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Enerplus Continues Operational Momentum in Third Quarter 2014 & Increases Annual Production Guidance

November 7, 2014

CALGARY, Nov. 7, 2014 /CNW/ - Enerplus Corporation ("Enerplus") (TSX: ERF) (NYSE: ERF) continued to deliver consistent, strong operational and financial performance during the third quarter of 2014.


  • Daily production averaged approximately 104,000 BOE, essentially unchanged from the second quarter. Crude oil and natural gas liquids production increased again in the third quarter to average 44,200 barrels per day, up 700 barrels over the second quarter. We continue to achieve strong performance from our Bakken/Three Forks properties in North Dakota with production increasing by approximately 1,600 BOE per day.

  • Natural gas production was maintained quarter over quarter despite an average of 3,000 - 4,000 BOE per day of Marcellus production being temporarily curtailed due to pipeline maintenance and low natural gas prices in the region.

  • As a result of strong performance year to date, and despite the sale of 3,500 BOE per day of non-core production, we are raising our annual average production guidance again. We are increasing the low end of our range by 2,000 BOE per day and now expect full year production to average between 102,000 - 104,000 BOE per day. The low end of this range largely reflects the risk of additional curtailment in the Marcellus in the fourth quarter. We have continued to see crude oil production growth in the fourth quarter and expect to achieve our annual average liquids target of 44,000 barrels per day.

  • We continued to execute on our non-core divestment strategy, completing two transactions and further strengthening our financial position. On September 30, 2014, we closed the sale of approximately 1,900 BOE per day of non-operated production in Canada, 75% weighted to natural gas. We also sold an additional 1,200 BOE per day of Canadian non-operated production (90% weighted to natural gas) which closed in early November 2014.

  • The total proceeds from these transactions are approximately $91 million reflecting attractive metrics of approximately $30,000 per flowing barrel of production that is predominately natural gas. We intend to continue to look for opportunities to rationalize non-core production, providing us with the opportunity to accelerate spending on our core assets while maintaining our financial strength.

  • We continued to execute our capital spending program investing $208 million on development drilling activities during the quarter. Our U.S. assets attracted the majority of our capital spending. Roughly two thirds of the capital, drilling and on-stream activity was attributable to the Bakken and the Marcellus in the quarter. In total, we drilled 19.3 net wells and brought 17.3 net wells on-stream across our portfolio.

  • Our non-core divestments have generated proceeds of over $200 million year-to-date. As a result of this success, we have redeployed a portion of these proceeds to advance opportunities within our core properties. We had accelerated some of our 2015 drilling activity into the fourth quarter of 2014, particularly in the Wilrich and at Fort Berthold. We anticipate this will have only a modest production impact in 2014 but will bring additional volumes on-stream earlier in 2015. We plan to spend an additional $30 million this year, and are adjusting our full year capital spending to $830 million.


  • Despite the drop in commodity prices, funds flow was maintained quarter over quarter at $213 million or $1.04 per share.

  • Dividends paid to shareholders represented 26% of funds flow during the quarter. As previously announced, with the strength of our balance sheet and the improved sustainability of our business, we elected to suspend our reinvestment program (the Stock Dividend Program), thereby reducing dilution and helping to improve our per share metrics.

  • Our realized commodity prices declined in the third quarter as both the benchmark price of crude oil and natural gas declined. The average realized price on our crude oil sales was CDN$86.49 per barrel, down 9% from the second quarter. The average realized selling price of our natural gas was CDN$3.22 per Mcf, a 20% reduction compared to the second quarter.

  • Our strong hedge positions are expected to provide a high level of cash flow protection for the remainder of 2014 and into 2015. For the remainder of 2014, we have approximately 64% of our forecast net crude oil production, after royalties, swapped at an average price of US$95.29 per barrel. For the first and second half of 2015, we have swapped 15,500 barrels per day and 8,000 barrels per day, respectively, of crude oil at an average price of US$93.58 and US$93.86 per barrel. With respect to natural gas, we have downside protection on approximately 50% of our forecast net production after royalties for the remainder of 2014. We also have downside protection on approximately 80 MMcf per day of natural gas production in place for 2015.

  • Cash general and administrative expenses were consistent with the second quarter at $1.97 per BOE and we are maintaining our full year guidance of $2.30 per BOE. We have reduced our guidance on share based compensation from $0.60 per BOE to $0.45 per BOE as a result of the decline in our share price.

