Enerplus Announces Strong 2013 First Quarter Results
This news release includes forward-looking statements and information within the meaning of applicable securities laws. Readers are advised to review the "Cautionary Note Regarding Forward-Looking Information and Statements" at the conclusion of this news release. Readers are also referred to "Information Regarding Operational Information" and "Non-GAAP Measures" at the end of this news release for information regarding the presentation of the financial and operational information contained in this news release. A full copy of our 2012 Financial Statements and MD&A have been filed 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 10, 2013 /CNW/ - Enerplus Corporation ("Enerplus") (TSX: ERF) (NYSE: ERF) is pleased to announce that strong results for the first quarter have positioned us to achieve all of our operational targets for the coming year. Our portfolio of core assets in Canada and the U.S. continued to deliver profitable, organic growth.
-- We achieved average production of 87,183 BOE per day during the quarter. This growth was in part driven by record production levels from the Marcellus and our Fort Berthold assets in North Dakota. -- Most notably, our Marcellus production increased by approximately 40%, averaging 79 MMcf per day, up from 57 MMcf per day during the fourth quarter of 2012 as a result of a combination of strong well performance and increased tie-in activity at the end of the year. -- We closely managed our capital spending program during the first quarter as part of our strategy to improve the sustainability and profitability of our business. We invested $173 million during the quarter, approximately 25% of our capital spending budget for the year. The majority of our spending was once again directed to our crude oil projects in Canada and the U.S. Approximately 45% of our program was directed to our Bakken development at Fort Berthold, North Dakota where we realized a reduction in well costs during the first quarter. A total of 25 net wells were drilled with 17 net wells brought on-stream. -- With the steady recovery of natural gas prices and support from our hedging program, we generated $173 million ($0.87 per share) in funds flow during the quarter. Approximately 40% of our total production is now attributable to our U.S. assets, helping to mitigate the impact of wider Canadian heavy crude oil differentials. -- Our operating costs of $10.37/BOE were in line with our guidance, and while our general and administrative costs were higher than expected due to one-time charges associated with the departure of personnel, we continue to maintain our annual guidance for both these items. -- Our adjusted payout ratio was approximately 126%, a significant improvement from 254% a year ago due to the increase in funds flow, and reductions in our capital spending and monthly dividend. -- We have continued to keep our balance sheet strong with a debt to trailing 12 month funds flow ratio of 1.7 times at the end of the quarter. Approximately 70% of our $1 billion credit facility remains unutilized. -- We are also well positioned with hedges on approximately 65% of our net crude oil production and 35% of our net natural gas production for 2013 that we expect will provide us with significant funds flow protection in 2013. This will help ensure we have the financial capacity to support our capital spending plans and our dividend. We've also started to layer in additional hedges for 2014. -- We reported a net loss of $5.2 million for the quarter. Non-cash mark-to-market losses on our commodity derivatives as a result of higher forecast commodity prices at quarter end negatively impacted earnings. This non-cash loss had no impact on funds flow. -- Subsequent to the quarter, we sold approximately 600 BOE per day of low working interest crude oil production in southeast Saskatchewan and Alberta for $58 million. These assets were not considered part of our core portfolio and their sale not only increases our financial flexibility but also improves the concentration of our asset base. -- We are also currently marketing a package of small non-core properties representing approximately 1,300 BOE per day of primarily oil production in order to further focus our portfolio and provide additional funding for our capital program. -- We are maintaining our annual average production guidance of 82,000 to 85,000 BOE per day with an exit rate of 84,000 to 88,000 BOE per day, despite the sale of 600 BOE/day. Our guidance does not reflect the potential divestment activities mentioned above as we cannot predict the outcome of these efforts. SELECTED OPERATING RESULTS Three months ended March 31, 2013 2012 Average Daily Production Crude oil (bbls/day) 38,321 34,074 NGLs (bbls/day) 3,595 4,002 Natural gas (Mcf/day) 271,602 246,686 Total (BOE/day) 87,183 79,190 % Crude Oil & NGLs 48% 48% Average Selling Price((2)) Crude oil (per bbl) $ 78.52 $ 85.91 NGLs (per bbl) 58.58 56.77 Natural gas (per Mcf) 3.10 2.27 Net Wells Drilled 25 34 Three months ended March 31, 2013 2012 Average Benchmark Pricing WTI crude oil (US$/bbl) $94.37 $102.93 AECO natural gas - monthly index 3.08 2.52 (CDN$/Mcf) AECO natural gas - daily index 3.20 2.15 (CDN$/Mcf) NYMEX natural gas - monthly NX3 index 3.35 2.77 (US$/Mcf) USD/CDN exchange rate 1.01 1.00 SELECTED FINANCIAL RESULTS