Enerplus Announces Second Quarter 2016 Results Including Strengthened Balance Sheet and Further Cost Reductions
All financial information contained within this news release has been prepared in accordance with U.S. GAAP, except as noted under "Non-GAAP Measures". This news release includes forward-looking statements and information within the meaning of applicable securities laws. Readers are advised to review the "Forward-Looking Information and Statements" at the conclusion of this news release. A full copy of Enerplus' Second Quarter 2016 Financial Statements and MD&A are available on the Company's website at www.enerplus.com, under its SEDAR profile at www.sedar.com and on the EDGAR website at www.sec.gov.
CALGARY, Aug. 5, 2016 /CNW/ - Enerplus Corporation ("Enerplus" or the "Company") (TSX & NYSE: ERF) is pleased to announce its results from operations for the second quarter of 2016.
"We have significantly strengthened our balance sheet having reduced our debt, net of cash, by 45% since year-end 2015. In addition, we continue to drive costs lower as we position our company to deliver profitable growth in a lower commodity price environment," stated Ian C. Dundas, President & CEO. "Enerplus continues to perform at a high level operationally, and with our lower cost structure and improved financial strength we are modestly increasing our 2016 capital program in North Dakota as we position the company for growth in 2017."
KEY TAKEAWAYS:
- Production averaged 93,659 BOE per day during the quarter, including 43,908 barrels per day of crude oil and natural gas liquids. Annual average 2016 production is tracking the higher-end of Enerplus' guidance range of 90,000 – 94,000 BOE per day, despite the divestment of approximately 2,300 BOE per day at the end of the second quarter, largely due to strong Marcellus production. As a result, Enerplus is updating its 2016 average production guidance to 92,000 – 94,000 BOE per day. Crude oil and natural gas liquids production guidance remains unchanged at 43,000 – 45,000 barrels per day.
- Enerplus has significantly strengthened its balance sheet in 2016. The receipt of divestment proceeds of $280.5 million year to date and net equity financing proceeds of $220.4 million, have helped reduce the Company's total debt net of cash by 45% since December 31, 2015. At June 30, 2016, Enerplus had $723.3 million of senior notes outstanding and $49.2 million in cash, and the Company's $800 million bank credit facility was undrawn. At June 30, 2016, Enerplus' senior debt to adjusted EBITDA ratio was 1.2 times and debt to funds flow ratio was 2.0 times.
- Enerplus continued to deliver significant cost savings during the second quarter including a reduction in cash costs comprising operating, transportation, G&A and interest of $1.68 per BOE compared to the same period in 2015.
- Operating costs were $7.10 per BOE in the quarter, 10% lower than the same period in 2015 and below the Company's annual guidance of $8.50 per BOE as a result of continued cost reductions and the divestment of higher operating cost properties. Cash G&A expenses were $1.71 per BOE in the second quarter, 16% lower than the same period in 2015 and below the Company's annual guidance of $2.00 per BOE primarily due to a reduction in staffing levels. Based on this performance, Enerplus is reducing its 2016 guidance for operating expenses to $7.90 per BOE and cash G&A expenses to $1.95 per BOE.
- Enerplus recorded a net loss of $168.6 million or ($0.77) per share in the second quarter, which is attributable to non-cash items including an impairment charge and a deferred tax asset valuation allowance as a result of the continued decline in the twelve month trailing average commodity prices.
- Enerplus generated second quarter funds flow of $76.0 million, an increase of 82% from the previous quarter. The increased funds flow was driven by higher crude oil prices, improved commodity price differentials and lower cash costs.
- Enerplus' realized pricing differentials in the Bakken and Marcellus have meaningfully improved over the past year. Although in part this is due to lower benchmark prices, improvements in the supply-demand balance in each basin have also contributed to the tighter differentials. Compared to the same period in 2015, Enerplus' second quarter realized Bakken differential narrowed by US$1.07 per barrel to US$8.23 per barrel below WTI, and Enerplus' second quarter realized Marcellus differential narrowed by US$0.63 per Mcf averaging US$0.76 per Mcf below NYMEX.
