Accrued payables |
|
$ |
92,806 |
|
|
$ |
167,253 |
|
Accounts payable trade |
|
|
76,948 |
|
|
|
72,697 |
|
|
|
|
Total accounts payable |
|
$ |
169,754 |
|
|
$ |
239,950 |
|
|
|
|
7) DEBT
($ thousands) |
|
|
June 30, 2016 |
|
|
|
December 31, 2015 |
|
|
|
|
Current: |
|
|
|
|
|
|
|
|
|
Senior notes |
|
$ |
28,620 |
|
|
$ |
|
|
|
|
|
|
|
|
28,620 |
|
|
|
|
|
|
|
|
Long-term: |
|
|
|
|
|
|
|
|
|
Bank credit facility |
|
$ |
|
|
|
$ |
86,543 |
|
|
Senior notes |
|
|
694,699 |
|
|
|
1,137,139 |
|
|
|
|
|
|
|
694,699 |
|
|
|
1,223,682 |
|
|
|
|
Total debt |
|
$ |
723,319 |
|
|
$ |
1,223,682 |
|
|
|
|
32 ENERPLUS 2016 Q2
REPORT
For the three and six months ended June 30, 2016, Enerplus has repurchased US$95 million and US$267 million, respectively, in
outstanding senior notes at a discount, resulting in gains of $12.2 million and $19.3 million, respectively. These repurchases have resulted in total payments of $109.4 million
and $335.4 million for the three and six months ended June 30, 2016.
The
terms and rates of the Company's outstanding senior notes are provided below:
Issue Date |
|
Interest Payment Dates |
|
Principal Repayment |
|
Coupon
Rate |
|
Original
Principal ($ thousands) |
|
Remaining
Principal ($ thousands) |
|
|
|
CDN$ Carrying
Value ($ thousands) |
|
|
September 3, 2014 |
|
March 3 and Sept 3 |
|
5 equal annual installments
beginning September 3, 2022 |
|
3.79% |
|
US$200,000 |
|
US$105,000 |
|
|
$ |
136,534 |
|
May 15, 2012 |
|
May 15 and Nov 15 |
|
Bullet payment on May 15, 2019 |
|
4.34% |
|
CDN$30,000 |
|
CDN$30,000 |
|
|
|
30,000 |
|
May 15, 2012 |
|
May 15 and Nov 15 |
|
Bullet payment on May 15, 2022 |
|
4.40% |
|
US$20,000 |
|
US$20,000 |
|
|
|
26,018 |
|
May 15, 2012 |
|
May 15 and Nov 15 |
|
5 equal annual installments
beginning May 15, 2020 |
|
4.40% |
|
US$355,000 |
|
US$298,000 |
|
|
|
387,668 |
|
June 18, 2009 |
|
June 18 and Dec 18 |
|
5 equal annual installments
beginning June 18, 2017 |
|
7.97% |
|
US$225,000 |
|
US$110,000 |
|
|
|
143,099 |
|
|
|
|
|
|
|
|
|
|
Total carrying value |
|
|
$ |
723,319 |
|
|
8) ASSET RETIREMENT OBLIGATION
Enerplus has estimated the present value of its asset retirement obligation to be $188.2 million at June 30, 2016 compared to
$206.4 million at December 31, 2015 based on a total undiscounted liability of $472.4 million and $556.4 million, respectively. The asset retirement obligation was
calculated using a weighted credit-adjusted risk-free rate of 5.90% (December 31, 2015 5.91%).
($ thousands) |
|
|
Six months ended
June 30, 2016 |
|
|
|
|
Year ended
December 31, 2015 |
|
|
|
|
|
Balance, beginning of year |
|
$ |
206,359 |
|
|
|
$ |
288,692 |
|
|
Change in estimates |
|
|
1,819 |
|
|
|
|
(35,386 |
) |
|
Property acquisitions and development activity |
|
|
240 |
|
|
|
|
761 |
|
|
Divestments |
|
|
(22,648 |
) |
|
|
|
(48,748 |
) |
|
Settlements |
|
|
(3,204 |
) |
|
|
|
(14,935 |
) |
|
Accretion expense |
|
|
5,641 |
|
|
|
|
15,975 |
|
|
|
|
|
Balance, end of period |
|
$ |
188,207 |
|
|
|
$ |
206,359 |
|
|
|
|
|
9) OIL AND NATURAL GAS SALES
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
($ thousands) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
|
|
|
|
Oil and natural gas sales |
|
$ |
212,741 |
|
|
|
$ |
298,433 |
|
|
|
$ |
383,164 |
|
|
|
$ |
542,510 |
|
|
Royalties(1) |
|
|
(38,411 |
) |
|
|
|
(46,703 |
) |
|
|
|
(66,173 |
) |
|
|
|
(85,820 |
) |
|
|
|
|
|
|
|
|
Oil and natural gas sales, net of royalties |
|
$ |
174,330 |
|
|
|
$ |
251,730 |
|
|
|
$ |
316,991 |
|
|
|
$ |
456,690 |
|
|
|
|
|
|
|
|
|
- (1)
- Royalties
above do not include production taxes which are reported separately on the Condensed Consolidated Statements of Income/(Loss).
