Enerplus Announces Second Quarter 2017 Results
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 2017 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. 11, 2017 /CNW/ - Enerplus Corporation ("Enerplus" or the "Company") (TSX & NYSE: ERF) is pleased to announce its second quarter 2017 operating and financial results. The Company reported second quarter 2017 net income of $129.3 million, or $0.53 per share. This compares to a second quarter 2016 net loss of $168.6 million, or $0.77 per share.
SECOND QUARTER 2017 HIGHLIGHTS:
- 35% production growth in North Dakota quarter-over-quarter
- Generated adjusted funds flow of $114.2 million
- Increasing 2017 production guidance to 84,000 – 86,000 BOE per day
- 12% reduction in operating expenses quarter-over-quarter, 19% reduction year-over-year
- Lowering operating, cash G&A, and transportation expense guidance by a total of $0.65 per BOE
"Our second quarter results demonstrate the oil production growth potential of our high-quality position at Fort Berthold, where we remain on track to deliver 50% production growth over the course of 2017," stated Ian C. Dundas, President and Chief Executive Officer. "Additionally, our focus on cost management and commitment to maintaining our strong financial footing continues to position Enerplus to deliver sustained, long-term profitable growth in a lower commodity price environment."
FINANCIAL AND OPERATIONAL SUMMARY
Second quarter 2017 production averaged 86,209 BOE per day, including 40,994 barrels per day of crude oil and natural gas liquids. Liquids production increased to 48% of total company production, growing 13% from the first quarter driven by strong North Dakota volumes. Operations in North Dakota have been trending ahead of schedule which, combined with continued strong well performance, helped deliver second quarter North Dakota production of 28,047 BOE per day, a 35% increase from the previous quarter.
Enerplus is increasing its 2017 annual average production guidance range to 84,000 to 86,000 BOE per day (from 81,000 to 85,000 BOE per day) and its 2017 annual average liquids guidance to 39,500 to 41,500 barrels per day (from 38,500 to 41,500 barrels per day).
During the second quarter, Enerplus closed the previously announced divestment of shallow gas assets in Canada and its Brooks waterflood property with combined production of approximately 5,600 BOE per day. Second quarter production also included approximately 6 MMcf per day related to a Marcellus gas balancing adjustment. Production in the third quarter is expected to be sequentially lower due to this divestment and the gas balancing adjustment, combined with fewer wells planned to be brought on-stream in North Dakota and the Marcellus relative to the second quarter. Production is expected to significantly build later in the year with capital activity in the third quarter driving strong volumes into the fourth quarter. Enerplus remains well positioned to achieve its fourth quarter production guidance of 86,000 to 91,000 BOE per day including 43,000 to 48,000 barrels per day of liquids.
Enerplus generated adjusted funds flow of $114.2 million, a 5% decrease from the previous quarter as a result of lower commodity prices, which was offset by strong liquids production growth out of North Dakota, and reduced operating and G&A expenses during the quarter.
Exploration and development capital spending in the second quarter of 2017 was $101.7 million, with $70.7 million directed to North Dakota, $9.9 million allocated to the Canadian waterfloods, and $17.5 million directed to the Marcellus. Enerplus' 2017 exploration and development capital budget of $450 million is unchanged.
Enerplus' commodity hedging program realized cash gains of $2.2 million for the second quarter of 2017, compared to cash gains of $6.6 million in the first quarter of 2017.
Enerplus' realized Bakken crude oil price differential averaged US$5.43 per barrel below WTI in the second quarter, a 3% improvement relative to the previous quarter. Spot Bakken prices strengthened considerably late in the second quarter and into the third quarter as the Dakota Access Pipeline was brought into service in June. Based on this ongoing strength in pricing, Enerplus continues to expect its Bakken crude oil differential to average approximately US$4.50 per barrel below WTI during 2017.