- Capital spending in the second quarter was $48.1 million of which $30.4 million was directed to North Dakota. As a result of Enerplus' stronger financial position and lower cost structure, which is driving margin improvement, the Company is increasing its 2016 capital spending guidance to $215 million from $200 million to add three gross completions and pre-order facilities equipment in North Dakota during the latter part of the year for the 2017 program. The incremental expenditure will allow Enerplus to further test well downspacing in Fort Berthold, and is expected to add approximately 1,000 BOE per day to Enerplus' fourth quarter production volumes and better position the Company for growth in 2017. Enerplus continues to expect its 2016 capital and dividend commitments to be fully funded through internally generated cash flow at current forward strip commodity prices.
ASSET ACTIVITY
North Dakota production averaged 28,800 BOE per day during the second quarter, largely flat from the previous quarter and up 6% from the same period in 2015. Enerplus continues to operate one drilling rig at Fort Berthold with capital spending in the quarter totaling $30.4 million resulting in 4.6 net wells drilled and 7.2 net wells on-stream. Well costs continue to trend down as a result of improvements in drilling time and ongoing completions optimization. Enerplus' average cost for a two-mile lateral well in the second quarter was US$7.8 million including drilling, completion, tie-in and facilities costs, 26% lower than the Company's 2015 average. Initial 30-day production rates from operated wells brought on-stream in the second quarter averaged approximately 1,450 BOE per day. At the end of the quarter, Enerplus had approximately 8 net drilled uncompleted wells in Fort Berthold.
Marcellus production averaged 195 MMcf per day during the second quarter, a modest increase from the first quarter of 2016. Capital spending in the Marcellus was $9.3 million in the quarter delivering 0.3 net wells drilled and 1.8 net wells on-stream. The production increase over the previous quarter was due to strong well performance. Enerplus participated in 7 gross on-stream wells in the second quarter with initial 30-day production rates that averaged 15.8 MMcf per day and an average lateral length of 6,400 ft. Enerplus continues to plan for limited activity levels in the Marcellus for the remainder of 2016.
Production from the Canadian waterflood assets averaged 16,560 BOE per day during the second quarter of 2016, 5% lower than the previous quarter. Lower second quarter production was due to limited capital activity levels and the divestment of certain non-core assets located in northwest Alberta in June 2016. In the second quarter, Enerplus spent approximately $7.1 million on waterflood optimization activities. Enerplus will continue to focus on cost management in these assets which is helping to deliver strong operating netbacks.
PRODUCTION AND CAPITAL SPENDING
| Three months ended June 30, 2016 |
Six months ended June 30, 2016 |
|||
| Crude Oil & NGLs (bbls/day) |
Average Production |
Capital Spending |
Average Production |
Capital Spending |
| Canada |
14,915 |
$7.1 |
15,453 |
$26.2 |
| United States |
28,993 |
$31.6 |
29,002 |
$52.3 |
| Total Crude Oil & NGLs (bbls/day) |
43,908 |
$38.7 |
44,455 |
$78.5 |
| Natural Gas (Mcf/day) |
||||
| Canada |
79,878 |
$0.1 |
89,708 |
$0.1 |
| United States |
218,625 |
$9.3 |
218,119 |
$12.8 |
| Total Natural Gas (Mcf/day) |
298,503 |
$9.4 |
307,827 |
$12.9 |
| Company Total (BOE/day) |
93,659 |
$48.1 |
95,759 |
$91.4 |
| NET DRILLING ACTIVITY(1)– for the three months ended June 30, 2016 |
||
| Crude Oil |
Wells Drilled |
Wells On-stream |
| Canada |
- |
- |
| United States |
4.6 |
7.2 |
| Total Crude Oil |
4.6 |
7.2 |
| Natural Gas |
||
| Canada |
- |
- |
| United States |
0.3 |
1.8 |
| Total Natural Gas |
0.3 |
1.8 |
| Company Total |
4.9 |
9.1 |
| (1) Table may not add due to rounding |
||
CRUDE OIL & NATURAL GAS PRICING
Enerplus' average crude oil selling price during the second quarter was $46.48 per barrel, an increase of 47% compared to the prior quarter as a result of the higher benchmark crude oil prices and narrowing Canadian differentials. Benchmark West Texas Intermediate (WTI) crude oil prices increased by 36% quarter-over-quarter to average US$45.59 per barrel in the second quarter. Enerplus' realized pricing outperformed benchmark WTI prices as light and heavy crude differentials in Canada improved by 16% and 7% respectively, compared to the previous quarter, due to industry wide production outages resulting from the severe wildfires in northern Alberta. These outages also supported U.S. Bakken crude differentials which improved by 2% quarter-over-quarter.
