Enerplus Building Momentum with Strong Operational First Quarter 2015 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 our First Quarter 2015 Financial Statements and MD&A are available on our website at www.enerplus.com under our profile on SEDAR at www.sedar.com and on the EDGAR website at www.sec.gov.
CALGARY, May 8, 2015 /CNW/ - Enerplus Corporation ("Enerplus") (TSX: ERF) (NYSE: ERF) announces the results from operations for the first quarter 2015.
HIGHLIGHTS:
- Enerplus delivered strong operating results and continued to demonstrate prudent financial stewardship through a focus on disciplined capital allocation and cost control. We are well positioned to achieve our key operating targets in 2015 and remain in a strong financial position as we navigate through a challenging commodity price environment.
- Production averaged approximately 100,900 BOE per day, down 4% quarter-over-quarter in response to reduced capital spending and deferred activity. Crude oil and natural gas liquids accounted for 43% of first quarter volumes, which was in line with our expectations. Well completion activity in North Dakota was deferred from December until late February in response to low oil prices and cost uncertainty.
- With prices stabilizing and improved cost structures, we plan to accelerate second quarter well completions in North Dakota and re-establish growth in the region. Given the solid momentum going into the second quarter, in part based upon strong well performance in North Dakota, we are well positioned to achieve our annual average production guidance of 93,000 - 100,000 BOE per day and liquids guidance of 42-44% despite the previously announced sale of non-core oil producing assets.
- Significant declines in commodity prices resulted in first quarter funds flow of $109 million compared to $213 million in the fourth quarter of 2014. The West Texas Intermediate benchmark price for crude oil averaged US$48.64 per barrel during the quarter, down from approximately US$73 per barrel during the previous quarter. AECO and NYMEX gas prices were sharply lower quarter-over-quarter, both falling by 26%. Although supported by our strong commodity hedge position, funds flow over the quarter was impacted by one-time charges of $11 million and realized losses on our foreign exchange revenue hedges of $8.6 million. Funds flow was also impacted by our decision to delay completion activity in North Dakota until late February.
- We reported a net loss of $293 million for the quarter as we incurred a non-cash asset impairment charge of $268 million. Under U.S. GAAP we are required to use twelve month trailing average prices to determine impairment and consequently the impairment reflects the low oil prices in the fourth quarter of 2014 and the first quarter of 2015.
- Capital spending during the quarter was $167 million and remains on track with our full year capital program. We directed the majority of capital to our North Dakota, Wilrich and Canadian crude oil properties. In total, we drilled 27.9 net wells and brought 17.4 net wells on-stream across our portfolio in the first quarter.
- Both our operating and G&A costs came in under expectations during the quarter at $11.03 per BOE and $2.36 per BOE respectively. Operating costs excluding Marcellus gathering fees were $9.66 per BOE during the quarter. Further information on our treatment of Marcellus gathering fees is provided in the first quarter 2015 Management's Discussion and Analysis.
- Our focus on cost efficiencies, the deferral of activity and our strong hedge position continue to help preserve our financial flexibility for 2015. We ended the quarter with a debt to funds flow ratio of 1.7 times, up from 1.3 times at year-end 2014. We reduced our dividend by 44% to $0.05 per share effective with the April payment as we believe this is a more appropriate level in the context of current commodity prices. Subsequent to the quarter, our previously announced non-core asset sales closed generating proceeds of $186 million. These proceeds were used to repay the debt outstanding on our $1 billion bank credit facility, which is essentially undrawn following these divestments.
"We achieved strong operating performance despite a challenging environment. Our focus on disciplined capital allocation and a commitment to a strong balance sheet has positioned us with significant financial flexibility in this market. We remain well positioned to achieve our 2015 targets," said Ian Dundas, President & CEO.
