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. Readers are also referred to “Information Regarding Financial and 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 second quarter 2013 Financial Statements and MD&A, as well as 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.
- Funds flow increased by almost 20% during the quarter compared to the first quarter of 2013, and 40% compared to the second quarter last year, to approximately $205 million, driven by higher production and a significant improvement in our netback as a result of higher realized commodity prices.
- Our adjusted payout ratio decreased to 89% in the quarter. On a year-to-date basis, our adjusted payout ratio is approximately 106% before considering the proceeds of our divestment activities and reflects the improved sustainability of our business.
- Operations in both Canada and the U.S. continued to perform ahead of our expectations. Daily production was up 10% over the second quarter of 2012 and 3% higher than the first quarter of 2013, averaging 90,037 BOE/day. For the first six months of 2013, daily production has averaged 88,618 BOE/day, significantly ahead of our expectations.
- Natural gas production in both Canada and the U.S. showed the most notable increases as a result of successful drilling activity in the Wilrich and continued strong performance in the Marcellus.
- Drilling and development activities in Canada slowed during the quarter, resulting in a 20% decrease in capital spending compared to the first quarter of 2013. Approximately $140 million was invested across our portfolio with over 80% of our spending dedicated to our oil properties in both Canada and the U.S. In the first half of 2013, we’ve invested approximately$313 million in development capital which is about 45% of our full year budget. Our North Dakota operations continued to attract the majority of our capital investment given the strong economic returns from this region.
- Our hedging program generated approximately $21 million year-to-date in cash gains.
- Operating costs and general and administrative costs continue to track our expectations.
- We increased the concentration in our Canadian waterflood portfolio through the acquisition of an additional 50% working interest in the Pouce Coupe Boundary Lake light oil pool in Alberta and also added to our acreage positions in our core areas in North Dakota and Pennsylvania.
- As previously announced, we have also either sold or entered into agreements to sell approximately 1,300 BOE/day of non-core producing assets, net of acquisitions. In addition, we have also closed the sale of infrastructure assets in the Fort Berthold region for approximately $34 million.
- Year-to-date, including agreements signed, we have sold approximately $192 million in non-core assets and invested approximately $55 million in acquistions in our core areas.
- As a result of non-core asset sales and the increase in funds flow, our trailing 12 month debt-to-funds flow ratio also improved, falling to 1.6 times at the end of the quarter.
|SELECTED FINANCIAL RESULTS||Three months ended June 30,||Six months ended June 30,|
|Cash and Stock Dividends||54,009||88,599||107,794||194,594|
|Debt Outstanding – net of cash||1,133,048||1,152,746||1,133,048||1,152,746|
|Property and Land Acquisitions||51,692||23,649||55,659||56,669|
|Debt to Trailing 12 Month Funds Flow||1.6x||2.0x||1.6x||2.0x|
|Financial per Weighted Average Shares Outstanding|
|Weighted Average Number of Shares Outstanding (000’s)||199,825||196,768||199,430||193,306|
|Selected Financial Results per BOE(1)|
|Oil & Gas Sales(2)||$48.65||$42.07||$47.68||$44.51|
|Commodity Derivative Instruments||1.11||0.68||1.29||(0.38)|
|General and Administrative||(2.29)||(2.76)||(2.71)||(2.82)|
|Equity Based Compensation||(0.45)||0.19||(0.57)||(0.01)|
|Interest and Other Expenses||(1.38)||(0.90)||(1.78)||(0.81)|
|SELECTED OPERATING RESULTS||Three months ended June 30,||Six months ended June 30,|
|Average Daily Production|
|Crude oil (bbls/day)||38,066||36,527||38,193||35,300|
|Natural gas (Mcf/day)||290,841||253,126||281,275||249,905|
|% Crude Oil & Natural Gas Liquids||46%||49%||47%||48%|
|Average Selling Price(2)|
|Crude oil (per bbl)||$ 82.95||$ 74.36||$ 80.74||$ 79.93|
|NGLs (per bbl)||45.64||60.11||52.16||58.30|
|Natural gas (per Mcf)||3.70||2.06||3.41||2.17|
|Net Wells drilled||10||19||35||53|
|(1)||Non-cash amounts have been excluded.|
|(2)||Net of oil and gas transportation costs, but before the effects of commodity derivative instruments.|
|Three months ended June 30,||Six months ended June 30,|
|Average Benchmark Pricing|
|WTI crude oil (US$/bbl)||$94.22||$93.49||$94.30||$98.21|
|AECO- monthly index (CDN$/Mcf)||3.59||1.83||3.34||2.18|
|AECO- daily index (CDN$/Mcf)||3.53||1.90||3.37||2.02|
|NYMEX- monthly NX3 index (US$/Mcf)||4.09||2.26||3.72||2.52|
|USD/CDN exchange rate||1.02||1.01||1.02||1.01|
|Share Trading Summary||CDN* – ERF||U.S.** – ERF|
|For the three months ended June 30, 2013||(CDN$)||(US$)|
* TSX and other Canadian trading data combined.