Enerplus' average natural gas selling price during the second quarter was $1.49 per Mcf, 16% lower than the prior quarter, reflecting the significant weakness experienced in Western Canadian gas prices during the period. Benchmark NYMEX gas prices fell by 7% in the second quarter, while in Canada benchmark AECO monthly natural gas prices were 41% weaker than in the first quarter of 2016 in large part due to excessive inventory levels caused by mild winter weather. Supported by Enerplus' AECO basis hedging contracts, the Company's realized Canadian gas price differential significantly outperformed the AECO benchmark price, averaging US$0.86 per Mcf below NYMEX during the quarter compared to the benchmark AECO monthly differential of US$0.99 per Mcf below NYMEX.
Enerplus' realized Marcellus differential improved by 16% during the second quarter to average US$0.76 per Mcf below NYMEX. Industry rig counts in the Marcellus region have fallen meaningfully over the past year which has moderated Northeast Pennsylvania production growth and improved price differentials to NYMEX. Enerplus expects its Marcellus differential to widen in the third quarter with the stronger NYMEX prices.
RISK MANAGEMENT
Enerplus continues to protect a portion of funds flow through commodity hedging. Based on 2016 forecast net oil production after royalties, Enerplus has approximately 39% of volumes protected in the second half of 2016 and 2017 through collar structures. Based on 2016 forecast net natural gas production after royalties, Enerplus has approximately 29% and 20% of volumes protected in the second half of 2016 and 2017 respectively, through a combination of swaps and collar structures.
| Commodity Hedging Detail (as at July 22, 2016) |
|||||
| WTI Crude Oil (US$/bbl)(1) |
NYMEX Natural |
||||
| Jul 1, 2016 – |
Jan 1, 2017 – |
Jul 1, 2016 – |
Nov 1, 2016 – |
Jan 1, 2017 – |
|
| Swaps |
|||||
| Sold Swaps |
- |
- |
$2.53 |
$2.48 |
- |
| Volume (bbl/d or Mcf/d) |
- |
- |
50,000 |
25,000 |
- |
| % of net production |
- |
- |
22% |
11% |
- |
| 3 Way Collars |
|||||
| Sold Puts |
$45.09 |
$38.59 |
$2.50 |
$2.50 |
$2.03 |
| Volume (bbl/d or Mcf/d) |
12,000 |
12,000 |
25,000 |
25,000 |
45,000 |
| % of net production |
39% |
39% |
11% |
11% |
20% |
| Purchased Puts |
$57.82 |
$50.00 |
$3.00 |
$3.00 |
$2.72 |
| Volume (bbl/d or Mcf/d) |
12,000 |
12,000 |
25,000 |
25,000 |
45,000 |
| % of net production |
39% |
39% |
11% |
11% |
20% |
| Sold Calls |
$71.75 |
$60.50 |
$3.75 |
$3.75 |
$3.37 |
| Volume (bbl/d or Mcf/d) |
12,000 |
12,000 |
25,000 |
25,000 |
45,000 |
| % of net production |
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 |
|||||
2016 REVISED GUIDANCE
Enerplus has revised its full year 2016 guidance to reflect stronger natural gas production from the Marcellus, a lower expected overall royalty expense, reduced operating and G&A expenses, and a modest increase in capital spending to support 2017 growth.