| SELECTED FINANCIAL RESULTS |
||||
| Three months ended March 31, |
||||
| 2015 |
2014 |
|||
| Financial (000's) |
||||
| Funds Flow |
$ |
109,164 |
$ |
220,512 |
| Cash and Stock Dividends |
47,359 |
54,935 |
||
| Net Income/(Loss) |
(293,206) |
40,037 |
||
| Debt Outstanding - net of cash |
1,272,204 |
1,020,720 |
||
| Capital Spending |
167,011 |
217,763 |
||
| Property and Land Acquisitions |
(236) |
9,969 |
||
| Property Divestments |
3,712 |
117,225 |
||
| Debt to Trailing 12-Month Funds Flow |
1.7x |
1.3x |
||
| Financial per Weighted Average Shares Outstanding |
||||
| Funds Flow |
$ |
0.53 |
$ |
1.09 |
| Net Income/(Loss) (Basic) |
(1.42) |
0.20 |
||
| Weighted Average Number of Shares Outstanding (000's) |
205,845 |
203,178 |
||
| Selected Financial Results per BOE(1)(2) |
||||
| Oil & Natural Gas Sales(3) |
$ |
26.89 |
$ |
55.66 |
| Royalties and Production Taxes |
(5.50) |
(12.05) |
||
| Commodity Derivative Instruments |
9.56 |
(1.72) |
||
| Operating Expenses |
(9.56) |
(8.97) |
||
| Transportation Costs |
(2.92) |
(2.51) |
||
| General and Administrative |
(2.36) |
(2.31) |
||
| Share Based Compensation |
(0.80) |
(0.77) |
||
| Interest, Foreign Exchange and Other Expenses |
(3.28) |
(1.67) |
||
| Taxes |
- |
(0.87) |
||
| Funds Flow |
$ |
12.03 |
$ |
24.79 |
| SELECTED OPERATING RESULTS |
Three months ended March 31, |
||||
| 2015 |
2014 |
||||
| Average Daily Production(2) |
|||||
| Crude oil (bbls/day) |
39,355 |
37,760 |
|||
| NGLs (bbls/day) |
3,735 |
3,262 |
|||
| Natural gas (Mcf/day) |
346,589 |
346,794 |
|||
| Total (BOE/day) |
100,855 |
98,821 |
|||
| % Crude Oil & Natural Gas Liquids |
43% |
42% |
|||
| Average Selling Price(2)(3) |
|||||
| Crude oil (per bbl) |
$ |
44.04 |
$ |
93.04 |
|
| NGLs (per bbl) |
22.48 |
67.90 |
|||
| Natural gas (per Mcf) |
2.58 |
5.07 |
|||
| Net Wells drilled |
28 |
30 |
|||
| (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) |
Before transportation costs, royalties and commodity derivative instruments. |
| Three months ended March 31, |
||||
| Average Benchmark Pricing |
2015 |
2014 |
||
| WTI crude oil (US$/bbl) |
$ |
48.64 |
$ |
98.68 |
| AECO– monthly index (CDN$/Mcf) |
2.95 |
4.76 |
||
| AECO– daily index (CDN$/Mcf) |
2.75 |
5.71 |
||
| NYMEX – last day (US$/Mcf) |
2.98 |
4.94 |
||
| USD/CDN exchange rate |
1.24 |
1.10 |
||
| Share Trading Summary |
CDN* – ERF |
U.S.** - ERF |
||
| For the three months ended March 31, 2015 |
(CDN$) |
(US$) |
||
| High |
$ |
14.53 |
$ |
11.73 |
| Low |
$ |
9.41 |
$ |
7.89 |
| Close |
$ |
12.84 |
$ |
10.14 |
| * |
TSX and other Canadian trading data combined. |
| ** |
NYSE and other U.S. trading data combined. |
| 2015 Dividends per Share |
||||
| CDN$ |
US$(1) |
|||
| January |
$ |
0.09 |
$0.08 |
|
| February |
$ |
0.09 |
$0.07 |
|
| March |
$ |
0.09 |
$0.07 |
|
| First Quarter Total |
$ |
0.27 |
$0.22 |
|
| (1) |
US$ dividends represent CDN$ dividends converted |
| Production and Capital Spending |
||
| Three months ended March 31, 2015 |
||
| Crude Oil & NGLs (bbls/day) |
Average Production |
Capital Spending |
| Canada |
19,332 |
57 |
| United States |
23,758 |
79 |
| Total Crude Oil & NGLs (bbls/day) |
43,090 |
136 |
| Natural Gas (Mcf/day) |
||
| Canada |
135,419 |
20 |
| United States |
211,170 |
11 |
| Total Natural Gas (Mcf/day) |
346,589 |
31 |
| Company Total (BOE/day) |
100,855 |
167 |
| Net Drilling Activity*** – for the three months ended March 31, 2015 |
||||
| Crude Oil |
Horizontal Wells Drilled |
Wells Pending Tie-in * |
Wells On-stream** |
Dry & Abandoned Wells |
| Canada |
14.4 |
9.0 |
10.9 |
- |
| United States |
8.2 |
7.3 |
3.6 |
- |
| Total Crude Oil |
22.6 |
16.3 |
14.5 |
- |
| Natural Gas |
||||
| Canada |
3.0 |
3.0 |
- |
- |
| United States |
2.2 |
2.2 |
2.9 |
- |
| Total Natural Gas |
5.2 |
5.2 |
2.9 |
- |
| Company Total |
27.9 |
21.5 |
17.4 |
- |
| *Wells drilled during the quarter pending potential completion/tie-in or abandonment as at March 31, 2015. |
||||
| **Total wells brought on-stream during the quarter regardless of when they were drilled. |
||||
