Enerplus announces operational guidance for 2010 and preliminary 2009
year-end reserve and resource information
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. For information regarding the presentation of certain information in this news release, see "Currency, BOE and Operational Information" at the conclusion of this news release.
We are positioning Enerplus to deliver competitive long-term returns that include a balance between growth and income to investors. Our 2010 development capital program and operating guidance reflects compelling economic returns from our investments into existing assets while also investing in organic early stage growth opportunities. We intend to continue adding quality assets in both
Capital Development Spending
We are forecasting 2010 capital development spending of
In comparison with last year, this increase in capital spending is primarily related to new opportunities in the Bakken oil resource play and the Marcellus shale gas play. We anticipate that approximately
Our capital spending plans include approximately
We will review our 2010 capital investment plans regularly throughout the year in the context of prevailing economic conditions and potential acquisitions, and make adjustments as deemed necessary. We anticipate our spending will be evenly distributed throughout the year given the nature and location of our spending.
Projected 2010 Capital Expenditures
Spending* Number of net wells
Resource Play ($ millions) to be drilled
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Bakken/Tight Oil $118 42
Waterfloods 92 38
Other Conventional Oil 27 7
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Total Oil $237 87
Marcellus Shale Gas $80 11
Tight Gas 49 5
Shallow Gas 38 156
Other Conventional Gas 21 10
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Total Gas $188 182
Company Total $425 269
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% crude oil 56% 32%
* Capital spending total is after the recovery of $33 million of
Alberta drilling royalty credits; includes drilling, facilities,
maintenance and capitalized G&A
Production Guidance
Based upon our capital spending plans for 2010, we expect to produce on average approximately 37,000 bbls/day of crude oil and natural gas liquids and 294 MMcf/day of natural gas, totaling approximately 86,000 BOE/day, down roughly 2% from our anticipated 2009 exit rate of approximately 88,000 BOE/day. Crude oil and natural gas liquids production is expected to increase throughout 2010 and represent approximately 45% of our exit rate volumes. As the results of our development programs are realized, we expect our exit production rate will increase back to our anticipated 2009 exit rate levels of approximately 88,000 BOE/day setting the stage for continued growth in 2011. Our production forecast does not reflect any acquisition or divestment activities in 2010.
Projected 2010 Average Annual Production
Crude Natural Gas
Resource oil Liquids Natural Gas Total
Play (bbls/day) (bbls/day) (MMcf/day) (BOE/day)
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Bakken/Tight Oil 9,900 - 8.4 11,300
Waterfloods 13,400 500 9.0 15,400
Marcellus Shale Gas - - 10.8 1,800
Tight Gas - 1,700 67.8 13,000
Shallow Gas - - 114.6 19,100
Conventional Oil
& Gas 9,700 1,800 83.4 25,400
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Company Total 33,000 4,000 294 86,000
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% of Total 38% 5% 57%
Projected 2010 Exit Rate Production
Crude Natural Gas
Resource oil Liquids Natural Gas Total
Play (bbls/day) (bbls/day) (MMcf/day) (BOE/day)
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Bakken/Tight Oil 10,900 - 8.4 12,300
Waterfloods 14,400 500 9.0 16,400
Marcellus Shale Gas - - 18.0 3,000
Tight Gas - 1,700 69.0 13,200
Shallow Gas - - 109.2 18,200
Conventional Oil
& Gas 9,700 1,800 80.4 24,900
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Company Total 35,000 4,000 294 88,000
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% of Total 40% 5% 55%
Operating Costs
We expect operating costs to be approximately
General & Administrative Costs and Conversion Costs
G&A costs are expected to average
In addition, we are expecting an incremental
Royalties & Taxes
In the context of current forward commodity prices, we expect Crown and freehold royalties to be approximately 20% of our gross oil and gas sales in 2010, which is slightly higher than our 2009 expectations of 17%. In addition, we expect cash taxes to be less than 5% of our U.S. cash flow in 2010. We do not expect to pay any significant Canadian taxes.
Hedging
Based upon the current forward market, Enerplus has floor protection on approximately 34% of our forecast 2010 crude oil production net of royalties at an effective price of approximately US$77 per barrel. With regard to natural gas, we currently have approximately 17% of our projected 2010 natural gas production volumes, net of royalties, hedged at an effective price of
Acquisitions
As part of our strategy to improve our performance and introduce more early stage growth opportunities to our portfolio, we expect to continue to pursue acquisitions in tight oil and tight gas resource plays. We currently have our entire
We expect to spend approximately
Divestments
As part of our strategy to improve the profitability and focus within our portfolio, we plan to divest of various non-core properties that do not fit with our resource play focus. These properties are located primarily within western
Kirby Oil Sands
We continue to expect regulatory approval of our 10,000 BOE/day Kirby in-situ oil sands project in early 2010. While we believe that there is value in the Kirby project, the anticipated return on investment and timing of positive cash flow is currently not compelling relative to our existing portfolio of opportunities. As a result, our 2010 capital budget includes minimal spending associated with this lease. We continue to believe in the quality and potential of Kirby and our independent reserve engineers have increased the best estimate of contingent resources by more than 100% to approximately 500 million barrels of bitumen since acquiring Kirby in early 2007. See "Information Regarding Contingent Resource Estimates" at the end of this news release. We will be reviewing our long-term plans as they relate to Kirby in 2010.