10) GENERAL AND ADMINISTRATIVE EXPENSE
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
($ thousands) |
|
|
2016 |
|
|
|
2015 |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
|
|
|
|
|
General and administrative expense |
|
$ |
14,600 |
|
|
$ |
19,872 |
|
|
$ |
33,026 |
|
|
$ |
41,307 |
|
Share-based compensation expense |
|
|
4,644 |
|
|
|
4,390 |
|
|
|
8,671 |
|
|
|
15,035 |
|
|
|
|
|
|
|
|
General and administrative expense |
|
$ |
19,244 |
|
|
$ |
24,262 |
|
|
$ |
41,697 |
|
|
$ |
56,342 |
|
|
|
|
|
|
|
|
ENERPLUS 2016 Q2
REPORT 33
11) INTEREST EXPENSE
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
($ thousands) |
|
|
2016 |
|
|
|
2015 |
|
|
|
2016 |
|
|
|
2015 |
|
|
|
|
|
|
|
|
Realized: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest on bank debt and senior notes |
|
$ |
10,064 |
|
|
$ |
15,881 |
|
|
$ |
24,598 |
|
|
$ |
32,674 |
|
Unrealized: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of debt issue costs |
|
|
570 |
|
|
|
240 |
|
|
|
752 |
|
|
|
480 |
|
|
|
|
|
|
|
|
Interest expense |
|
$ |
10,634 |
|
|
$ |
16,121 |
|
|
$ |
25,350 |
|
|
$ |
33,154 |
|
|
|
|
|
|
|
|
12) FOREIGN EXCHANGE
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
($ thousands) |
|
|
2016 |
|
|
|
2015 |
|
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
|
|
|
|
Realized: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign exchange (gain)/loss |
|
$ |
252 |
|
|
$ |
8,402 |
|
|
|
$ |
2,002 |
|
|
|
$ |
(27,172 |
) |
|
Unrealized: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Translation of U.S. dollar debt and working capital (gain)/loss |
|
|
131 |
|
|
|
(18,590 |
) |
|
|
|
(56,027 |
) |
|
|
|
69,424 |
|
|
|
Foreign exchange derivatives (gain)/loss |
|
|
|
|
|
|
(17,468 |
) |
|
|
|
|
|
|
|
|
34,294 |
|
|
|
|
|
|
|
|
|
Foreign exchange (gain)/loss |
|
$ |
383 |
|
|
$ |
(27,656 |
) |
|
|
$ |
(54,025 |
) |
|
|
$ |
76,546 |
|
|
|
|
|
|
|
|
|
13) INCOME TAXES
Enerplus' provision for income tax is as follows:
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
($ thousands) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
|
|
|
|
Current tax expense/(recovery) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
$ |
(366 |
) |
|
|
$ |
(400 |
) |
|
|
$ |
(669 |
) |
|
|
$ |
(400 |
) |
|
|
United States |
|
|
139 |
|
|
|
|
298 |
|
|
|
|
283 |
|
|
|
|
361 |
|
|
|
|
|
|
|
|
|
Current tax expense/(recovery) |
|
|
(227 |
) |
|
|
|
(102 |
) |
|
|
|
(386 |
) |
|
|
|
(39 |
) |
|
|
|
|
|
|
|
|
Deferred tax expense/(recovery) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
$ |
21,069 |
|
|
|
$ |
(27,676 |
) |
|
|
$ |
33,915 |
|
|
|
$ |
(36,939 |
) |
|
|
United States |
|
|
32,231 |
|
|
|
|
(193,973 |
) |
|
|
|
275,870 |
|
|
|
|
(323,120 |
) |
|
|
|
|
|
|
|
|
Deferred tax expense/(recovery) |
|
|
53,300 |
|
|
|
|
(221,649 |
) |
|
|
|
309,785 |
|
|
|
|
(360,059 |
) |
|
|
|
|
|
|
|
|
Income tax expense/(recovery) |
|
$ |
53,073 |
|
|
|
$ |
(221,751 |
) |
|
|
$ |
309,399 |
|
|
|
$ |
(360,098 |
) |
|
|
|
|
|
|
|
|
The difference between expected income taxes based on the statutory income tax rate and the effective income tax rate for the current and prior period is
impacted by the following: expected annual earnings, recognition of valuation allowance, foreign rate differentials for foreign operations, statutory and other rate differentials, the reversal or
recognition of previously recognized or unrecognized deferred tax assets, non-taxable portions of capital gains and losses, and non-deductible share-based compensation. Enerplus recorded valuation
allowances of $105.0 million and $363.5 million as at the three and six month periods ended June 30, 2016, respectively (2015 nil
and nil, respectively).