| *** Table may not add due to rounding. |
||||
Asset Activity
We had some notable operational successes during the quarter. At Fort Berthold, we continue to evolve our completion design with strong results. Despite no operated on-stream activity for most of the quarter, we brought a 4-well pad on-stream at the end of February with initial 30 day average production rates (IP30) per well ranging from 1,290 – 1,390 barrels of oil per day. Additionally, one of our most recent Three Forks wells, located in the southeast area of our acreage, is significantly outperforming our expectations for that region with an IP30 rate of approximately 1,230 barrels of oil per day. In all, we drilled 8.2 net wells with 3.6 net wells brought on-stream over the quarter for a total investment of $79 million. Average daily production during the quarter was 26,500 BOE per day from both Fort Berthold and Sleeping Giant. We are seeing cost reductions materialize with well costs trending down close to 15% from 2014 levels. Our average well cost in Fort Berthold year-to-date is approximately US$11.5 million.
With drilling activity outpacing completions at Fort Berthold, we continued to build an inventory of drilled uncompleted wells which stood at 18.8 net wells at quarter-end. As completion activity begins to increase in the second quarter in response to prices stabilizing and improved cost structures, we will start to work through some of this uncompleted well inventory. We expect to re-establish production growth in North Dakota in the second quarter. We are also evaluating an increase in the number of planned completions in the second half of 2015.
In the Marcellus, capital spending was meaningfully lower in the quarter at $11 million, compared to $26 million during the previous quarter. Drilling activity slowed as we moved to a one-rig drilling program with 2.2 net wells drilled and 2.9 net wells brought on-stream. We continued to curtail production due to weak natural gas prices in the region and expect to continue curtailing production for the remainder of the year. Production during the quarter averaged 195 MMcf per day.
In our Canadian oil portfolio, we drilled 14.4 net wells with 10.9 net wells brought on-stream. The drilling activity was largely focused at Brooks, targeting the Lower Mannville sands. Average well results have been in line with our expectations and we are targeting growth of approximately 1,350 BOE per day during 2015, resulting in expected annual average production of approximately 3,900 BOE per day from the Brooks area. The timing of the Brooks drilling program was driven by lease retention.
In the Deep Basin, our operated 3 horizontal well pad was drilled and completed at Ansell. Initial production rates in late March showed encouraging results. The wells were completed under budget and initial production results support our assessment of a sweet spot trend across Enerplus' lands.
Crude Oil & Natural Gas Pricing
The West Texas Intermediate benchmark price for crude oil fell more than 30% quarter-over-quarter and over 50% from the first quarter of 2014. Both Canadian heavy and light oil differentials were slightly weaker, while the Bakken crude oil differential improved from the fourth quarter. Our average realized sales price for crude oil during the quarter was down approximately 36% from the fourth quarter to $44.04 per barrel. The outlook ahead on crude differentials is positive. Improved market access, particularly to the U.S. Gulf Coast, has reduced the downside impact mid-continent refinery outages have historically had on Canadian prices. Reduced supply from oil sands producers due to seasonal maintenance is expected to further strengthen Canadian crude oil differentials in the second quarter. The narrowing of the Bakken crude differential is a result of increased rail capacity coming into service during the quarter. The reversal of Enbridge's Line 9, scheduled for the second quarter of 2015, is expected to provide further support for U.S. Bakken differentials in the coming months.