Three months ended March 31, 2013 2012 Financial (000's) Funds Flow $172,596 $162,706 Cash and Stock Dividends 53,785 105,995 Net Income/(Loss) (5,238) (33,821) Debt Outstanding - net of cash 1,125,762 902,937 Capital Spending 172,944 317,066 Property and Land Acquisitions 3,967 33,020 Property Dispositions 1,331 52,611 Asset Disposition gain/(loss) 217 24,100 Debt to Trailing 12 Month Funds Flow 1.7x 1.6X Financial per Weighted Average Shares Outstanding Funds Flow( ) $0.87 $0.86 Net Income/(Loss) (0.03) (0.18) Weighted Average Number of Shares 199,031 189,844 Outstanding (000's) Selected Financial Results per BOE((1)) Oil & Gas Sales((2)) $46.67 $47.04 Royalties (9.52) (9.26) Commodity Derivative Instruments 1.47 (1.48) Operating Costs (10.42) (9.81) General and Administrative Expenses (3.15) (2.87) Equity Based Compensation (0.70) (0.22) Interest and Other Expenses (2.19) (0.72) Taxes (0.16) (0.10) Funds Flow $22.00 $22.58 ((1) )Non-cash amounts have been excluded. ((2) )Net of oil and gas transportation costs, but before the effects of commodity derivative instruments. Share Trading Summary CDN* - ERF U.S.** - ERF For the three months ended March (CDN$) (US$) 31, 2013 High $15.50 $15.17 Low $12.26 $12.03 Close $14.84 $14.61 * TSX and other Canadian trading data combined. **NYSE and other U.S. trading data combined. 2013 Dividends per Share Payment Month CDN$ US$((1)) January $0.09 $0.09 February $0.09 $0.09 March $0.09 $0.09 First Quarter $0.27 $0.27 Total ((1)) (US$ dividends represent CDN$ dividends converted at the relevant foreign exchange rate on the payment date.) Production and Capital Spending Three months ended March 31, 2013 Crude Oil & NGLs Average Capital Spending (BOE/day) Production Volumes ($ millions) Canada 22,284 $47 United States 19,632 77 Total Crude Oil & 41,916 $124 NGLs (BOE/day) Natural Gas (Mcf/day) Canada 177,809 $36 United States 93,793 13 Total Natural Gas 271,602 $49 (Mcf/day) Company Total 87,183 $173 (BOE/day) Net Drilling Activity - for the three months ended March 31, 2013 Wells Dry &
Horizontal Pending Abandoned Crude Vertical Total Completion/ Wells Oil Wells Wells Wells Tie-in * On-stream** Wells
Canada 14.4 0.4 14.8 10.9 4.2 -
United 3.7 - 3.7 2.8 7.7 - States
Total 18.1 0.4 18.5 13.7 11.9 - Crude Oil
Canada 5.4 - 5.4 2.4 3.2 -
United 0.8 - 0.8 0.8 1.7 - States
Total 6.2 - 6.2 3.2 4.9 - Natural Gas
Company 24.3 0.4 24.7 16.9 16.8 - Total
*Wells drilled during the quarter that are pending potential completion/tie-in or abandonment as at March 31, 2013. ** Total wells brought on-stream during the quarter regardless of when they were drilled.
U.S. Crude Oil
Our U.S. crude oil production increased by approximately 7% during the first quarter of 2013 compared to the fourth quarter of 2012 due to the additional working interests purchased in the Sleeping Giant field in Montana in December 2012 and continued drilling at Fort Berthold in North Dakota. We invested $77 million during the quarter in North Dakota targeting both the Bakken and Three Forks formations. We drilled three net operated long horizontal wells and participated in one non-operated well. In addition, five operated long horizontal wells, two short horizontal wells and one non-operated well were brought on-stream.
The Fort Berthold region continues to be our most active development area within our portfolio. Our focus in 2013 is on improving our capital efficiencies and to continue to deliver growth in production and reserves. We initially budgeted $12.9 million for the drilling, completion and tie-in of a long horizontal well in 2013. During the quarter we realized savings in the order of 10% due primarily to lower costs for completion services and supplies. We are encouraged by these cost reductions and will work to extend them throughout the remainder of the year. In total, we plan to drill, complete and tie-in approximately 20 to 25 wells in 2013.
U.S. Natural Gas
Our U.S. natural gas production continued to grow during the first quarter. Marcellus production increased from approximately 57 MMcf per day during the fourth quarter of 2012 to average 79 MMcf per day during the quarter, well ahead of our expectations. While drilling activity slowed down as expected, we continue to benefit from better than expected well performance and increased tie-in activity late in 2012. Our Marcellus capital program this year is almost exclusively focused on the northeast region of Pennsylvania. With the recent strengthening in NYMEX natural gas prices, the economics of our capital program have improved significantly. Our Marcellus production is currently delivering a netback of approximately $2.50 per Mcf.
Canada Crude Oil
Capital spending activities to date in our Canadian crude oil portfolio were focused primarily at our Medicine Hat Glauconitic "C" property in Alberta and in Saskatchewan where we continued to drill into the Ratcliffe trend.
At Medicine Hat, we continued with our waterflood optimization program drilling five injection and two producing wells into the field during the quarter. We also began work on a significant battery upgrade to support the growing production from this field. In addition to our waterflood program, we are encouraged by the response to our polymer injection project which began in mid-2012. We expect to make a decision on a second polymer project in this field by year end.
