Enerplus Announces Third Quarter 2018 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' Third Quarter 2018 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, Nov. 9, 2018 - Enerplus Corp. ("Enerplus" or the "Company") (TSX & NYSE: ERF) today reported its third quarter 2018 operating and financial results. The Company's third quarter 2018 net income was $86.9 million or $0.35 per share. For the first nine months of 2018, net income was $129.0 million, or $0.53 per share.
HIGHLIGHTS
- Total production of 96,861 BOE per day in Q3, up 4% from the prior quarter
- Liquids production of 53,430 barrels per day in Q3, up 7% from the prior quarter
- Generated adjusted funds flow of $210 million during Q3, an increase of 21% from the prior quarter
- 2018 annual production guidance revised to the upper-end of the prior ranges, now 92,500 to 93,000 BOE per day with 49,500 to 50,000 barrels per day of liquids
- 2018 annual liquids production growth projected to be 22% at the midpoint of guidance
- 2018 capital spending guidance unchanged at $585 million
- Repurchased 1.6 million common shares in September and October for $25 million
- Visibility to meaningful free cash flow in Q4 2018
- Encouraging results from four DJ Basin appraisal wells (three Codell, one Niobrara)
- Reduced cash G&A guidance by $0.05 per BOE to $1.50 per BOE
- Balance sheet remains among the strongest in the peer group with a net debt to adjusted funds flow ratio of 0.4 times
"With our third quarter results, we are on track in 2018 to generate robust double-digit returns on capital employed, deliver over 20% liquids production growth and generate meaningful free cash flow," stated Ian C. Dundas, President and Chief Executive Officer. "At the same time, we are maintaining top-quartile balance sheet strength."
"In addition to our dividend, we continued returning capital to shareholders through share repurchases in the third quarter and have repurchased $25 million in stock since September. Based on current market conditions, we expect to continue to allocate a portion of our free cash flow to repurchase shares", noted Dundas.
THIRD QUARTER FINANCIAL AND OPERATIONAL SUMMARY
Production
Third quarter production averaged 96,861 BOE per day, an increase of 4% from the second quarter. Liquids production for the quarter averaged 53,430 barrels per day (91% crude oil and 9% natural gas liquids), an increase of 7% from the second quarter. This represents growth of 22% on total production and 37% on liquids production compared to the same period in 2017.
Capital activity for the remainder of the year will be largely focused on drilling in North Dakota in preparation for the 2019 program. Enerplus expects flat to modest sequential oil production growth in the fourth quarter and is providing fourth quarter liquids production guidance of 53,500 to 54,500 barrels per day. Full year 2018 production guidance is revised to 92,500 to 93,000 BOE per day, with liquids production guidance revised to 49,500 to 50,000 barrels per day, the upper end of the prior ranges. The guidance implies 22% annual liquids production growth in 2018 at the midpoint.
Net Income and Adjusted Funds Flow
Enerplus generated net income of $86.9 million in the third quarter of 2018, an increase of $74.5 million from the previous quarter due to lower non-cash mark-to-market losses on the Company's commodity derivative instruments and higher realized commodity prices and production.
Adjusted funds flow was $210.4 million during the third quarter, up 21% from the second quarter. This was driven by higher realized crude oil and natural gas prices and higher production in the third quarter. This represents adjusted funds flow growth of over 130% compared to the same period in 2017.
Pricing Realizations and Cost Structure
Enerplus' realized Bakken oil price differential averaged US$2.54 per barrel below WTI in the third quarter, an improvement from US$3.42 per barrel below WTI in the prior quarter.
For the fourth quarter of 2018, Enerplus has fixed physical differential sales of 20,250 barrels per day of Bakken oil production at approximately US$2.53 per barrel below WTI. Its remaining production is sold on a monthly basis into the highest netback markets available. With spot Bakken differentials widening to date in the fourth quarter, Enerplus is revising its annual average Bakken differential guidance to US$3.80 per barrel below WTI, from US$3.50 per barrel below WTI previously.
For 2019, the Company has recently added additional fixed differential contracts and now has physical differential sales of approximately 16,000 barrels per day for its Bakken oil production at approximately US$3.00 per barrel below WTI.
The Company's realized third quarter Marcellus natural gas price differential was US$0.48 per Mcf below NYMEX, a 30% improvement from the second quarter.
Third quarter operating expenses were $6.81 per BOE, a decrease from $7.20 per BOE in the second quarter. Transportation costs of $3.70 per BOE were 4% higher than the prior quarter. Cash general and administrative ("G&A") expenses of $1.35 per BOE were 6% lower compared to the prior quarter. Enerplus is reducing its 2018 cash G&A expense guidance by $0.05 per BOE to $1.50 per BOE.