Enerplus' realized Marcellus natural gas sales price differential widened slightly to US$0.64 per Mcf below NYMEX in the second quarter compared to US$0.60 per Mcf in the previous quarter. Regulatory issues announced in May have delayed the construction of the Rover pipeline project that will transport gas from the Marcellus/Utica region into the U.S. Midwest and Eastern Canada. Combined with higher production in the region relative to the previous quarter, this delay weakened regional market prices, pushing Marcellus basis differentials wider late in the quarter. Considering the uncertainty in the timing of the in-service date of the Rover pipeline, Enerplus now expects its Marcellus natural gas realized price differential to average US$0.75 per Mcf below NYMEX for 2017 (compared to US$0.60 per Mcf previously). Enerplus expects its Marcellus price differentials will continue to narrow once Rover and other pipeline projects slated for completion in the second half of 2017 are in-service, with a view to more consistent differentials and improved pricing moving into 2018.
Second quarter operating expenses averaged $5.83 per BOE, 12% lower compared to the prior quarter. Operating expenses continued to improve in the second quarter largely due to additional savings from the 2017 divestment program. As a result, Enerplus is lowering its 2017 operating expense guidance to $6.40 per BOE, from $6.85 per BOE. Enerplus expects operating costs to increase over the remainder of 2017 as its liquids production weighting increases.
Transportation costs in the second quarter averaged $3.72 per BOE, a decrease from $3.88 per BOE in the first quarter of 2017. Enerplus is reducing its 2017 guidance for transportation costs to $3.90 per BOE, from $4.00 per BOE, due to the impact of lower than expected USD/CDN foreign exchange rates on U.S. transportation costs and the increase in the Company's annual production guidance.
Cash G&A expenses were $1.53 per BOE for the quarter, compared to $1.87 per BOE in the previous quarter. The decrease in cash G&A expenses was due to continued cost savings initiatives and the impact of reductions in staffing levels following asset divestments during the year. Enerplus is reducing its cash G&A expense guidance to $1.75 per BOE, from $1.85 per BOE.
Enerplus remains in a strong financial position. Total debt net of cash at June 30, 2017 was $308.1 million. Total debt was comprised of $693.1 million of senior notes outstanding. The Company was undrawn on its $800 million bank credit facility, and had a cash balance of $385.1 million. At June 30, 2017, Enerplus' net debt to adjusted funds flow ratio was 0.7 times.
AVERAGE DAILY PRODUCTION(1)
| Three months ended June 30, 2017 |
Six months ended June 30, 2017 |
||||||
| Oil & NGL (Mbbl/d) |
Natural gas (MMcf/d) |
Total |
Oil & NGL (Mbbl/d) |
Natural gas (MMcf/d) |
Total |
||
| Williston Basin |
28.9 |
19.9 |
32.2 |
25.5 |
19.1 |
28.7 |
|
| Marcellus |
0.0 |
204.7 |
34.1 |
0.0 |
204.7 |
34.1 |
|
| Canadian Waterfloods(2) |
11.0 |
13.0 |
13.1 |
12.0 |
16.9 |
14.8 |
|
| Other(2) |
1.1 |
33.8 |
6.7 |
1.2 |
40.7 |
8.0 |
|
| Total |
41.0 |
271.3 |
86.2 |
38.7 |
281.4 |
85.6 |
|
| (1) |
Table may not add due to rounding. |
| (2) |
Includes volumes from Canadian properties that were divested during the first six months of 2017. |
SUMMARY OF WELLS BROUGHT ON-STREAM(1)
| Three months ended June 30, 2017 |
Six months ended June 30, 2017 |
||||||||||
| Operated |
Non Operated |
Operated |
Non Operated |
||||||||
| Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
||||
| Williston Basin |
11 |
8.1 |
1 |
0.5 |
19 |
14.8 |
1 |
0.5 |
|||
| Marcellus |
0 |
0.0 |
13 |
2.3 |
0 |
0.0 |
27 |
3.1 |
|||
| Canadian Waterfloods |
3 |
3.0 |
0 |
0.0 |
5 |
5.0 |
0 |
0.0 |
|||
| Total |
14 |
11.1 |
14 |
2.7 |
24 |
19.8 |
28 |
3.6 |
|||
| (1) |
Table may not add due to rounding. |
ASSET ACTIVITY
Williston Basin
Williston Basin production averaged 32,240 BOE per day (90% liquids) during the second quarter of 2017, a 29% increase compared to the prior quarter. Second quarter Williston Basin production was comprised of 28,047 BOE per day in North Dakota, a 35% increase from the prior quarter, and 4,193 BOE per day in Montana, approximately flat to the prior quarter.