On the natural gas side, both AECO and NYMEX fell sharply as a result of strong production in the U.S. combined with a delay in winter weather in key regions in the U.S. which allowed storage to return to more seasonally average levels compared to this time last year. Our realized sales price for natural gas was $2.58 per Mcf during the quarter, down approximately 21% from the previous quarter. In the Marcellus, our realized differential was US$1.32 per Mcf below NYMEX, compared to the average regional spot differential of US$1.68 per Mcf. Approximately 46% of our Marcellus production is sold under long-term sales contracts which have exposure to markets outside of Northeast Pennsylvania.
Our commodity hedge position continues to help support funds flow in 2015. Approximately 35% of our expected crude oil production net of royalties from April through December is hedged at over US$90 per barrel and approximately 46% of anticipated natural gas volumes net of royalties are hedged at about US$3.90 per Mcf over the same period.
We have established an initial crude oil hedge position for 2016. Approximately 26% of our forecasted 2016 crude oil production net of royalties is hedged with 6,000 barrels per day protected through 3-way collars (US$50 per barrel by US$65 per barrel by $US80 per barrel), and an additional 2,000 barrels per day swapped at US$65.50 per barrel.
Board & Executive Changes
I would like to thank Mr. Edwin Dodge who is retiring and not standing for re-election as a Board member this year. Ed joined the Board of Directors of Enerplus in May 2004 and his guidance and direction have helped to successfully grow and transition the business over the past 11 years.
I would also like to thank Mr. Donald Nelson who is not standing for re-election as a Board member this year. Don joined the Board of Directors of Enerplus in June 2012 and has provided valuable insight and guidance during his time as a Director.
I am pleased to announce that John Hoffman has joined the executive team of Enerplus in the position of Vice-President of Canadian Operations. John brings a wealth of experience to the role having spent 25 years in the Canadian energy industry in both leadership and engineering roles, focused largely in the Western Canadian Sedimentary Basin.
Outlook
Despite the current commodity price environment, Enerplus is well positioned. We remain committed to disciplined capital allocation with a strong focus on cost control. We continue to achieve excellent results from our asset base with strong momentum continuing into the second quarter. We are also seeing encouraging signs in the market with a modest recovery in crude oil prices and costs continuing to trend down. As we look to re-establish production growth in our North Dakota properties, we are well positioned to achieve our annual average production guidance range for the year. Supported by our commodity hedging program and commitment to reducing costs and driving operational efficiencies, we expect to remain in a position of strength through 2015.
Q1 2015 Conference Call Details
A conference call hosted by Ian C. Dundas, President and CEO will be held at 8:00AM MT (10:00AM ET) today to discuss these results. Details of the conference call are as follows:
| Date: |
Friday, May 8, 2015 |
| Time: |
8:00 AM MT (10:00 AM ET) |
| Dial-In: |
647-427-7450 |
| 1-888-231-8191 (toll free) |
|
| Audiocast: http://www.newswire.ca/en/webcast/detail/1508249/1681339 |
|
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: |
16479542 |
Electronic copies of our First Quarter 2015 MD&A and Financial Statements, along with other public information including investor presentations, are available on our website at www.enerplus.com. Follow @EnerplusCorp on Twitter at https://twitter.com/EnerplusCorp.
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. "MBOE" and "MMBOE" mean "thousand barrels of oil equivalent" and "million barrels of oil equivalent", respectively.
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.
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 2015 average production volumes and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting our funds flow; the results from our drilling program and the timing of related production; oil and natural gas prices and differentials and our commodity and foreign exchange risk management programs in 2015 and in the future; expectations regarding our 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 2015 and its impact on our production level; potential future asset impairments; future debt and working capital levels and debt to funds flow ratio; our future acquisitions and dispositions; and the amount of future cash dividends that we may pay to our shareholders.
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 2015 guidance is based on the following assumptions: WTI price of US$55 per barrel, a NYMEX gas price of US$2.75 per Mcf, an AECO gas price of $2.50 per GJ and a US$/CDN exchange rate of 1.25. 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 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; inaccurate estimation 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; and certain other risks detailed from time to time in Enerplus' public disclosure documents (including, without limitation, those risks identified in our AIF and Form 40-F at December 31, 2014).
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.
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 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 our First Quarter 2015 MD&A.
Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation
SOURCE Enerplus Corporation
please contact Investor Relations at 1-800-319-6462 or email [email protected].
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