  • Operating costs increased to $10.67 per BOE, up 6% from the second quarter due to production curtailments on our lower operating cost Marcellus properties, seasonal well servicing and repairs and maintenance costs. Based on continued production curtailments expected in the Marcellus in the fourth quarter, we are revising our operating cost guidance back to our original estimate for 2014 of $10.25 per BOE.

  • We closed our US$200 million private placement of 3.79%, 10 year average life, senior notes which we announced in the second quarter. The proceeds were used to repay outstanding bank debt. At September 30, 2014 only 5% of our $1 billion credit facility was drawn and our debt-to-trailing 12 month funds flow ratio was 1.3x.

Three months ended September 30, Nine months ended September 30,
2014 2013 2014 2013
Financial (000's)
Funds Flow $ 212,779 $ 196,187 $ 646,502 $ 573,492
Cash and Stock Dividends 55,438 54,405 165,587 162,199
Net Income 67,430 (3,720) 147,424 18,350
Debt Outstanding - net of cash 1,091,110 964,577 1,091,110 964,577
Capital Spending 207,838 145,811 630,027 458,402
Property and Land Acquisitions 3,986 15,792 17,186 71,451
Property Dispositions 68,931 124,462 185,631 197,086
Debt to Trailing 12-Month Funds Flow 1.3x 1.2x 1.3x 1.2x
Financial per Weighted Average Shares Outstanding
Funds Flow $ 1.04 $ 0.98 $ 3.17 $ 2.87
Net Income (Basic) 0.33 (0.02) 0.72 0.09
Weighted Average Number of Shares Outstanding (000's) 205,164 201,117 204,174 200,002
Selected Financial Results per BOE(1)(2)
Oil & Natural Gas Sales(3) $ 46.13 $ 53.61 $ 50.66 $ 49.67
Royalties and Production Taxes (10.36) (11.91) (11.31) (10.46)
Commodity Derivative Instruments (0.26) (1.30) (1.52) 0.42
Operating Costs (10.67) (10.58) (10.28) (10.52)
General and Administrative (1.97) (2.48) (2.08) (2.63)
Share-Based Compensation 0.54 (0.60) (0.44) (0.58)
Interest, Foreign Exchange and Other Expenses (1.18) (1.78) (1.48) (1.78)
Taxes - (0.65) (0.40) (0.33)
Funds Flow $ 22.23 $ 24.31 $ 23.15 $ 23.79

Three months ended September 30, Nine months ended September 30,
2014 2013 2014 2013
Average Daily Production(2)
Crude oil (bbls/day) 40,332 38,883 39,328 38,426
NGLs (bbls/day) 3,869 2,985 3,591 3,357
Natural gas (Mcf/day) 359,007 275,164 356,288 279,212
Total (BOE/day) 104,035 87,729 102,300 88,318
% Natural Gas 58% 52% 58% 53%
Average Selling Price(2)(3)
Crude oil (per bbl) $ 86.49 $ 96.30 $ 90.91 $ 86.05
NGLs (per bbl) 44.85 49.88 53.01 51.48
Natural gas (per Mcf) 3.22 2.96 4.04 3.26
Net Wells drilled 19 15 63 50
(1) Non-cash amounts have been excluded.
(2) Based on Company interest production volumes. See "Basis of Presentation" section in the following MD&A.
(3) Net of oil and gas transportation costs, but before royalties and the effects of commodity derivative instruments.

Three months ended September 30, Nine months ended September 30,
Average Benchmark Pricing 2014 2013 2014 2013
WTI crude oil (US$/bbl) $97.17 $105.82 $99.61 $98.14
AECO- monthly index (CDN$/Mcf) 4.22 2.82 4.55 3.16
AECO- daily index (CDN$/Mcf) 4.02 2.43 4.81 3.05
NYMEX- last day (US$/Mcf) 4.06 3.58 4.55 3.67
USD/CDN exchange rate 1.09 1.04 1.09 1.02

Share Trading Summary CDN* - ERF U.S.** - ERF
For the three months ended September 30, 2014 (CDN$) (US$)
High $27.05 $25.37
Low $20.21 $18.45
Close $21.26 $18.97
* TSX and other Canadian trading data combined.
** NYSE and other U.S. trading data combined.

2014 Dividends per Share CDN$ US$(1)
First Quarter Total $0.27 $0.24
Second Quarter Total $0.27 $0.24
July $0.09 $0.08
August $0.09 $0.08
September $0.09 $0.08
Third Quarter Total $0.27 $0.24
Total Year-to-Date $0.81 $0.72
(1) US$ dividends represent CDN$ dividends converted at the relevant foreign exchange rate on the payment date.