| Summary of 2016 Expectations |
Revised Guidance |
Previous Guidance |
| Capital spending |
$215 million |
$200 million |
| Average annual production |
92,000 – 94,000 BOE/day |
90,000 – 94,000 BOE/day |
| Crude oil and natural gas liquids volumes |
43,000 – 45,000 barrels/day |
43,000 – 45,000 barrels/day |
| Average royalty and production tax rate |
22% |
23% |
| Operating expenses |
$7.90/BOE |
$8.50/BOE |
| Transportation expense |
$3.10/BOE |
$3.10/BOE |
| Cash G&A expenses |
$1.95/BOE |
$2.00/BOE |
Q2 2016 CONFERENCE CALL DETAILS
A conference call hosted by Ian C. Dundas, President and CEO will be held at 9:00AM MT (11:00AM ET) today to discuss these results. Details of the conference call are as follows:
| Date: |
Friday, August 5, 2016 |
||
| Time: |
9:00 AM MT (11:00 AM ET) |
||
| Dial-In: |
647-427-7450 |
||
| 1-888-231-8191 (toll free) |
|||
| Audiocast: |
http://event.on24.com/r.htm?e=1220760&s=1&k=27AA414C14D5775C55176FD27A428CCD |
To ensure timely participation in the conference call, callers are encouraged to dial in 15 minutes prior to the start time to register for the event. A telephone replay will be available for 30 days following the conference call and can be accessed at the following numbers:
| Dial-In: |
416-849-0833 |
| 1-855-859-2056 (toll free) |
|
| Passcode: |
45475268 |
SELECTED FINANCIAL RESULTS
| Three months ended June 30, |
Six months ended June 30, |
|||||||
| 2016 |
2015 |
2016 |
2015 |
|||||
| Financial (000's) |
||||||||
| Funds Flow(4) |
$ |
76,047 |
$ |
160,436 |
$ |
117,774 |
$ |
269,600 |
| Dividends to Shareholders |
6,547 |
30,935 |
21,011 |
78,294 |
||||
| Net Income/(Loss) |
(168,554) |
(312,544) |
(342,220) |
(605,750) |
||||
| Debt Outstanding - net of cash |
674,147 |
1,120,680 |
674,147 |
1,120,680 |
||||
| Capital Spending |
48,120 |
147,979 |
91,396 |
314,989 |
||||
| Property and Land Acquisitions |
343 |
(1,011) |
3,897 |
(1,248) |
||||
| Property Divestments |
92,735 |
187,801 |
280,503 |
191,513 |
||||
| Debt to Funds Flow Ratio(4) |
2.0x |
1.6x |
2.0x |
1.6x |
||||
| Financial per Weighted Average Shares Outstanding |
||||||||
| Net Income/(Loss) |
$ |
(0.77) |
$ |
(1.52) |
$ |
(1.61) |
$ |
(2.94) |
| Weighted Average Number of Shares Outstanding (000's) |
218,128 |
206,208 |
212,420 |
206,028 |
||||
| Selected Financial Results per BOE(1)(2) |
||||||||
| Oil & Natural Gas Sales(3) |
$ |
24.96 |
$ |
30.53 |
$ |
21.99 |
$ |
28.78 |
| Royalties and Production Taxes |
(5.51) |
(6.23) |
(4.72) |
(5.88) |
||||
| Commodity Derivative Instruments |
2.53 |
7.47 |
3.51 |
8.48 |
||||
| Cash Operating Expenses |
(7.20) |
(8.12) |
(7.67) |
(8.81) |
||||
| Transportation Costs |
(2.87) |
(2.87) |
(2.88) |
(2.89) |
||||
| General and Administrative Expenses |
(1.71) |
(2.03) |
(1.89) |
(2.19) |
||||
| Cash Share-Based Compensation |
(0.09) |
0.13 |
(0.09) |
(0.32) |
||||
| Interest, Foreign Exchange and Other Expenses |
(1.21) |
(2.48) |
(1.51) |
(2.87) |
||||
| Current Income Tax Recovery |
0.02 |
0.01 |
0.02 |
- |
||||
| Funds Flow(4) |
$ |
8.92 |
$ |
16.41 |
$ |
6.76 |
$ |
14.30 |
SELECTED OPERATING RESULTS
| Three months ended June 30, |
Six months ended June 30, |
|||||||
| 2016 |
2015 |
2016 |
2015 |
|||||
| Average Daily Production(2) |
||||||||
| Crude Oil (bbls/day) |
39,079 |
41,122 |
39,294 |
40,243 |
||||
| Natural Gas Liquids (bbls/day) |
4,829 |
5,145 |
5,161 |
4,444 |
||||
| Natural Gas (Mcf/day) |
298,503 |
366,971 |
307,827 |
356,836 |
||||
| Total (BOE/day) |
93,659 |
107,429 |
95,759 |
104,160 |
||||
| % Crude Oil & Natural Gas Liquids |
47% |
43% |
46% |
43% |
||||
| Average Selling Price (2)(3) |