In the second quarter, Enerplus brought on-stream 11 gross operated wells (74% average working interest) across its acreage at Fort Berthold. Of note is the Arctic 94-36BH well which has continued to produce at strong rates after three months on production. The well has delivered a peak 90-day production rate of 1,250 BOE per day. This 4,300 foot lateral well was completed with a proppant volume of approximately 2,300 pounds per foot, higher than Enerplus' base completion design of 1,000 pounds per foot. Two wells were brought on production from the Marsupials pad with an average lateral length of 4,300 feet and an average peak 30-day production rate per well of 1,318 BOE per day. Four wells on the Mountains pad were brought on production with an average lateral length of 9,300 feet and an average peak 30-day production rate per well of 1,275 BOE per day.
The Company drilled 10 gross operated wells (85% average working interest) in the second quarter, including a 20,000 ft. (10,000 ft. lateral) well drilled in under 12 days from spud to rig release, a new record for the Company. This represents an 18% improvement in drilling days compared to the Company's previous fastest drill.
Marcellus
Marcellus production averaged 205 MMcf per day during the second quarter of 2017, approximately flat to the previous quarter. Production volumes in the quarter included approximately 6 MMcf per day related to a gas balancing adjustment. Thirteen gross non-operated wells (18% average working interest) were brought on-stream during the second quarter of 2017. Twelve of these wells had more than 30 days on production as of the date of this news release with an average lateral length of 4,900 feet per well and an average peak 30-day production rate per well of 13.2 MMcf per day.
The Company participated in drilling 13 gross non-operated wells (18% average working interest) during the second quarter.
Canadian Waterfloods
Canadian waterflood production averaged 13,144 BOE per day (83% liquids) during the second quarter of 2017, a decrease of 20% from the previous quarter primarily due to the divestment of the Brooks property during the quarter. Activity in the quarter was largely focused at Ante Creek with the continued advancement of waterflood implementation across the field. Water injection has been increased from 1,000 barrels of water per day in January 2017 to over 5,000 barrels of water per day currently, with a target injection of 12,000 to 15,000 barrels of water per day by year-end.
RISK MANAGEMENT
Enerplus continues to manage price risk through commodity hedging. Using swaps and collar structures, Enerplus has an average of 20,000 barrels per day of crude oil protected for the remainder of 2017 (approximately 72% of forecast crude oil production, net of royalties), 18,000 barrels per day of crude oil protected in 2018, and 4,000 barrels per day of crude oil protected in 2019.
For natural gas, Enerplus has 50,000 Mcf per day protected for the remainder of 2017 (approximately 25% of forecast natural gas production net of royalties) using collar structures.
| Commodity Hedging Detail (As at August 10, 2017) |
||||||
| WTI Crude Oil |
Nymex Natural Gas |
|||||
| Jul 1, 2017 – |
Jan 1, 2018 – |
Jul 1, 2018 – |
Jan 1, 2019 – |
Apr 1, 2019 – |
Jul 1, 2017 – Dec 31, 2017 |
|
| Swaps |
||||||
| Sold Swaps |
$53.50 |
$53.73 |
$53.73 |
$53.73 |
- |
- |
| Volume (bbls/d or Mcf/d) |
2,000 |
3,000 |
3,000 |
3,000 |
- |
- |
| Three-Way Collars |
||||||
| Sold Puts |
$39.62 |
$42.83 |
$42.63 |
$45.00 |
$43.75 |
$2.06 |
| Volume (bbls/d or Mcf/d) |
18,000 |
13,000 |
17,000 |
1,000 |
4,000 |
50,000 |
| Purchased Puts |
$50.61 |
$53.04 |
$52.56 |
$56.00 |
$54.69 |
$2.75 |
| Volume (bbls/d or Mcf/d) |
18,000 |
13,000 |
17,000 |
1,000 |
4,000 |
50,000 |
| Sold Calls |
$60.33 |
$61.99 |
$61.29 |
$70.00 |
$66.18 |
$3.41 |
| Volume (bbls/d or Mcf/d) |
18,000 |
13,000 |
17,000 |
1,000 |
4,000 |
50,000 |
| (1) |
Based on weighted average price (before premiums) assuming annual average production of 85,000 BOE/day, net of royalties and production taxes of 24%. |
2017 UPDATED GUIDANCE
Enerplus' updated 2017 guidance is summarized below.