Capital Expenditures and Balance Sheet Position
Exploration and development capital spending in the third quarter was $193.3 million and was associated with drilling 16.8 net wells and bringing 23.4 net wells on production across the Company. Through the first nine months of 2018, capital expenditures have totaled $521.8 million. Capital activity in the fourth quarter will be largely focused on drilling in North Dakota in preparation for the 2019 program. Enerplus has reaffirmed its 2018 capital budget of $585 million.
Total debt net of cash at September 30, 2018 was $313.6 million. Total debt was comprised of $661.2 million of senior notes outstanding. The Company was undrawn on its $800 million bank credit facility and had a cash balance of $347.6 million. At September 30, 2018, Enerplus' net debt to adjusted funds flow ratio was 0.4 times. Subsequent to the quarter, the Company renewed its $800 million bank credit facility for one year, maturing October 31, 2021.
Share Repurchase
During the third quarter, Enerplus repurchased 544,300 common shares under its Normal Course Issuer Bid at an average share price of $15.54. Subsequent to the end of the third quarter, the Company repurchased an additional 1,071,366 common shares at an average share price of $15.42. In total, the Company has repurchased 1,615,666 shares in 2018 for a cost of $25.0 million.
Based on current market conditions, Enerplus expects to continue to repurchase shares using a portion of its free cash flow.
ASSET ACTIVITY
Average Daily Production(1)
| Three months ended | Nine months ended | |||||||||
| Crude Oil (Mbbl/d) | Natural Gas Liquids (Mbbl/d) | Natural gas (MMcf/d) | Total Production (Mboe/d) | Crude Oil (Mbbl/d) | Natural Gas Liquids (Mbbl/d) | Natural gas (MMcf/d) | Total Production (Mboe/d) | |||
| Williston Basin | 38.9 | 3.6 | 25.8 | 46.7 | 34.2 | 3.4 | 23.6 | 41.5 | ||
| Marcellus | - | - | 210.3 | 35.0 | - | - | 207.0 | 34.5 | ||
| Canadian Waterfloods | 9.0 | 0.1 | 3.5 | 9.7 | 9.1 | 0.1 | 4.2 | 9.9 | ||
| DJ Basin | 0.8 | - | - | 0.8 | 0.4 | - | - | 0.4 | ||
| Other(2) | 0.2 | 0.9 | 21.1 | 4.6 | 0.2 | 1.0 | 24.7 | 5.3 | ||
| Total | 48.9 | 4.6 | 260.6 | 96.9 | 43.9 | 4.5 | 259.6 | 91.7 | ||
| (1) | Table may not add due to rounding. |
| (2) | Nine months ended September 30, 2018 includes approximately 600 boe/d of production from Canadian natural gas properties sold in Q1 2018. |
Summary of Wells Brought On-Stream(1)
| Three months ended | Nine months ended | ||||||||||
| Operated | Non-Operated | Operated | Non-Operated | ||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||
| Williston Basin | 18 | 16.3 | 6 | 1.8 | 37 | 31.8 | 9 | 2.4 | |||
| Marcellus | - | - | 9 | 1.9 | - | - | 34 | 5.2 | |||
| Canadian Waterfloods | - | - | 1 | - | 2 | 1.9 | 1 | - | |||
| DJ Basin | 4 | 3.2 | - | - | 4 | 3.2 | - | - | |||
| Other | - | - | 1 | 0.2 | - | - | 2 | 0.4 | |||
| Total | 22 | 19.5 | 17 | 3.9 | 43 | 36.9 | 46 | 8.1 | |||
| (1) | Table may not add due to rounding. |
Williston Basin
Williston Basin production averaged 46,709 BOE per day (83% oil) during the third quarter of 2018, up 7% from the second quarter of 2018. Third quarter Williston Basin production was comprised of 43,390 BOE per day in North Dakota, and 3,319 BOE per day in Montana.
Enerplus brought on-stream 18 gross operated wells (91% average working interest, 15 two-mile laterals and 3 one-mile laterals) across four pads at Fort Berthold during the third quarter. The average peak 30-day production rates per well was 1,513 BOE per day (78% oil, on a three-stream basis) with an average completed lateral length per well at 8,600 feet.
The Company drilled 11 gross operated wells (91% average working interest) in the third quarter.
The Company continues to run two operated drilling rigs at Fort Berthold.
Marcellus
Marcellus production averaged 210 MMcf per day during the third quarter, an increase of 4% from the previous quarter.