34 ENERPLUS 2016 Q2
REPORT
14) SHAREHOLDERS' EQUITY
a) Share Capital
|
|
Six months ended June 30, |
|
Year ended December 31, |
|
|
|
|
|
|
|
2016 |
|
2015 |
|
|
|
Authorized unlimited number of common shares Issued: (thousands) |
|
Shares |
|
|
Amount |
|
|
|
Shares |
|
|
Amount |
|
|
|
|
Balance, beginning of year |
|
206,539 |
|
$ |
3,133,524 |
|
|
|
205,732 |
|
$ |
3,120,002 |
|
Issued for cash: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Option Plan |
|
|
|
|
|
|
|
|
234 |
|
|
3,205 |
|
|
Issue of shares |
|
33,350 |
|
|
230,115 |
|
|
|
|
|
|
|
|
|
Share issue costs (net of tax of $2,620) |
|
|
|
|
(7,084 |
) |
|
|
|
|
|
|
|
Non-cash: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share-based compensation settled |
|
594 |
|
|
9,407 |
|
|
|
573 |
|
|
10,050 |
|
|
Stock Option Plan exercised |
|
|
|
|
|
|
|
|
|
|
|
267 |
|
|
|
|
Balance, end of period |
|
240,483 |
|
$ |
3,365,962 |
|
|
|
206,539 |
|
$ |
3,133,524 |
|
|
|
|
Dividends declared to shareholders for the three and six months ended June 30, 2016 were $6.5 million and $21.0 million,
respectively (2015 $30.9 million and $78.3 million, respectively).
On
May 31, 2016, Enerplus issued 33,350,000 common shares at a price of $6.90 per share for gross proceeds of $230,115,000 ($220,410,400 net of issue costs).
At
the Company's Annual General Meeting on May 6, 2016, the Shareholders of the Company approved a reduction in Enerplus' legal stated capital to $1 per share to be reflected in the
contributed surplus account of the Company. This transaction does not result in an adjustment to the financial statements under U.S. GAAP.
b) Share-based Compensation
The
following table summarizes Enerplus' share-based compensation expense, which is included in General and Administrative expense on the Consolidated Statements of Income/(Loss):
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
($ thousands) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
|
|
|
|
Cash: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term incentive plans expense |
|
$ |
773 |
|
|
|
$ |
(1,233 |
) |
|
|
$ |
1,506 |
|
|
|
$ |
6,041 |
|
|
Non-cash: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term incentive plans and stock option expense |
|
|
5,391 |
|
|
|
|
4,591 |
|
|
|
|
8,820 |
|
|
|
|
9,561 |
|
|
|
Equity swap (gain)/loss |
|
|
(1,520 |
) |
|
|
|
1,032 |
|
|
|
|
(1,655 |
) |
|
|
|
(567 |
) |
|
|
|
|
|
|
|
|
Share-based compensation expense |
|
$ |
4,644 |
|
|
|
$ |
4,390 |
|
|
|
$ |
8,671 |
|
|
|
$ |
15,035 |
|
|
|
|
|
|
|
|
|
i) Long-term Incentive ("LTI") Plans
In 2014, the Performance Share Unit ("PSU") and Restricted Share Unit ("RSU") plans were amended such that grants under the plans are settled through the
issuance of treasury shares. The amendment was effective beginning with our grant in March of 2014 and any prior grants were settled in cash. The final cash-settled PSU and RSU grants were settled in
December, 2015 and March, 2016, respectively. The Company's Director Share Units ("DSU") continue to be granted as cash-settled awards.