Production and Capital Spending Three months ended
September 30, 2014
Nine months ended
September 30, 2014
Crude Oil & NGLs (BOE/day) Average
($ millions)
($ millions)
Canada 19,415 $37 19,398 $128
United States 24,786 96 23,521 255
Total Crude Oil & NGLs (BOE/day) 44,201 $133 42,919 $383
Natural Gas (Mcf/day)
Canada 154,855 $18 154,306 $115
United States 204,152 57 201,982 132
Total Natural Gas (Mcf/day) 359,006 $75 356,288 $247
Company Total (BOE/day) 104,035 $208 102,300 $630

Net Drilling Activity - for the three months ended September 30, 2014
Crude Oil Horizontal
Tie-in *
Dry &
Canada 3.4 - 3.4 2.2 5.5 -
United States 6.6 - 6.6 6.6 5.6 -
Total Crude Oil 10.0 - 10.0 8.8 11.1 -
Natural Gas
Canada 2.1 - 2.1 1.4 0.8 -
United States 7.2 - 7.2 6.9 5.4 -
Total Natural Gas 9.3 - 9.3 8.3 6.2 -
Company Total 19.3 - 19.3 17.1 17.3 -
* Wells drilled during the quarter that are pending potential completion/tie-in or abandonment as at September 30, 2014.
** Total wells brought on-stream during the quarter regardless of when they were drilled.


Drilling activity continued at a brisk pace in Fort Berthold during the third quarter with 6.6 net wells drilled and 5.6 net wells brought on-stream. Production grew again to average 22,400 BOE per day, up almost 1,600 BOE per day from the second quarter. Year-to-date, we have continued to drill into both the Bakken and Three Forks zones with 10 operated wells and 2.4 net non-operated wells brought on-stream. Production performance has continued to improve as a result of our completion optimization activity. The 30 day initial production rates on our two mile horizontal wells brought on-stream in 2014 have averaged 1,725 barrels per day, 20% above our high expected ultimate recovery type curve. We are also seeing an improvement of over 10% in the 60 day production rates which have averaged approximately 1,400 barrels per day.

In the Marcellus, drilling activity continued with 7.2 net wells drilled and 5.4 net wells brought on-stream. Basis differentials in the region continued to widen as a result of on-going production growth and the shortage of take-away capacity. Our Marcellus production received a discount of US$1.72 per Mcf to the NYMEX benchmark price during the quarter. As a result of the lower prices in the region, combined with pipeline maintenance, 3,000 - 4,000 BOE per day of production was intentionally curtailed during the quarter. Despite this curtailment, production from the Marcellus was essentially unchanged from the second quarter, averaging 187 MMcf per day. Plans are currently underway to slow our pace of activity, moving from a four-rig program to a two-rig program. As a result, we expect capital spending on our Marcellus assets in the fourth quarter to be meaningfully lower than in the third quarter.

As discussed earlier in the year, Enerplus has drilled and completed two horizontal Duvernay wells in the Willesden Green area of central Alberta. Our initial horizontal well at 1-7-45-5W5M was completed in the first quarter of 2014 with a 13 stage hybrid slickwater frac. The well was subsequently shut-in for installation of surface equipment and pipeline tie-in. In late June, we brought this well on production achieving a 30 day initial production rate of 535 BOE per day including 2.24 MMcf per day of sales gas with 162 barrels per day of total liquids, 53% condensate.

Our second horizontal well at 15-8-46-9W5M was completed in the second quarter of this year with a 14 stage hybrid slickwater frac. This well was also shut-in while surface equipment and pipelines were installed to a third party gas plant and oil battery in the area. We brought this well on-stream in early October and during the first 30 days of production, it has averaged an estimated 700 BOE per day including 1.75 MMcf per day of sales gas, with 410 barrels per day of liquids, roughly 85% condensate.

Both wells have met our expectations on liquids content based upon our geotechnical analysis. The cost of these wells was higher than we expected, particularly on the completions, which is similar to what others have experienced in this deep, over-pressured play. We see a number of opportunities to increase drilling and completion efficiencies going forward, particularly with multi-well pads. Further evaluation of these wells over the coming months is required in order to determine our next steps.


A summary of our revised 2014 guidance is outlined below.