In Saskatchewan, we drilled three horizontal wells targeting the Ratcliffe at our Freda Lake and Neptune properties during the quarter. We expect to complete and tie-in these wells during the second quarter. We have been very pleased with our drilling results in this area as we've grown production from approximately 700 BOE per day in 2010 to over 3,500 BOE/day during the quarter. After spring break-up, we expect to run one rig over the balance of the year and plan to continue to convert older vertical producing wells into water injection wells to optimize the waterfloods in this trend.
Canada Natural Gas
As planned, we have not invested significant capital in our Canadian natural gas assets in 2013 and as a result, daily production has continued to decline. We did however drill two horizontal wells targeting the Wilrich zone based upon the success of our 2012 drilling program in the Ansell area of Alberta. The first well is meeting our type curve assumptions with a 30-day initial production rate of approximately 6 MMcf per day of natural gas. The second well had an initial peak test rate of approximately 35 MMcf per day during the first 17 hours at 15.3 MPa in mid-March. The well has been on production since mid-April and production has averaged 17 MMcf per day since that time, well ahead of our expectations.
On March 21, 2013, the Board of Directors of Enerplus announced that Gordon J. Kerr will be retiring as President & Chief Executive Officer effective June 30, 2013. Ian C. Dundas, Executive Vice President & Chief Operating Officer, will succeed Mr. Kerr as President & Chief Executive Officer. Mr. Kerr will also be retiring as a Director of Enerplus on June 30, 2013, and Mr. Dundas will be appointed as a director at that time.
Q1 Results Live Conference Call
A conference call hosted by Mr. Gordon J. Kerr and Mr. Ian C. Dundas will be held today at 8:30 am MT (10:30 am ET) to discuss these results. Details of the conference call are as follows:
Date: Friday, May 10, 2013
Time: 8:30 am MT (10:30 am ET)
1-888-231-8191 (toll free)
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:
1-855-859-2056 (toll free)
Minor Corrections to Year-End Filings
Enerplus has filed a Notice that corrects certain minor and immaterial errors in the estimated net present value of future net revenues of oil and gas reserves, on an after-tax basis, presented in our 2012 year-end disclosure. A copy of the Notice is available on our SEDAR profile at www.sedar.com and our EDGAR profile at www.sec.gov.
INFORMATION REGARDING FINANCIAL AND OPERATIONAL INFORMATION
Currency and Production Amounts
All amounts in this news release are stated in Canadian dollars unless otherwise specified. All oil, NGL and gas production volumes contained in this news release are presented on a "gross" basis, before deduction of royalties, as in accordance with Canadian practice.
Barrels of Oil Equivalent and Cubic Feet of Gas 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.
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", "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: achievement of operational targets for 2013; Enerplus' expected operating and general and administrative costs and oil and gas production volumes for 2013; the proportion of our anticipated oil and natural gas production that is hedged; Enerplus' financial capacity to support capital spending plans and its dividend; potential asset divestments; future efficiencies and reserves and production growth from capital spending; future capital and development expenditures and the allocation thereof among our assets; future development and drilling locations, plans and costs; and the performance of and future results from Enerplus' assets and operations, including anticipated production levels, decline rates and future growth prospects.
The forward-looking information contained in this news release reflects several material factors and expectations and assumptions of Enerplus including, without limitation: that Enerplus' operations and development plans will achieve the expected results; the general continuance of current or, where applicable, assumed industry conditions, including third party costs; the continuation of assumed tax, royalty and regulatory regimes; commodity price and cost assumptions; the continued availability of adequate debt and/or equity financing, cash flow and other sources to fund Enerplus' capital and operating requirements as needed; the extent of its liabilities; and that Enerplus will be able to complete planned asset sales. 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 the demand for or supply of Enerplus' products; unanticipated operating results, results from development plans or production declines; 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; an inability to complete planned asset sales; 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 Enerplus' Annual Information Form and Form 40-F for the year ended December 31, 2012, filed on SEDAR and EDGAR, respectively, on February 22, 2013).
The forward-looking information contained in this news release speaks only as of the date of this news release, and none of Enerplus or its subsidiaries assume any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.
In this news release, we use the terms "adjusted payout ratio" to analyze operating performance, leverage and liquidity, and "netback" as measures of operating performance. We calculate "adjusted payout ratio" as cash dividends to shareholders, net of our stock dividends (and for 2012 comparative purposes, our DRIP proceeds), plus capital spending (including office capital) divided by funds flow. "Netback" is calculated as oil and gas sales revenues after deducting royalties, operating costs and transportation.
Enerplus believes that, in addition to net earnings and other measures prescribed by IFRS, the term "adjusted payout ratio" and "netback" are useful supplemental measures as they provides an indication of the results generated by Enerplus' principal business activities. However, these measures are not recognized by GAAP and do not have a standardized meaning prescribed by IFRS. Therefore, these measures, as defined by Enerplus, may not be comparable to similar measures presented by other issuers.
Gordon J. Kerr President & Chief Executive Officer Enerplus Corporation
For further information, please contact our Investor Relations Department at 1-800-319-6462 or email firstname.lastname@example.org.
SOURCE: Enerplus Corporation
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CO: Enerplus Corporation ST: Alberta NI: OIL ERN CONF
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