| Guidance |
|
| Capital spending |
$450 million |
| Average annual production |
84,000 – 86,000 BOE/d (from 81,000 – 85,000 BOE/d) |
| Q4 average production |
86,000 – 91,000 BOE/d |
| Average annual crude oil and natural gas liquids production |
39,500 – 41,500 bbls/d (from 38,500 – 41,500 bbls/d) |
| Q4 average crude oil and natural gas liquids production |
43,000 – 48,000 bbls/d |
| Average royalty and production tax rate |
24% |
| Operating expense |
$6.40/BOE (from $6.85/BOE) |
| Transportation expense |
$3.90/BOE (from $4.00/BOE) |
| Cash G&A expense |
$1.75/BOE (from $1.85/BOE) |
| Differential/Basis Outlook (1) |
|
| 2017 Average U.S. Bakken crude oil differential (compared to WTI crude oil): |
US$(4.50)/bbl |
| 2017 Average Marcellus natural gas sales price differential (compared to NYMEX natural gas): |
US$(0.75)/Mcf (from US$0.60/Mcf) |
| (1) Excluding transportation costs. |
|
Q2 2017 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 11, 2017 |
| 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=1465072&s=1&k=CADC1AEF83082428A5DE5A9554453FBD |
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: |
53114555 |
SELECTED FINANCIAL AND OPERATING RESULTS
| Three months ended |
Six months ended |
||||||||
| 2017 |
2016 |
2017 |
2016 |
||||||
| Financial (000's) |
|||||||||
| Adjusted Funds Flow(4) |
$ |
114,199 |
$ |
76,047 |
$ |
234,119 |
$ |
117,774 |
|
| Dividends to Shareholders |
7,264 |
6,547 |
14,505 |
21,011 |
|||||
| Net Income/(Loss) |
129,302 |
(168,554) |
205,595 |
(342,220) |
|||||
| Debt Outstanding – net of Cash |
308,067 |
674,147 |
308,067 |
674,147 |
|||||
| Capital Spending |
101,739 |
48,120 |
222,086 |
91,396 |
|||||
| Property and Land Acquisitions |
4,713 |
343 |
7,249 |
3,897 |
|||||
| Property Divestments |
59,842 |
92,735 |
58,942 |
280,503 |
|||||
| Net Debt to Adjusted Funds Flow Ratio(4) |
0.7x |
2.0x |
0.7x |
2.0x |
|||||
| Financial per Weighted Average Shares Outstanding |
|||||||||
| Net Income/(Loss) |
$ |
0.53 |
$ |
(0.77) |
$ |
0.85 |
$ |
(1.61) |
|
| Weighted Average Number of Shares Outstanding (000's) |
242,127 |
218,128 |
241,710 |
212,420 |
|||||
| Selected Financial Results per BOE(1)(2) |
|||||||||
| Oil & Natural Gas Sales(3) |
$ |
35.96 |
$ |
24.96 |
$ |
36.14 |
$ |
21.99 |
|
| Royalties and Production Taxes |
(8.95) |
(5.51) |
(8.42) |
(4.72) |
|||||
| Commodity Derivative Instruments |
0.28 |
2.53 |
0.57 |
3.51 |
|||||
| Cash Operating Expenses |
(5.88) |
(7.20) |
(6.23) |
(7.67) |
|||||
| Transportation Costs |
(3.72) |
(2.87) |
(3.80) |
(2.88) |
|||||
| General and Administrative Expenses |
(1.53) |
(1.71) |
(1.69) |
(1.89) |
|||||
| Cash Share-Based Compensation |
— |
(0.09) |
(0.01) |
(0.09) |
|||||
| Interest, Foreign Exchange and Other Expenses |
(1.34) |
(1.21) |
(1.31) |
(1.51) |
|||||
| Current Income Tax Recovery/(Expense) |
(0.26) |
0.02 |
(0.14) |
0.02 |
|||||
| Adjusted Funds Flow(4) |
$ |
14.56 |
$ |
8.92 |
$ |
15.11 |
$ |
6.76 |
|
| Three months ended June 30, |
Six months ended June 30, |
||||||||
| 2017 |
2016 |
2017 |
2016 |
||||||
| Average Daily Production(2) |
|||||||||
| Crude Oil (bbls/day) |
36,861 |
39,079 |
35,030 |
39,294 |
|||||
| Natural Gas Liquids (bbls/day) |
4,133 |
4,829 |
3,648 |
5,161 |
|||||
| Natural Gas (Mcf/day) |
271,292 |
298,503 |
281,393 |
307,827 |
|||||
| Total (BOE/day) |
86,209 |
93,659 |
85,577 |
95,759 |
|||||
| % Crude Oil and Natural Gas Liquids |
48% |
47% |
45% |
46% |
|||||
| Average Selling Price (2)(3) |
|||||||||
| Crude Oil (per bbl) |
$ |
55.66 |
$ |
46.48 |
$ |
56.54 |
$ |
39.00 |
|
| Natural Gas Liquids (per bbl) |
25.14 |
15.67 |
30.57 |
13.37 |
|||||