Nine gross non-operated wells (22% average working interest) were brought on-stream during the quarter with an average completed lateral length of 6,500 feet per well and average peak 30-day production rates per well of 15.4 MMcf per day.
The Company participated in drilling 15 gross non-operated wells (15% average working interest) during the third quarter.
Canadian Waterfloods
Canadian waterflood production averaged 9,670 BOE per day (93% oil) during the third quarter, largely flat to the previous quarter. Capital activity in the third quarter was primarily focused on the Company's drilling program at Medicine Hat.
DJ Basin
Enerplus brought on production four gross (3.2 net) operated wells in the DJ Basin during the third quarter. In total, the Company has drilled five gross (4.2 net) wells in the play including its first well, Maple 8-67-36-25C, which has produced approximately 100,000 barrels of oil (130,000 BOE, three-stream basis) in its first 12 producing months. Results from the additional four wells completed during the third quarter are encouraging with all four wells meeting or tracking above the Maple well's performance. On average, the wells have each produced 29,700 barrels of oil in their first 90 days with peak 90-day average production rates per well of 330 barrels of oil per day. On a three-stream basis, based on estimated natural gas production and NGL yield, the wells have produced 37,400 BOE per well in their first 90 days with peak 90-day average production rates per well of 415 BOE per day. The wells are on track to produce 100,000 barrels of oil in 12 months on production - competitive with other recent wells in the basin.
Three of the wells were completed in the Codell formation with one well completed in the Niobrara formation. The Niobrara well, Cherry Creek 8-67-28-27N, has been among the strongest performing wells and has given the Company further confidence in the prospectivity of the Niobrara across a portion of the Company's acreage, with the potential to materially add to the scope of the asset.
With positive well results and a supportive regulatory environment, Enerplus plans to continue delineation drilling and progressing midstream options in 2019. The Company will provide a further update regarding its 2019 capital plans in connection with its 2019 budget.
Updated Fourth Quarter and Full Year 2018 Guidance
The Company has provided fourth quarter production guidance, revised its annual average production guidance, and reduced its cash G&A guidance. All other guidance remains unchanged.
| 2018 Guidance | |
| Capital spending | $585 million |
| Average annual production | 92,500 to 93,000 BOE/day (from 91,000 to 93,000 BOE/day) |
| Average annual crude oil and natural gas liquids production | 49,500 to 50,000 bbls/day (from 49,000 to 50,000 bbls/d) |
| Q4 2018 liquids production | 53,500 to 54,500 bbls/day |
| Average royalty and production tax rate | 25% |
| Operating expense | $7.00/BOE |
| Transportation expense | $3.60/BOE |
| Cash G&A expense | $1.50/BOE (from $1.55/BOE) |
| 2018 Full-Year Differential/Basis Outlook (1) | |
| U.S. Bakken crude oil differential (compared to WTI crude oil) | US$(3.80)/bbl (from US$(3.50)/bbl) |
| Marcellus natural gas sales price differential (compared to NYMEX natural gas) | US$(0.40)/Mcf |
| (1) | Excluding transportation costs. |
RISK MANAGEMENT
Enerplus continues to manage price risk through commodity hedging. Using swaps and collar structures, Enerplus has an average of 23,000 barrels per day of crude oil protected for the remainder of 2018, 23,140 barrels per day protected in 2019, and 16,000 barrels per day protected in 2020.
For natural gas, Enerplus has 33,370 Mcf per day protected for the fourth quarter of 2018 using collar structures.