ENERPLUS 2016 Q2
REPORT 35
The
following table summarizes the PSU, RSU and DSU activity for the six months ended June 30, 2016:
For the six months ended
June 30, 2016 |
|
Cash-settled LTI plans
|
|
Equity-settled LTI plans
|
|
|
|
|
(thousands of units) |
|
RSU |
|
DSU |
|
PSU |
|
RSU |
|
Total |
|
|
|
Balance, beginning of year |
|
92 |
|
166 |
|
1,222 |
|
1,627 |
|
3,107 |
|
|
Granted |
|
|
|
134 |
|
1,417 |
|
1,987 |
|
3,538 |
|
|
Vested |
|
(89 |
) |
|
|
(9 |
) |
(594 |
) |
(692 |
) |
|
Forfeited |
|
(3 |
) |
|
|
(88 |
) |
(202 |
) |
(293 |
) |
|
|
Balance, end of period |
|
|
|
300 |
|
2,542 |
|
2,818 |
|
5,660 |
|
|
|
Cash-settled LTI Plans
For the three and six months ended June 30, 2016, the Company recorded cash share-based compensation of $0.8 million and
$1.5 million, respectively (June 30, 2015 recovery of $1.2 million and expense of $6.0 million). For the three and six months
ended June 30, 2016 the Company made cash payments of nil and $2.7 million, respectively, related to its cash-settled plans
(June 30, 2015 nil and $5.6 million).
As
of June 30, 2016, a liability of $2.6 million (December 31, 2015 $2.3 million) with respect to the DSU plan has
been recorded to Accounts Payable on the Consolidated Balance Sheets.
Equity-settled LTI Plans
For the three and six months ended June 30, 2016 the Company recorded non-cash share-based compensation expense of $5.4 million and
$8.8 million, respectively (2015 $4.6 million and $9.6 million, respectively).
The
following table summarizes the cumulative share-based compensation expense recognized to-date which is recorded to Paid-in Capital on the Consolidated Balance Sheets. Unrecognized amounts will be
recorded to non-cash share-based compensation expense over the remaining vesting terms.
At June 30, 2016 ($ thousands, except for years) |
|
|
PSU(1) |
|
|
RSU |
|
|
Total |
|
|
Cumulative recognized share-based compensation expense |
|
$ |
9,403 |
|
$ |
11,219 |
|
$ |
20,622 |
|
Unrecognized share-based compensation expense |
|
|
8,861 |
|
|
9,241 |
|
|
18,102 |
|
|
Fair value |
|
$ |
18,264 |
|
$ |
20,460 |
|
$ |
38,724 |
|
|
Weighted-average remaining contractual term (years) |
|
|
1.9 |
|
|
1.5 |
|
|
|
|
|
- (1)
- Includes
estimated performance multipliers.
ii) Stock Option Plan
The Company did not grant any stock options for the three and six months ended June 30, 2016. At June 30, 2016 all stock options are
fully vested and any related non-cash share-based compensation expense has been fully recognized.
The
following table summarizes the stock option plan activity for the period ended June 30, 2016:
Period ended June 30, 2016 |
|
Number of
Options (thousands) |
|
|
Weighted
Average
Exercise Price |
|
|
Options outstanding, beginning of year |
|
7,580 |
|
$ |
18.49 |
|
|
Forfeited |
|
(1,070 |
) |
|
18.76 |
|
|
Options outstanding, end of period |
|
6,510 |
|
$ |
18.45 |
|
|
Options exercisable, end of period |
|
6,510 |
|
$ |
18.45 |
|
|
At June 30, 2016, Enerplus had 6,510,000 options that were exercisable at a weighted average reduced exercise price of $18.45 with a
weighted average remaining contractual term of 3.0 years, giving an aggregate intrinsic value of nil (2015 nil). The intrinsic value of options exercised
for both the three and six months ended June 30, 2016 was nil (June 30, 2015 $0.1 million and $0.2 million,
respectively).