Financial Strength
Enerplus has one of the strongest balance sheets within the oil and gas sector with a trailing 12 month debt to cash flow ratio of 0.7 times at
We expect that our debt levels may increase by approximately
Given our focus on early stage resource plays such as the Marcellus and Bakken, we will consider investment and distribution levels that modestly exceed cash flow provided we retain balance sheet strength and achieve compelling economics on our development capital program.
Preliminary 2009 Year-End Contingent Resource and Reserves Outlook
In August of 2009, Enerplus advised that McDaniel & Associates Consultants Ltd. ("McDaniel") was replacing Sproule Associates Ltd. as our independent reserve evaluator for all our Canadian conventional assets. GLJ Petroleum Consultants Ltd. ("GLJ") will continue to evaluate our oil sands assets, Netherland Sewell & Associates Inc. ("NSAI") will continue to evaluate our western U.S. assets and Haas Petroleum Engineering Services Inc. ("Haas"), established oil and gas reserve evaluators located in
We expect a material increase in the contingent resources for the company from both the acquisition in the Marcellus shale gas play and on oil sands as compared to year-end 2008. Haas has completed a preliminary contingent resource estimate on the Marcellus and GLJ has completed their draft contingent resource report on our Kirby oil sands property. Both of these estimates have been conducted in accordance with National Instrument 51-101. For additional information on disclosure of contingent resource estimates, see "Information Regarding Contingent Resource Estimates" at the end of this news release.
Based on the draft GLJ report, the Kirby oil sands best estimate of contingent resources has increased from 417 million barrels of bitumen at year-end 2008 to 497 million barrels of bitumen at year-end 2009 which reflects a 19% increase year-over-year and a 104% increase since acquiring the lease in 2007.
Based on the preliminary Haas report, we expect the best estimate of contingent resources in our Marcellus acreage to increase 0.7 trillion cubic feet ("Tcf") from an internal estimate of 1.4 Tcf of natural gas effective
We expect to book only a modest amount of reserves associated with our Marcellus properties at year-end 2009 given the limited number of wells and limited time these wells have been on production. We do, however, continue to see upside as reflected in the contingent resource estimate and would expect to see F&D costs, FD&A costs and recycle ratios improve corporately over time with success in this and other plays within the company.
Based upon discussions with NSAI to date, we do not expect any material revisions to our U.S. reserves and we continue to expect positive additions associated with the on-going development of these assets.
Preliminary estimates from McDaniel, combined with an internal assessment of our minor properties, have indicated a decrease of approximately 0.36 Tcf of natural gas reserves and 6.5 MMbbl of crude oil reserves representing approximately 24% of our natural gas reserves and approximately 4% of our crude oil reserves on a proved plus probable basis at year-end 2008. These revisions are due to changes in evaluation methodology, the removal of undeveloped drilling locations, reservoir performance and the decline in natural gas prices all of which are primarily associated with our shallow natural gas assets. We expect a final report early in 2010 and will include this information in our year-end results which we anticipate announcing in late
From a methodology standpoint, McDaniel has made a different assessment of final producing rates and decline factors than previously used which has resulted in a significant impact primarily on our shallow gas reserves.
We expect to remove approximately half of the undeveloped drilling locations from our year-end reserves estimates, the majority of which are shallow gas. This relates in part to our plans to direct less capital to these assets in the future as we now have better opportunities elsewhere in our portfolio as well as the decline in gas prices which has made a number of drilling locations uneconomic. Reservoir performance issues associated with our shallow natural gas properties have also reduced the number of drilling locations and associated reserve volumes although we expect to continue drilling approximately 200 shallow gas wells per year subject to gas prices and portfolio changes. We expect to have in the order of six years of drilling inventory after adjustments at year-end 2009.
The performance shortfall is related primarily to shallow gas performance associated with increased interference and poorer infill well performance. This poorer performance has steepened the decline of our shallow gas properties yet it has not had a material impact on our current year production and we continue to see overall corporate production performance that remains in line with our expectations. We have also incorporated this decline in performance into our 2010 production guidance.
We expect our overall 2009 corporate finding & development ("F&D") costs, finding, development & acquisition ("FD&A") costs and recycle ratios to be negatively impacted by the revisions noted above. While this will also impact our net asset value, we believe that the impact may be less on a proportional basis given the declines are largely attributable to natural gas properties and the later life impact of some of the reserve changes.