Commodity Hedging Detail (As at October 30, 2018)
| WTI Crude Oil | Nymex Natural Gas (US$/Mcf) (1) | ||||||||
| Oct 1 – Dec 31, 2018 | Jan 1 – Mar 31, 2019 | Apr 1 – Jun 30, 2019 | Jul 1, – Sep 30, 2019 | Oct 1, – Dec 31, 2019 | Jan 1, – Dec 31, 2020 | Oct 1, – Oct 31, 2018 | Nov 1, – Dec 31, 2018 | ||
| Swaps | |||||||||
| Sold Swaps | $53.73 | $53.73 | - | - | - | - | - | - | |
| Volume (bbls/d or Mcf/d) | 3,000 | 3,000 | - | - | - | - | - | - | |
| Three-Way Collars | |||||||||
| Sold Puts | $42.74 | $44.28 | $44.50 | $44.64 | $44.64 | $46.88 | - | - | |
| Volume (bbls/d or Mcf/d) | 20,000 | 17,000 | 23,500 | 24,500 | 24,500 | 16,000 | - | - | |
| Purchased Puts | $52.48 | $54.12 | $54.59 | $54.81 | $54.81 | $57.50 | $2.75 | $2.75 | |
| Volume (bbls/d or Mcf/d) | 20,000 | 17,000 | 23,500 | 24,500 | 24,500 | 16,000 | 40,000 | 30,000 | |
| Sold Calls | $61.10 | $64.12 | $65.52 | $65.95 | $65.99 | $72.50 | $3.38 | $3.47 | |
| Volume (bbls/d or Mcf/d) | 20,000 | 17,000 | 23,500 | 24,500 | 24,500 | 16,000 | 40,000 | 30,000 | |
| (1) | Based on weighted average price (before premiums). |
| (2) | The total average deferred premium spent on the three-way collars is US$1.60/bbl from October 1, 2018 to December 31, 2020. |
Q3 2018 CONFERENCE CALL DETAILS
A conference call hosted by Ian C. Dundas, President and CEO will be held at 9:00 AM MT (11:00 AM ET) today to discuss these results. Details of the conference call are as follows:
| Date: | Friday, November 9, 2018 |
| Time: | 9:00 AM MT (11:00 AM ET) |
| Dial-In: | 587-880-2171 (Alberta) |
| 1-888-390-0546 (Toll Free) | |
| Conference ID: | 05319137 |
| Audiocast: | https://event.on24.com/wcc/r/1850900/FDCF5A6B9BA63518D1E2697B62639ED6 |
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:
| Replay Dial-In: | 1-888-390-0541 (Toll Free) |
| Replay Passcode: | 31937 # |
SELECTED FINANCIAL AND OPERATING RESULTS
| SELECTED FINANCIAL RESULTS | Three months ended September 30, | Nine months ended September 30, | ||||||||||
| 2018 | 2017 | 2018 | 2017 | |||||||||
| Financial (000's) | ||||||||||||
| Net Income/(Loss) | $ | 86,923 | $ | 16,131 | $ | 128,964 | $ | 221,726 | ||||
| Adjusted Funds Flow(4) | 210,351 | 90,386 | 539,221 | 324,505 | ||||||||
| Dividends to Shareholders - Declared | 7,355 | 7,264 | 22,022 | 21,769 | ||||||||
| Debt Outstanding – net of Cash and Restricted Cash | 313,591 | 318,273 | 313,591 | 318,273 | ||||||||
| Capital Spending | 193,264 | 119,102 | 521,818 | 341,188 | ||||||||
| Property and Land Acquisitions | 1,702 | 2,222 | 16,366 | 9,471 | ||||||||
| Property Divestments | (762) | (1,361) | 6,026 | 57,581 | ||||||||
| Net Debt to Adjusted Funds Flow Ratio(4) | 0.4x | 0.7x | 0.4x | 0.7x | ||||||||
| Financial per Weighted Average Shares Outstanding | ||||||||||||
| Net Income - Basic | $ | 0.35 | $ | 0.07 | $ | 0.53 | $ | 0.92 | ||||
| Net Income - Diluted | 0.35 | 0.07 | 0.52 | 0.90 | ||||||||
| Weighted Average Number of Shares Outstanding (000's) | 245,235 | 242,129 | 244,659 | 241,854 | ||||||||
| Selected Financial Results per BOE(1)(2) | ||||||||||||
| Oil & Natural Gas Sales(3) | $ | 52.32 | $ | 33.23 | $ | 48.03 | $ | 35.21 | ||||
| Royalties and Production Taxes | (13.39) | (7.98) | (12.03) | (8.28) | ||||||||
| Commodity Derivative Instruments | (2.68) | 0.40 | (1.32) | 0.51 | ||||||||
| Cash Operating Expenses | (6.80) | (6.73) | (7.01) | (6.39) | ||||||||
| Transportation Costs | (3.70) | (3.61) | (3.60) | (3.74) | ||||||||
| General and Administrative Expenses | (1.35) | (1.61) | (1.49) | (1.67) | ||||||||
| Cash Share-Based Compensation | 0.02 | (0.10) | (0.09) | (0.04) | ||||||||
| Interest, Foreign Exchange and Other Expenses | (0.81) | (1.17) | (0.94) | (1.25) | ||||||||
| Current Income Tax Recovery/(Expense) | (0.01) | (0.01) | (0.01) | (0.10) | ||||||||
| Adjusted Funds Flow(4) | $ | 23.60 | $ | 12.42 | $ | 21.54 | $ | 14.25 | ||||
| SELECTED OPERATING RESULTS | Three months ended September 30, | Nine months ended September 30, | ||||||||||
| 2018 | 2017 | 2018 | 2017 | |||||||||
| Average Daily Production(2) | ||||||||||||