36 ENERPLUS 2016 Q2
REPORT
c) Basic and Diluted Net Income/(Loss) Per Share
Net income/(loss) per share has been determined as follows:
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
(thousands, except per share amounts) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
|
|
|
|
Net income/(loss) |
|
$ |
(168,554 |
) |
|
|
$ |
(312,544 |
) |
|
|
$ |
(342,220 |
) |
|
|
$ |
(605,750 |
) |
|
Weighted average shares outstanding Basic |
|
|
218,128 |
|
|
|
|
206,208 |
|
|
|
|
212,420 |
|
|
|
|
206,028 |
|
|
Dilutive impact of share-based compensation(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding Diluted |
|
|
218,128 |
|
|
|
|
206,208 |
|
|
|
|
212,420 |
|
|
|
|
206,028 |
|
|
|
|
|
|
|
|
|
Net income/(loss) per share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(0.77 |
) |
|
|
$ |
(1.52 |
) |
|
|
$ |
(1.61 |
) |
|
|
$ |
(2.94 |
) |
|
|
Diluted(1) |
|
$ |
(0.77 |
) |
|
|
$ |
(1.52 |
) |
|
|
$ |
(1.61 |
) |
|
|
$ |
(2.94 |
) |
|
|
|
|
|
|
|
|
- (1)
- For
the three and six months ended June 30, 2016 the impact of share-based compensation was anti-dilutive as a conversion to shares would not increase the loss
per share.
15) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
a) Fair Value Measurements
At June 30, 2016 the carrying value of cash, accounts receivable, accounts payable, dividends payable and bank credit facilities approximated
their fair value due to the short-term maturity of the instruments.
At
June 30, 2016 senior notes had a carrying value of $723.3 million and a fair value of $791.9 million
(December 31, 2015 $1,137.2 million and $1,220.8 million, respectively).
There
were no transfers between fair value hierarchy levels during the period.
b) Derivative Financial Instruments
The deferred financial assets and liabilities on the Consolidated Balance Sheets result from recording derivative financial instruments at fair value.
The
following table summarizes the change in fair value for the three and six months ended June 30, 2016 and 2015:
|
|
Three months ended June 30,
|
|
|
|
Six months ended June 30,
|
|
|
|
Gain/(Loss) ($ thousands) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
2016 |
|
|
|
|
2015 |
|
Income Statement Presentation |
|
|
|
|
|
|
|
|
|
Foreign Exchange Derivatives |
|
$ |
|
|
|
|
$ |
17,468 |
|
|
|
$ |
|
|
|
|
$ |
(34,294 |
) |
Foreign exchange |
|
Electricity Swaps |
|
|
885 |
|
|
|
|
2,642 |
|
|
|
|
577 |
|
|
|
|
1,715 |
|
Operating expense |
|
Equity Swaps |
|
|
1,520 |
|
|
|
|
(1,032 |
) |
|
|
|
1,655 |
|
|
|
|
567 |
|
General and administrative expense |
|
Commodity Derivative Instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
(27,144 |
) |
|
|
|
(71,085 |
) |
|
|
|
(58,420 |
) |
|
|
|
(107,044 |
) |
Commodity derivative instruments |
|
|
Gas |
|
|
(16,321 |
) |
|
|
|
(21,731 |
) |
|
|
|
(11,207 |
) |
|
|
|
(22,181 |
) |
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(41,060 |
) |
|
|
$ |
(73,738 |
) |
|
|
$ |
(67,395 |
) |
|
|
$ |
(161,237 |
) |
|
|
|
|
|
|
|
|
|
|
The following table summarizes the income statement effects of Enerplus' commodity derivative instruments:
|
|
Three months ended June 30,
|
|
Six months ended June 30,
|
($ thousands) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
|
|
|
|
Change in fair value gain/(loss) |
|
$ |
(43,465 |
) |
|
|
$ |
(92,816 |
) |
|
|
$ |
(69,627 |
) |
|
|
$ |
(129,225 |
) |
|
Net realized cash gain/(loss) |
|
|
21,558 |
|
|
|
|
73,065 |
|
|
|
|
61,184 |
|
|
|
|
159,872 |
|
|
|
|
|
|
|
|
|
Commodity derivative instruments gain/(loss) |
|
$ |
(21,907 |
) |
|
|
$ |
(19,751 |
) |
|
|
$ |
(8,443 |
) |
|
|
$ |
30,647 |
|
|
|
|
|
|
|
|
|
ENERPLUS 2016 Q2
REPORT 37
The following table summarizes the fair values at the respective period ends:
|
|
June 30, 2016
|
|
December 31, 2015
|
|
|
Assets
|
|
Liabilities
|
|
Assets
|
|
Liabilities
|
($ thousands) |
|
|
Current |
|
|
Current |
|
|
Long-term |
|
|
|
Current |
|
|
Current |
|
|
Long-term |
|
|
|
|
Electricity Swaps |
|
$ |
|
|
$ |
1,199 |
|
$ |
|
|
|
$ |
|
|
$ |
1,776 |
|
$ |
|
|
Equity Swaps |
|
|
|
|
|
2,580 |
|
|
1,282 |
|
|
|
|
|
|
2,324 |
|
|
3,193 |
|
Commodity Derivative Instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
14,228 |
|
|
|
|
|
5,251 |
|
|
|
67,397 |
|
|
|
|
|
|
|
|
Gas |
|
|
|
|
|
5,831 |
|
|
1,335 |
|
|
|
4,041 |
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
14,228 |
|
$ |
9,610 |
|
$ |
7,868 |
|
|
$ |
71,438 |
|
$ |
4,100 |
|
$ |
3,193 |
|
|
|
|
c) Risk Management
i) Market Risk
Market risk is comprised of commodity price, foreign exchange, interest rate and equity price risk.