| Natural Gas (per Mcf) |
3.48 |
1.49 |
3.56 |
1.64 |
|||||
| (1) |
Non-cash amounts have been excluded. |
| (2) |
Based on Company interest production volumes. See "Presentation of Production Information" below. |
| (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" section in this news release. |
| Three months ended June 30, |
Six months ended June 30, |
|||||||||||
| Average Benchmark Pricing |
2017 |
2016 |
2017 |
2016 |
||||||||
| WTI crude oil (US$/bbl) |
$ |
48.29 |
$ |
45.59 |
$ |
50.10 |
$ |
39.52 |
||||
| AECO natural gas– monthly index (CDN$/Mcf) |
2.77 |
1.25 |
2.86 |
1.68 |
||||||||
| AECO natural gas – daily index (CDN$/Mcf) |
2.78 |
1.40 |
2.74 |
1.62 |
||||||||
| NYMEX natural gas – last day (US$/Mcf) |
3.18 |
1.95 |
3.25 |
2.02 |
||||||||
| USD/CDN average exchange rate |
1.34 |
1.29 |
1.33 |
1.33 |
||||||||
| Share Trading Summary |
CDN (1) - ERF |
U.S. (2) - ERF |
|||
| For the three months ended June 30, 2017 |
(CDN$) |
(US$) |
|||
| High |
$ |
11.48 |
$ |
8.54 |
|
| Low |
$ |
8.97 |
$ |
6.52 |
|
| Close |
$ |
10.52 |
$ |
8.12 |
|
| (1) TSX and other Canadian trading data combined. |
|||||
| (2) NYSE and other U.S. trading data combined. |
|||||
| 2017 Dividends per Share |
CDN$ |
US$(1) |
|||
| First Quarter Total |
$ |
0.03 |
$ |
0.02 |
|
| Second Quarter Total |
$ |
0.03 |
$ |
0.02 |
|
| Total Year to Date |
$ |
0.06 |
$ |
0.04 |
|
| (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 natural 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 average production volumes in 2017 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 2017 and beyond; 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 2017 and its impact on our production level and land holdings; our future royalty and production and cash taxes; 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, our updated 2017 guidance contained in this news release is based on the following prices for the rest of the year: a WTI price of US$50.00/bbl, a NYMEX price of US$3.00/Mcf, an AECO price of $2.40/GJ and a USD/CDN exchange rate of 1.30. 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 continued volatility, 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 Annual Information Form, management's discussion and analysis for the year-ended December 31, 2016. and Form 40-F at December 31, 2016).
The forward-looking information contained in this press release speak only as of the date of this press release. Enerplus does not undertake any obligation to publicly update or revise any forward-looking information contained herein, except as required by applicable laws.
NON-GAAP MEASURES
In this news release, we use the terms "adjusted funds flow" and "net debt to adjusted funds flow ratio" as measures to analyze operating performance, leverage and liquidity. "Adjusted 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. "Net debt to adjusted funds flow ratio" is calculated as total debt net of cash and restricted cash, divided by a trailing 12 months of adjusted funds flow. Calculation of these terms is described in Enerplus' 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 "adjusted funds flow" and "net debt to adjusted funds flow" are useful supplemental measures as they provide an indication of the results generated by Enerplus' principal business activities. However, these 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 2017 MD&A.
Electronic copies of Enerplus Corporation's Second Quarter 2017 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 the Company's 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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