Outlook
Enerplus is well positioned to execute on our growth and income-oriented business strategy. We are focused on activities that we expect will improve our operational performance and deliver value through growth and distributions. We are executing on our strategies relative to early stage participation in resource growth plays such as the Marcellus and expansion of our Bakken and Deep Basin interests. When combined with our continued financial strength, we are setting the stage for success going forward.
Gordon J. Kerr
President & Chief Executive Officer
Enerplus Resources Fund
Currency, BOE and Operational Information
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All dollar amounts or references to "$" in this news release are in Canadian dollars unless specified otherwise. Where applicable, Canadian dollar amounts have been converted to U.S. dollars using an exchange rate of CDN$1.00 = US$1.06. The actual U.S. dollar equivalent may be greater or less than the amount presented based on the exchange rate in effect at the applicable times.
Enerplus has adopted the standard of 6 Mcf:1 BOE when converting natural gas to BOEs. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 BOE is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Unless otherwise stated, all oil and gas production information and estimates are presented on a gross basis, before deducting royalty interests.
Cautionary Note Regarding Forward-Looking Information and Statements
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This news release contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "budget", "guidance", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", "strategy" and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: future capital spending amounts (including capital carry commitments), the timing thereof and the types of projects on which such capital will be spent; increased opportunities associated with growth assets; returns on our expenditures and investments; future oil and natural gas prices and foreign exchange rates; future acquisitions and dispositions and the costs and proceeds realized therefrom; drilling activities; the volume and product mix of our oil and natural gas production; the development of our oil sands project (including receipt of regulatory approvals); reserve and contingent resource estimate and the assumptions relating thereto, including land development and well densities and production; future operating, general and administrative and trust conversion costs and other expense estimates; F&D costs, FD&A costs and recycle ratios; royalties and taxes payable; our commodity risk management programs; future liquidity, debt levels and financial capacity and resources; future cash distributions to our unitholders; corporate structure and conversion to a corporate form and the timing thereof; and future growth opportunities including development, exploration, and acquisition activities and related expenditures.
The forward-looking information and statements contained in this news release reflect several material factors and expectations and assumptions of the Fund including, without limitation: that the Fund will conduct its operations, and will achieve operational results, as anticipated; the general continuance of current or, where applicable, assumed industry conditions; continuation of improved commodity prices; availability of cash flow, debt and/or equity sources to fund the Fund's capital and operating requirements as needed and to pay distributions to unitholders; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; availability of willing buyers for the properties proposed to be disposed of; well density and production rates and land development; and certain commodity price, foreign exchange rate and other cost assumptions. The Fund believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable at this time but no assurance can be given that these factors, expectations and assumptions will prove to be correct.
The forward-looking information and statements included in this news release are not guarantees of future performance and should not be unduly relied upon. Such information and statements involve 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 or statements including, without limitation: changes in commodity prices; unanticipated operating results or production declines; changes in tax or environmental laws or royalty rates; failure to receive required third party approvals; increased debt levels or debt service requirements; inaccurate estimation of or changes to estimates of the Fund's oil and gas reserves and resources volumes and the assumptions relating thereto; limited, unfavourable or no access to debt or equity capital markets; increased costs and expenses; the impact of competitors; reliance on industry partners; factors that may lead to an early conversion to a corporate structure; and certain other risks detailed from time to time in the Fund's public disclosure documents including, without limitation, those risks identified in our MD&A for the year ended
The forward-looking information and statements contained in this news release speak only as of the date of this news release, and none of the Fund or its subsidiaries assumes any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.
Information Regarding Contingent Resource Estimates
This news release contains estimates of "contingent resources". "Contingent resources" are not, and should not be confused with, oil and gas reserves. "Contingent resources" are defined in the Canadian Oil and Gas Evaluation Handbook as "those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage." There is no certainty that it will be commercially viable to produce any portion of the contingent resources or that Enerplus will produce any portion of the volumes currently classified as contingent resources. A "best estimate" of contingent resources means that it is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate, and if probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the best estimate.
The recovery and resource estimates provided herein are estimates only. Actual contingent resources (and any volumes that may be reclassified as reserves) and future production from such contingent resources may be greater than or less than the estimates provided herein. For a description of Enerplus' Kirby oil sands project, including the primary contingencies which currently prevent the classification of Enerplus' disclosed contingent resources associated with the Kirby oil sands project as reserves and the inherent risks and contingencies associated with the resource estimates and development of the project, see "Presentation of Enerplus' Oil and Gas Reserves, Resources and Production Information", "Operational Information - Enerplus' Play Types - Oil Sands" and "Risk Factors" in the Fund's Annual Information Form dated
%CIK: 0001126874
For further information: please contact our Investor Relations Department at 1-800-319-6462 or email [email protected]
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