Commodity Price Risk:
Enerplus manages a portion of commodity price risk through a combination of financial derivative and physical delivery sales contracts. Enerplus' policy is to
enter into commodity contracts subject to a maximum of 80% of forecasted production volumes net of royalties and production taxes.
The
following tables summarize the Corporation's price risk management positions at July 22, 2016:
Crude Oil Instruments:
Instrument Type(1) |
|
bbls/day |
|
US$/bbl |
|
|
|
Jul 1, 2016 Dec 31, 2016 |
|
|
|
|
|
|
WTI Purchased Put |
|
12,000 |
|
57.82 |
|
|
WTI Sold Call |
|
12,000 |
|
71.75 |
|
|
WTI Sold Put |
|
12,000 |
|
45.09 |
|
|
WCS Differential Swap |
|
3,000 |
|
(14.03 |
) |
|
MSW Differential Swap |
|
1,000 |
|
(3.50 |
) |
|
Jan 1, 2017 Dec 31, 2017 |
|
|
|
|
|
|
WTI Purchased Put |
|
12,000 |
|
50.00 |
|
|
WTI Sold Call |
|
12,000 |
|
60.50 |
|
|
WTI Sold Put |
|
12,000 |
|
38.59 |
|
|
|
- (1)
- Transactions
with a common term have been aggregated and presented at a weighted average price/bbl.
38 ENERPLUS 2016 Q2
REPORT
Natural Gas Instruments:
Instrument Type(1) |
|
MMcf/day |
|
US$/Mcf |
|
|
Jul 1, 2016 Oct 31, 2016 |
|
|
|
|
|
NYMEX Swap |
|
50.0 |
|
2.53 |
|
NYMEX Purchased Put |
|
25.0 |
|
3.00 |
|
NYMEX Sold Call |
|
25.0 |
|
3.75 |
|
NYMEX Sold Put |
|
25.0 |
|
2.50 |
|
Nov 1, 2016 Dec 31, 2016 |
|
|
|
|
|
NYMEX Swap |
|
25.0 |
|
2.48 |
|
NYMEX Purchased Put |
|
25.0 |
|
3.00 |
|
NYMEX Sold Call |
|
25.0 |
|
3.75 |
|
NYMEX Sold Put |
|
25.0 |
|
2.50 |
|
Jan 1, 2017 Dec 31, 2017 |
|
|
|
|
|
NYMEX Purchased Put |
|
45.0 |
|
2.72 |
|
NYMEX Sold Call |
|
45.0 |
|
3.37 |
|
NYMEX Sold Put |
|
45.0 |
|
2.03 |
|
|
- (1)
- Transactions
with a common term have been aggregated and presented at a weighted average price/Mcf.
Electricity Instruments:
Instrument Type |
|
MWh |
|
CDN$/MWh |
|
|
Jul 1, 2016 Dec 31, 2016 |
|
|
|
|
|
AESO Power Swap(1) |
|
15.0 |
|
46.60 |
|
Jan 1, 2017 Dec 31, 2017 |
|
|
|
|
|
AESO Power Swap(1) |
|
6.0 |
|
44.38 |
|
|
- (1)
- Alberta
Electrical System Operator ("AESO") fixed pricing.