**NYSE and other U.S. trading data combined.
|2013 Dividends per Share|
|First Quarter Total||$0.27||$0.27|
|Second Quarter Total||$0.27||$0.26|
|(1)||US$ dividends represent CDN$ dividends converted at the relevant foreign exchange rate on the payment date.|
|Production and Capital Spending||Three months ended
June 30, 2013
|Six months ended
June 30, 2013
|Crude Oil & NGLs (BOE/day)||Average
|Total Crude Oil & NGLs (BOE/day)||41,563||$113||41,739||$237|
|Natural Gas (Mcf/day)|
|Total Natural Gas (Mcf/day)||290,841||$27||281,275||$76|
|Company Total (BOE/day)||90,037||$140||88,618||$313|
|Net Drilling Activity – for the three months ended June 30, 2013|
|Total Crude Oil||8.3||–||8.3||5.1||14.7||–|
|Total Natural Gas||2.1||–||2.1||2.1||2.9||–|
*Wells drilled during the quarter that are pending potential completion/tie-in or abandonment as at June 30, 2013.
** Total wells brought on-stream during the quarter regardless of when they were drilled.
U.S. Crude Oil
Production from our U.S. crude oil assets increased slightly during the second quarter primarily due to drilling activity at FortBerthold, North Dakota. We invested approximately $78 million drilling 4.7 net long horizontal wells and bringing 6.1 net horizontal wells on-stream with the majority of the wells brought on late in the quarter. Service and supply costs continue to be lower than our original expectations with a 10% savings realized on well costs year-to-date. Production from Fort Berthold continues to be on track with our expectations and averaged just over 15,000 BOE/day during the quarter.
Canadian Crude Oil
Production from our Canadian crude oil properties was down slightly from the first quarter, averaging approximately 21,300 BOE/day due to a slow-down in development activity and the sale of non-core production. The majority of our activities were focused on drilling additional wells in our waterflood properties at Medicine Hat and Giltedge. We also acquired an incremental 50% working interest in the Pouce Coupe South Boundary Lake waterflood property during the quarter, taking our working interest to approximately 100%. This property has a very low historical decline rate of roughly 5% with an average netback of approximately $50/BOE and we believe there is future upside potential through incremental drilling and waterflood optimization.
U.S. Natural Gas
U.S. natural gas production grew by more than 10% during the quarter, averaging approximately 104 MMcf/day. The majority of our U.S. gas production is from the Marcellus region in northeast Pennsylvania which produced on average 88 MMcf/day of natural gas during the quarter, up 11% from the first quarter. We continue to see strong well performance, particularly in the Bradford and Susquehanna areas where approximately 90% of our Marcellus capital is being allocated. As a result of the growth in production volumes and increasing natural gas prices, we have seen a significant increase in funds flow from our Marcellus operations in 2013 generating approximately $34 million in funds flow year-to-date which has fully funded our 2013 capital spending in this region.
Canadian Natural Gas
Based upon the success of our drilling activity to date in the Wilrich, we plan to drill two additional horizontal development wells in the Ansell area in the latter half of the year with an expected on-stream early in 2014. We also plan to begin drilling two Montney horizontal wells at our Cameron/Julienne property in northeast British Columbia in the fourth quarter. The first of two vertical wells testing the Duvernay is currently underway. We expect to finish drilling both of these wells in the fourth quarter of 2013.