2014 Expectations Target
Average annual production 102,000 - 104,000 BOE/day (from 100,000 - 104,000 BOE/day)
Production mix (volume) 44,000 bbls/day crude oil and natural gas liquids
58,000 - 60,000 BOE/day natural gas (from 56,000 - 60,000 BOE/day)
Capital spending $830 million (from $800 million)
Average royalty rate
(% of gross sales, net of transportation)
Operating costs $10.25/BOE (from $10.10/BOE)
Cash G&A expenses $2.30/BOE
Cash share-based compensation expenses $0.45/BOE (from $0.60/BOE)
U.S. Cash taxes (% of U.S. funds flow) 2% (from 3% - 5%)


Despite the current decline in crude oil prices, Enerplus is very well positioned. Based upon our revised production guidance, we expect to deliver above-average production growth of 13% per share in 2014. Our dividend payout is conservative and our balance sheet is very strong. Our debt-to-trailing 12 month funds flow ratio was 1.3 times at the end of the quarter and we have virtually all of our $1 billion revolving line of credit available. We also have a significant portion of our crude oil production hedged for the remainder of 2014 and into 2015 at prices well above the current market. We anticipate that these positions will provide strong funds flow protection through the fourth quarter and into 2015, lending support for our plans for the remainder of this year and next.

Our preliminary plans for 2015 target continued production growth of 5 - 10% per share with a modestly lower capital spending program than in 2014. We have a significant portfolio of economic development opportunities in both crude oil and natural gas that are expected to provide us with organic growth potential for many years. We expect to maintain our strong financial position. We will continue to apply discipline to our capital spending program, ensuring that our plans are affordable and that our business is sustainable.


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:

Live Conference Call
Date: Friday, November 7, 2014
Time: 9:00AM MT / 11:00AM ET
Dial-In: 647-427-7450
888-231-8191 (toll free)
Passcode: 17622905

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 podcast of the conference call will be available on our website for downloading. A telephone replay will be available for 30 days following the conference call. The telephone replay can be accessed at the following numbers:

Dial-In: 416-849-0833
1-855-859-2056 (toll free)
Passcode: 17622905

Electronic copies of our Third Quarter 2014 MD&A and Financial Statements, along with other public information including investor presentations, are available on our website at For further information, please contact Investor Relations at 1-800-319-6462 or email

Follow @EnerplusCorp on Twitter at

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 our Canadian peer companies, the summary results contained within this news release presents our 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.

See "Non-GAAP Measures" below.


This news release 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 news release contains forward-looking information pertaining to the following: expected 2014 and 2015 average production volumes and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged; the results from our drilling program and the timing of related production; future oil and natural gas prices and differentials and our commodity risk management programs; expectations regarding our realized oil and natural gas prices; future royalty rates on our production and future production taxes; anticipated cash and non-cash G&A, share-based compensation and financing expenses; operating costs; capital spending levels in the remainder of 2014 and in 2015 and its impact on our production level; our future U.S. cash taxes; deferred income taxes, our tax pools and the time at which we may pay Canadian cash taxes and regular U.S. taxes; future debt and working capital levels and debt-to-funds-flow ratio and adjusted payout ratio, financial capacity, liquidity and capital resources to fund capital spending and working capital requirements; the amount and timing of future cash dividends that we may pay to our shareholders; and future dispositions, including expected proceeds therefrom and production volumes associated therewith.

The forward-looking information contained in this news release reflects several material factors, expectations and assumptions including, without limitation: that we will conduct our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve and resource volumes; commodity price and cost assumptions; the continued availability of adequate debt and/or equity financing and funds flow to fund our capital, operating and working capital requirements, and dividend payments as needed; the continued availability and sufficiency of our funds flow and availability under our bank credit facility to fund our working capital deficiency; the availability of third party services; and the extent of our liabilities. We believe the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

The forward-looking information included in this 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 in commodity prices; changes in realized prices of Enerplus' products; changes in the demand for or supply of our products; unanticipated operating results, results from our capital spending activities or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in our capital plans or by third party operators of our properties; increased debt levels or debt service requirements; inaccurate estimation of our oil and gas reserve and resource volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; reliance on industry partners and third party service providers; a failure to complete planned asset dispositions on the terms anticipated or at all; and certain other risks detailed from time to time in our public disclosure documents (including, without limitation, those risks and contingencies described under "Risk Factors and Risk Management" in our MD&A for the year ended December 31, 2013 and in our other public filings).

The forward-looking information contained in this news release speaks only as of the date of this news rlease, 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.


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 used to analyze leverage and liquidity and is calculated as total debt net of cash, divided by a trailing 12 months of funds flow.

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 ratio" 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. See disclosure under "Non-GAAP Measures" in our Third Quarter MD&A for reconciliation of these measures to the most directly comparable measures circulated in accordance with U.S. GAAP.

SOURCE Enerplus Corporation

Video with caption: "Video: Q3 Q&A with President and CEO, Ian C. Dundas". Video available at:

For further information:

Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation

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