Physical Contracts:
Instrument Type |
|
MMcf/day |
|
US$/Mcf |
|
|
|
Jul 1, 2016 Oct 31, 2016 |
|
21.4 |
|
(0.68 |
) |
|
AECO-NYMEX Basis |
|
|
|
|
|
|
Nov 1, 2016 Oct 31, 2017 |
|
80.0 |
|
(0.65 |
) |
|
AECO-NYMEX Basis |
|
|
|
|
|
|
Nov 1, 2017 Oct 31, 2018 |
|
80.0 |
|
(0.65 |
) |
|
AECO-NYMEX Basis |
|
|
|
|
|
|
Nov 1, 2018 Oct 31, 2019 |
|
80.0 |
|
(0.64 |
) |
|
AECO-NYMEX Basis |
|
|
|
|
|
|
|
Foreign Exchange Risk:
Enerplus is exposed to foreign exchange risk in relation to its U.S. operations, and U.S. dollar denominated senior notes and working capital.
Additionally, Enerplus' crude oil sales and a portion of its natural gas sales are based on U.S. dollar indices. To mitigate exposure to fluctuations in foreign exchange, Enerplus may enter
into foreign exchange derivatives. At June 30, 2016 Enerplus did not have any foreign exchange derivatives outstanding.
Interest Rate Risk:
As of June 30, 2016 all of Enerplus' debt was based on fixed interest rates, and Enerplus had no interest rate derivatives outstanding.
ENERPLUS 2016 Q2
REPORT 39
Equity Price Risk:
Enerplus is exposed to equity price risk in relation to its long-term incentive plans detailed in Note 14. Enerplus has entered into various equity swaps
maturing between 2016 and 2018 and has effectively fixed the figure settlement cost on 470,000 shares at weighted average price of $16.89 per share.
ii) Credit Risk
Credit risk represents the financial loss Enerplus would experience due to the potential non-performance of counterparties to its financial instruments.
Enerplus is exposed to credit risk mainly through its joint venture, marketing and financial counterparty receivables.
Enerplus
mitigates credit risk through credit management techniques including conducting financial assessments to establish and monitor counterparties' credit worthiness, setting exposure limits,
monitoring exposures against these limits and obtaining financial assurances such as letters of credit, parental guarantees, or third party credit insurance where warranted. Enerplus monitors and
manages its concentration of counterparty credit risk on an ongoing basis.
Enerplus'
maximum credit exposure at the balance sheet date consists of the carrying amount of its non-derivative financial assets and the fair value of its derivative financial assets. At
June 30, 2016 approximately 50% of Enerplus' marketing receivables were with companies considered investment grade.
At
June 30, 2016 approximately $2.1 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
of 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 uncollectable the account is written off with a corresponding charge to the
allowance account. Enerplus' allowance for doubtful accounts balance at June 30, 2016 was $3.4 million
(December 31, 2015 $3.2 million).
iii) Liquidity Risk & Capital Management
Liquidity risk represents the risk that Enerplus will be unable to meet its financial obligations as they become due. Enerplus mitigates liquidity risk through
actively managing its capital, which it defines as debt (net of cash) and shareholders' capital. Enerplus' objective is to provide adequate short and longer term liquidity while maintaining a
flexible capital structure to sustain the future development of its business. Enerplus strives to balance the portion of debt and equity in its capital structure given its current oil and natural gas
assets and planned investment opportunities.
Management
monitors a number of key variables with respect to its capital structure, including debt levels, capital spending plans, dividends, access to capital markets, as well as acquisition and
divestment activity.
At
June 30, 2016 Enerplus was in full compliance with all covenants under the bank credit facility and outstanding senior notes.
16) CONTINGENCIES
Enerplus is subject to various legal claims and actions arising in the normal course of business. Although the outcome of such claims and actions cannot be
predicted with certainty, the Company does not expect these matters to have a material impact on the Consolidated Financial Statements. In instances where the Company determines that a loss is
probable and the amount can be reasonably estimated, an accrual is recorded.