||||||||
| Crude Oil (per bbl) |
$ |
46.48 |
$ |
58.26 |
$ |
39.00 |
$ |
51.35 |
| Natural Gas Liquids (per bbl) |
15.67 |
20.88 |
13.37 |
21.55 |
||||
| Natural Gas (per Mcf) |
1.49 |
2.09 |
1.64 |
2.32 |
||||
| Net Wells drilled |
5 |
8 |
17 |
36 |
||||
| (1) |
Non-cash amounts have been excluded. |
| (2) |
Based on Company interest production volumes. See "Basis of Presentation" section in the Second Quarter 2016 MD&A. |
| (3) |
Before transportation costs, royalties and commodity derivative instruments. |
| (4) |
These non-GAAP measures may not be directly comparable to similar measures presented by other entities. See "Non-GAAP Measures". |
| Three months ended June 30, |
Six months ended June 30, |
|||||||
| Average Benchmark Pricing |
2016 |
2015 |
2016 |
2015 |
||||
| WTI crude oil (US$/bbl) |
$ |
45.59 |
$ |
57.94 |
$ |
39.52 |
$ |
53.29 |
| AECO natural gas – monthly index (CDN$/Mcf) |
1.25 |
2.67 |
1.68 |
2.81 |
||||
| AECO natural gas – daily index (CDN$/Mcf) |
1.40 |
2.64 |
1.62 |
2.70 |
||||
| NYMEX natural gas – last day (US$/Mcf) |
1.95 |
2.64 |
2.02 |
2.81 |
||||
| USD/CDN exchange rate |
1.29 |
1.23 |
1.33 |
1.24 |
||||
| Share Trading Summary |
CDN(1) - ERF |
U.S.(2) - ERF |
||||||
| For the three months ended June 30, 2016 |
(CDN$) |
(US$) |
||||||
| High |
$ |
8.78 |
$ |
6.94 |
||||
| Low |
$ |
4.68 |
$ |
3.55 |
||||
| Close |
$ |
8.51 |
$ |
6.57 |
||||
| (1) TSX and other Canadian trading data combined. |
||||||||
| (2) NYSE and other U.S. trading data combined. |
||||||||
| 2016 Dividends per Share |
||||||||
| Payment Month |
CDN$ |
US$(1) |
||||||
| First Quarter Total |
$ |
0.09 |
$ |
0.06 |
||||
| April |
$ |
0.01 |
$ |
0.01 |
||||
| May |
0.01 |
0.01 |
||||||
| June |
0.01 |
0.01 |
||||||
| Second Quarter Total |
$ |
0.03 |
$ |
0.03 |
||||
| Total Year-to-Date |
$ |
0.12 |
$ |
0.09 |
||||
| (1) CDN$ dividends converted at the relevant foreign exchange rate on the payment date. |
||||||||
Currency and Accounting Principles
All amounts in this news release are stated in Canadian dollars unless otherwise specified. All financial information in this news release has been prepared and presented in accordance with U.S. GAAP, except as noted below under "Non-GAAP Measures".
Barrels of Oil Equivalent
This news release also contains references to "BOE" (barrels of oil equivalent). Enerplus has adopted the standard of six thousand cubic feet of gas to one barrel of oil (6 Mcf: 1 bbl) when converting natural gas to BOEs. BOEs may be misleading, particularly if used in isolation. The foregoing conversion ratios are based on an energy equivalency conversion method primarily applicable at the burner tip and do not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading.
Presentation of Production Information
Under U.S. GAAP oil and gas sales are generally presented net of royalties and U.S. industry protocol is to present production volumes net of royalties. Under Canadian industry protocol oil and gas sales and production volumes are presented on a gross basis before deduction of royalties. In order to continue to be comparable with its Canadian peer companies, the summary results contained within this news release presents Enerplus' production and BOE measures on a before royalty company interest basis. All production volumes and revenues presented herein are reported on a "company interest" basis, before deduction of Crown and other royalties, plus Enerplus' royalty interest.
Readers are cautioned that the average initial production rates contained in this news release are not necessarily indicative of long-term performance or of ultimate recovery.