As the majority of our funds flow comes from crude oil revenues, we continue to enter into additional WTI hedge positions in order to provide greater certainty of our future funds flow. We now have 75% of our remaining 2013 crude oil production, after royalties, hedged at a price of US$100.35 per barrel and we have 56% of our expected 2014 crude oil production volumes, net of royalties, hedged at an average price of US$93.06 per barrel. We also have 32% of our remaining 2013 natural gas volumes, after royalties, hedged at an average price of $3.51 per Mcf. For 2014, we have 24% of our expected net natural gas production hedged against the NYMEX benchmark at a price of US$4.17 per Mcf with an additional 2% hedged against the AECO benchmark at a price of $3.85 per Mcf.
As a result of lower drilling activity during the second quarter and planned turn-around activity, along with the impact of non-core property divestments, we expect to see a decline in production volumes during the third quarter. Although production has exceeded expectations year-to-date, we are not increasing our annual average production guidance beyond 85,000 BOE/day given our plans to continue to rationalize additional assets over the course of the year. If we are unable to complete additional divestments, we would expect our annual average and exit production to potentially exceed our current guidance. As the majority of the sales completed to date have been crude oil properties and with the growth in our natural gas production from our core assets, we now expect our crude oil and liquids production will represent approximately 48% of our total volumes in 2013.
We remain on track to meet our other guidance targets for 2013, with the exception of cash equity-based compensation expenses which we are increasing to $0.60 per BOE from $0.45 per BOE given the increase in our share price to date in 2013.
U.S. Filing Status
As a result of the increase in value of our U.S. assets combined with the majority of our shareholders residing in the U.S., effective January 1, 2014, we anticipate that Enerplus will no longer qualify as a “foreign private issuer” under U.S. securities regulations. Enerplus would then be considered a U.S. domestic issuer and would become subject to U.S. domestic reporting requirements from that date forward.
The change in filing status would not impact our operations, but would change the way in which we report and file our operating and financial results. For example, our financial statements would be prepared under U.S. Generally Accepted Accounting Principles. The U.S. GAAP financial statements will satisfy our Canadian filing obligations and IFRS statements will no longer be prepared. We expect the most significant differences between U.S. GAAP and IFRS for Enerplus will relate to the accounting for our oil and gas assets, specifically, impairment calculations and the accounting treatment for dispositions. Other differences may include the accounting for decommissioning liabilities and differences in balance sheet presentation. We expect these changes may impact earnings, however, we do not expect a material change in most of our key performance indicators such as funds flow, debt levels, capital spending, operating costs, general and administrative expenses, netbacks or adjusted payout ratio. Sales revenues and production volumes would be reported on a net (after royalty) basis however we will also provide supplementary disclosures for gross sales revenue and volumes to facilitate comparison with Canadian peers. In addition to filing our reserves under Canadian National Instrument 51-101 standards, our reserves information would also be prepared and filed under the U.S. SEC standards.
Enerplus has undergone significant change in our portfolio and strategy over the past few years. The impact of these changes is being reflected in our improved operational performance. Based upon our results for the first half of 2013 and including the non-core asset sales we’ve made year-to-date, we expect to meet or beat our guidance this year. We’ve achieved significant growth in production and funds flow and our balance sheet remains strong. As a result of this performance, we are delivering profitable growth and income to our investors.
Q2 Results Live Conference Call
A conference call hosted by Mr. Ian C. Dundas will be held at 9:00 am MT (11:00 am ET) to discuss these results. Details of the conference call are as follows:
|Date:||Friday, August 9, 2013|
|Time:||9:00 am MT (11:00 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)|
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 production volumes are presented on a company interest basis, being the Company’s working interest share before deduction of any royalties paid to others plus the Company’s royalty interests. Company interest is not a term defined in Canadian National Instrument 51-101- Standards of Disclosure for Oil and Gas Activities and may not be comparable to information produced by other entities.
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 and the impact of such on our 2013 production; 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; the performance of and future results from Enerplus’ assets and operations, including anticipated production levels, decline rates and future growth prospects; the expected change of our status from “foreign private issuer” to U.S. domestic issuer as of January 1, 2014 and expected changes in our reporting related thereto; and our ability to improve our trading multiple and create significant value for 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’ 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 continued availability and sufficiency of our funds flow and availability under our bank credit facility to fund our working capital deficiency; 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.
Ian C. Dundas
President & Chief Executive Officer
SOURCE Enerplus Corporation
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