40 ENERPLUS 2016 Q2
REPORT
17) SUPPLEMENTAL CASH FLOW INFORMATION
a) Changes In Non-Cash Operating Working Capital
|
|
Three months ended June 30,
|
|
|
|
Six months ended June 30,
|
|
|
($ thousands) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
Accounts receivable |
|
$ |
288 |
|
|
|
$ |
(5,371 |
) |
|
|
$ |
29,640 |
|
|
|
$ |
18,696 |
|
|
Other current assets |
|
|
(3,426 |
) |
|
|
|
(10,079 |
) |
|
|
|
(96 |
) |
|
|
|
(14,877 |
) |
|
Accounts payable |
|
|
(10,272 |
) |
|
|
|
(7,321 |
) |
|
|
|
(12,480 |
) |
|
|
|
(768 |
) |
|
|
|
|
|
|
$ |
(13,410 |
) |
|
|
$ |
(22,771 |
) |
|
|
$ |
17,064 |
|
|
|
$ |
3,051 |
|
|
|
|
|
b) Other
|
|
Three months ended June 30,
|
|
|
Six months ended June 30,
|
|
|
($ thousands) |
|
|
2016 |
|
|
|
|
2015 |
|
|
|
2016 |
|
|
|
|
2015 |
|
|
|
|
|
Income taxes paid/(received) |
|
$ |
(17,194 |
) |
|
|
$ |
148 |
|
|
$ |
(19,118 |
) |
|
|
$ |
(19,197 |
) |
|
Interest paid |
|
|
17,832 |
|
|
|
|
25,936 |
|
|
|
27,638 |
|
|
|
|
32,418 |
|
|
|
|
|
ENERPLUS 2016 Q2
REPORT 41
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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 June 30, 2016.
- 2.
- No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim
filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the
circumstances under which it was made, with respect to the period covered by the interim filings.
- 3.
- Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim
financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of
the issuer, as of the date of and for the periods presented in the interim filings.
- 4.
- Responsibility: The issuer's other certifying officer and I are responsible for establishing and
maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers' Annual and
Interim Filings, for the issuer.
- 5.
- Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3,
the issuer's other certifying officer and I have, as at the end of the period covered by the interim filings
- (a)
- designed
DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that
- (i)
- material
information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being
prepared; and
- (ii)
- information
required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities
legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and
- (b)
- designed
ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with the issuer's GAAP.
- 5.1
- Control framework: The control framework the issuer's other certifying officer and I used to
design the issuer's ICFR is Internal Control Integrated Framework (2013 Framework) issued by the Committee of
Sponsoring Organizations of the Treadway Commission.
- 5.2
- ICFR material weakness relating to design: N/A
- 5.3
- Limitation on scope of design: N/A
- 6.
- Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the
issuer's ICFR that occurred during the period beginning on April 1, 2016 and ended on June 30, 2016 that has materially affected, or is reasonably likely to materially affect, the
issuer's ICFR.
Date:
August 5, 2016
|
|
|
(signed by)
|
|
|
Ian C. Dundas
President and Chief Executive Officer
Enerplus Corporation
|
|
|
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FORM 52-109F2 CERTIFICATION OF INTERIM FILINGS FULL CERTIFICATE
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Exhibit 99.4
FORM 52-109F2
CERTIFICATION OF INTERIM FILINGS
FULL CERTIFICATE
I,
JODI JENSON LABRIE, Senior Vice President and Chief Financial Officer of Enerplus Corporation, certify the following:
- 1.
- Review: I have reviewed the interim financial report and interim MD&A (together, the "interim
filings") of Enerplus Corporation (the "issuer") for the interim period ended June 30, 2016.
- 2.
- No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim
filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the
circumstances under which it was made, with respect to the period covered by the interim filings.
- 3.
- Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim
financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of
the issuer, as of the date of and for the periods presented in the interim filings.
- 4.
- Responsibility: The issuer's other certifying officer and I are responsible for establishing and
maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers' Annual and
Interim Filings, for the issuer.
- 5.
- Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3,
the issuer's other certifying officer and I have, as at the end of the period covered by the interim filings
- (a)
- designed
DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that
- (i)
- material
information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being
prepared; and
- (ii)
- information
required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities
legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and
- (b)
- designed
ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with the issuer's GAAP.
- 5.1
- Control framework: The control framework the issuer's other certifying officer and I used to
design the issuer's ICFR is Internal Control Integrated Framework (2013 Framework) issued by The Committee of
Sponsoring Organizations of the Treadway Commission.
- 5.2
- ICFR material weakness relating to design: N/A
- 5.3
- Limitation on scope of design: N/A
- 6.
- Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the
issuer's ICFR that occurred during the period beginning on April 1, 2016 and ended on June 30, 2016 that has materially affected, or is reasonably likely to materially affect, the
issuer's ICFR.
Date:
August 5, 2016
|
|
|
(signed by)
|
|
|
Jodi Jenson Labrie
Senior Vice President and Chief Financial Officer
Enerplus Corporation
|
|
|
QuickLinks
FORM 52-109F2 CERTIFICATION OF INTERIM FILINGS FULL CERTIFICATE
This regulatory filing also includes additional resources:
a2229287zenerplus_q2-mda.pdf
a2229287zenerplus_q2-fs.pdf
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