FORWARD-LOOKING INFORMATION AND STATEMENTS
This news release contains certain forward-looking information and statements ("forward-looking information") within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "guidance", "ongoing", "may", "will", "project", "should", "believe", "plans", "budget", "strategy" and similar expressions are intended to identify forward-looking information. In particular, but without limiting the foregoing, this news release contains forward-looking information pertaining to the following: expected 2016 average production volumes and the anticipated production mix; the proportion of anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting funds flow; the results from drilling programs and the timing of related production; oil and natural gas prices and differentials and commodity and foreign exchange risk management programs in 2016 and in 2017; expectations regarding realized oil and natural gas prices; anticipated cash and non-cash G&A, share based compensation and financing expenses; operating and transportation costs; capital spending levels in 2016, anticipated drilling and completions program, and the expected impact on production levels; potential future asset impairments; future debt and working capital levels and debt to funds flow ratios.
The forward-looking information contained in this news release reflects several material factors and expectations and assumptions of Enerplus including, without limitation: that Enerplus will conduct its operations and achieve results of operations as anticipated; that Enerplus' development plans will achieve the expected results; current commodity price and cost assumptions; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of Enerplus' reserves and resources volumes; the continued availability of adequate debt and/or equity financing, cash flow and other sources to fund Enerplus' capital and operating requirements, and dividend payments as needed; availability of third party services; and the extent of its liabilities. In addition, Enerplus' 2016 revised guidance is based on the following assumptions: WTI crude oil price of US$42.61/bbl, NYMEX gas price of US$2.46/Mcf, and AECO gas price of $2.00/GJ, and USD/CDN exchange rate of 1.32. Enerplus believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.
The forward-looking information included in this news release is not a guarantee of future performance and should not be unduly relied upon. Such information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information including, without limitation: changes, including future decline, in commodity prices; changes in realized prices for Enerplus' products; changes in the demand for or supply of Enerplus' products; unanticipated operating results, results from Enerplus' capital spending activities or production declines; curtailment of Enerplus' 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 development plans by Enerplus or by third party operators of Enerplus' properties; increased debt levels or debt service requirements; Enerplus' inability to comply with covenants under its bank credit facility and senior notes; changes in estimates of Enerplus' oil and gas reserves and resources 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; failure to complete any anticipated acquisitions or divestitures; and certain other risks detailed from time to time in Enerplus' public disclosure documents (including, without limitation, those risks identified in its AIF and Form 40-F at December 31, 2015).
NON-GAAP MEASURES
In this news release, we use the terms "funds flow" and "debt to funds flow ratio" as measures to analyze operating performance, leverage and liquidity. "Funds flow" is calculated as net cash generated from operating activities but before changes in non-cash operating working capital and asset retirement obligation expenditures. "Debt to funds flow ratio" is calculated as total debt net of cash, divided by a trailing 12 months of funds flow. In addition, "senior debt to adjusted EBITDA" is used to determine Enerplus' compliance with financial covenants under its bank credit facility and outstanding senior notes. Calculation of these terms is described in Enerplus Corporation's Second Quarter 2016 MD&A under the "Liquidity and Capital Resources" section.
Enerplus believes that, in addition to net earnings and other measures prescribed by U.S. GAAP, the terms "funds flow" and "debt to funds flow" are useful supplemental measures as they provide an indication of the results generated by Enerplus' principal business activities. However, these measures, and "senior debt to adjusted EBITDA" measures, are not measures recognized by U.S. GAAP and do not have a standardized meaning prescribed by U.S.GAAP. Therefore, these measures, as defined by Enerplus, may not be comparable to similar measures presented by other issuers. For reconciliation of these measures to the most directly comparable measure calculated in accordance with U.S. GAAP, and further information about these measures, see disclosure under "Non-GAAP Measures" in Enerplus' Second Quarter 2016 MD&A.
Electronic copies of Enerplus Corporation's Second Quarter 2016 MD&A and Financial Statements, along with other public information including investor presentations, are available on its website at www.enerplus.com. Shareholders may, upon request, receive a printed copy of our audited financial statements at any time. For further information, please contact Investor Relations at 1-800-319-6462 or email [email protected].
Follow @EnerplusCorp on Twitter at https://twitter.com/EnerplusCorp.
Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation
SOURCE Enerplus Corporation
ENERPLUS CORPORATION, The Dome Tower, Suite 3000, 333 - 7th Avenue SW, Calgary, Alberta T2P 2Z1, T. 403-298-2200 F. 403-298-2211, www.enerplus.com
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