| Crude Oil (bbls/day) | 48,867 | 35,245 | 43,892 | 35,102 | ||||||||
| Natural Gas Liquids (bbls/day) | 4,563 | 3,681 | 4,487 | 3,659 | ||||||||
| Natural Gas (Mcf/day) | 260,591 | 241,212 | 259,629 | 267,852 | ||||||||
| Total (BOE/day) | 96,861 | 79,128 | 91,651 | 83,403 | ||||||||
| % Crude Oil and Natural Gas Liquids | 55% | 49% | 53% | 46% | ||||||||
| Average Selling Price (2)(3) | ||||||||||||
| Crude Oil (per bbl) | $ | 83.98 | $ | 54.21 | $ | 78.58 | $ | 55.75 | ||||
| Natural Gas Liquids (per bbl) | 25.95 | 26.22 | 28.85 | 29.09 | ||||||||
| Natural Gas (per Mcf) | 3.22 | 2.58 | 3.14 | 3.26 | ||||||||
| Net Wells Drilled | 17 | 10 | 49 | 39 | ||||||||
| (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 September 30, | Nine months ended September 30, | |||||||||||
| Average Benchmark Pricing | 2018 | 2017 | 2018 | 2017 | ||||||||
| WTI crude oil (US$/bbl) | $ | 69.50 | $ | 48.20 | $ | 66.75 | $ | 49.47 | ||||
| Brent (ICE) crude oil (US$/bbl) | 75.97 | 52.18 | 72.68 | 52.59 | ||||||||
| AECO natural gas– monthly index (CDN$/Mcf) | 1.35 | 2.04 | 1.41 | 2.58 | ||||||||
| NYMEX natural gas – last day (US$/Mcf) | 2.90 | 3.00 | 2.90 | 3.17 | ||||||||
| USD/CDN average exchange rate | 1.31 | 1.25 | 1.29 | 1.31 | ||||||||
| Share Trading Summary | CDN(1) - ERF | U.S.(2) - ERF | ||||
| For the three months ended September 30, 2018 | (CDN$) | (US$) | ||||
| High | $ | 18.04 | $ | 13.87 | ||
| Low | $ | 14.51 | $ | 11.03 | ||
| Close | $ | 15.95 | $ | 12.34 | ||
| (1) | TSX and other Canadian trading data combined. |
| (2) | NYSE and other U.S. trading data combined. |
| 2018 Dividends per Share | CDN$ | US$(1) | ||||
| First Quarter Total | $ | 0.03 | $ | 0.02 | ||
| Second Quarter Total | $ | 0.03 | $ | 0.02 | ||
| Third Quarter Total | $ | 0.03 | $ | 0.02 | ||
| Total Year to Date | $ | 0.09 | $ | 0.06 | ||
| (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. 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 2018 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 estimated differentials and our commodity risk management programs in 2018 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 2018 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; and expectations regarding our share repurchase program, including sources of funds therefrom.
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 initial production performance referenced should be considered preliminary data and such data is not necessarily indicative of long-term performance, or of ultimate recovery; 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 2018 guidance contained in this news release is based on the following forward prices: WTI US$66.86/bbl, NYMEX US$2.96/Mcf, and a USD/CDN exchange rate of 1.29. 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, 2017, and Form 40-F at December 31, 2017). The purpose of our free cash flow guidance is to assist readers in understanding our expected and targeted financial results, and this information may not be appropriate for other purposes.
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", "free cash flow", "net debt to adjusted funds flow ratio" and "total debt net of cash" 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. "Total debt net of cash" is calculated as senior notes plus any outstanding bank credit facility balance, minus cash and restricted cash. Free cash flow is defined as "Adjusted funds flow less exploration and development capital spending". 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", "free cash flow", "net debt to adjusted funds flow", and "total debt net of cash" 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' Third Quarter 2018 MD&A.
Electronic copies of Enerplus Corp.'s Third Quarter 2018 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 investorrelations@enerplus.com.
Follow @EnerplUSCorp on Twitter at https://twitter.com/EnerplUSCorp.
Ian C. Dundas
President & Chief Executive Officer
Enerplus Corp.
SOURCE Enerplus Corp.
Contact
Enerplus Corp., The Dome Tower, Suite 3000, 333 - 7th Avenue SW, Calgary, Alberta T2P 2Z1, T. 403-298-2200 F. 403-298-2211, www.enerplus.com
