Enerplus Resources Fund

Enerplus Resources Fund

August 19, 2009 16:24 ET

Enerplus Announces Strategic Marcellus Shale Acquisition and Equity Financing

CALGARY, ALBERTA--(Marketwire - Aug. 19, 2009) - Enerplus Resources Fund (TSX:ERF.UN)(NYSE:ERF) -

The Trust Units offered will be issued by way of a short form prospectus to be filed with the securities regulatory authorities in each of the provinces and territories of Canada. The offering is subject to the receipt of all necessary regulatory and stock exchange approvals and other customary conditions. The Trust Units offered have not been registered under the U.S. Securities Act of 1933, as amended, and will not be offered or sold in the United States. This press release shall not constitute an offer to sell or the solicitation of an offer to buy nor shall there be any sale of the securities in the United States or any jurisdiction in which such offer, solicitation or sale would be unlawful.

This news release contains forward-looking information and forward-looking statements, as well as references to "contingent resources", "original gas-in-place", "technically recoverable resources", "recycle ratio", "projected FD&A costs", "Tcfe", "Bcfe", "MMcfe" and "Mcfe". Unless otherwise indicated, all resource, reserve and production information included in this news release is on a gross working interest basis before the deduction of royalty/revenue interests. Additional information on these matters is included at the conclusion of this news release.

Enerplus Resources Fund ("Enerplus") is pleased to announce that it has entered into agreements with three private natural gas producers, Chief Oil & Gas LLC, Chief Exploration & Development LLC and a limited partnership managed by Tug Hill, Inc. (collectively "Chief"), to acquire 30% of their interests in the Marcellus shale natural gas resource play in the northeastern United States. Chief currently owns an average 72% working interest in approximately 540,000 gross acres, the majority of which is located in Pennsylvania within the heart of the Marcellus shale gas play. Upon completion of the acquisition, Enerplus will own an average 21.5% non-operated working interest in this acreage (approximately 116,000 net acres).

Total consideration for the acquisition is US$406 million (approximately US$3,500/net acre) comprised of US$162.4 million in cash to be paid upon closing and US$243.6 million to be paid as a carry of 50% of Chief's future drilling and completion costs in the Marcellus shale play, which we expect will be invested over the next four years. As part of the transaction, Enerplus will also enter into Area of Mutual Interest ("AMI") agreements with Chief that will allow us the opportunity to partner on any follow-on acquisitions or swaps in the Marcellus play. These AMIs will provide us with the opportunity to jointly acquire more land under the current ownership structure as well as the potential to increase our working interest ownership and possibly operate in certain new areas. Enerplus is obligated to pay the carry amount in order to retain the full 30% working interest in Chief's lands and participate in the AMI. We expect the transaction to close in early September 2009, subject to standard closing conditions, with an effective date of May 1, 2009.

"This transaction is a significant step in high-grading our asset base to provide greater growth potential and further improve our operating performance", stated Gordon Kerr, President & Chief Executive Officer. "Enerplus has gained an entry point into one of the premier shale gas resource plays in North America, consistent with our strategic direction, with an experienced partner who has a proven track record in shale gas development. With the play in the early stages of development, we believe there is tremendous opportunity for future production, reserves and value growth".

In conjunction with the acquisition, Enerplus has agreed to issue 9.25 million trust units through a Canadian bought deal financing at a price of CDN$21.65 per trust unit for gross proceeds of CDN$200 million. A portion of the net proceeds are expected to be used to pay for the upfront cash portion of the acquisition and the remainder will initially be used to repay bank indebtedness and subsequently used to fund a portion of Enerplus' on-going capital expenditures.



The Marcellus shale is the largest unconventional natural gas resource play in North America according to an April 2009 report prepared for the U.S. Department of Energy (the "USDE Report"). Spanning six states in the northeastern U.S., the play covers an estimated 95,000 square miles. Given the much larger aerial extent of this play compared to the other shale gas plays, according to the USDE Report, the Marcellus play has the highest estimate of original gas in place of up to 1,500 trillion cubic feet ("Tcf") and approximately 262 Tcf of technically recoverable resource. For additional information regarding the quantities estimated in the USDE Report, see "Information Regarding Contingent Resource and Other Estimates" at the end of this news release. The use of horizontal drilling technology and hydraulic fracture treatments has been the key to unlocking the large resource basins in North America, making them economically feasible to produce. With its proximity to the large northeast U.S. natural gas market and expanding pipeline take-away capacity, natural gas from the Marcellus receives a premium price and has one of the lowest breakeven prices of all natural gas producing areas in North America.


Enerplus is acquiring an average 21.5% working interest in approximately 540,000 gross acres in the heart of the Marcellus shale fairway with an average net revenue interest of approximately 82%. This land is located primarily in Pennsylvania, concentrated in the northeast and southwest areas of the state, with additional acreage in West Virginia and Maryland. Much of the acreage is contiguous with an average primary lease term of approximately five years. As well, the majority of the leases allow extensions of the primary term for an additional five years.

Based upon the current development plans, Enerplus would participate in the drilling of approximately 750 gross wells over the next five years and production volumes are expected to increase to approximately 100 MMcfe/day of natural gas to Enerplus before royalties over that period. Current production is approximately 8.2 MMcfe/day gross (1.8 MMcfe/day to Enerplus) and using our internal estimates prepared in accordance with National Instrument 51-101 ("NI 51-101"), Enerplus is acquiring approximately 8.0 Bcfe of gross proved plus probable reserves based upon our working interest using forward prices and costs as of June 8, 2009.

Enerplus has conducted an internal evaluation of the leases in accordance with NI 51-101 and has determined a best estimate of contingent resources of approximately 1.4 Tcfe of natural gas applicable to our working interest effective July 1, 2009. This estimate is based upon a drilling density of four to six wells per 640 acre spacing which would result in over 2,400 gross wells. Notwithstanding that we believe the Marcellus natural gas formation is present over the entire acreage block, our best estimate assumes only 55% of the land is developed. As development plans move forward, we believe a greater percentage of the land could be drilled and/or drilling densities increased thereby increasing the reserves and potentially the resource estimates over time. An independent third party reserve and contingent resource evaluation is expected to be completed at year end.

Given the early stage of development, Enerplus believes the majority of the current value resides in the land and its future resource potential. While the transaction is not immediately accretive to production or reserves per unit and will result in increased 2009 finding, development and acquisition ("FD&A") costs for Enerplus at a corporate level, we expect the significant future growth potential to provide accretion as the leases are developed. We anticipate attractive long-term acquisition and development metrics on the acquired Marcellus interests. Based upon our best estimate of contingent resources and the acquisition costs and forecast capital spending including the vendor carry, we expect a projected FD&A cost of approximately US$1.60/Mcfe and recycle ratios of over 3x.

See "Information Regarding Contingent Resource and Other Estimates" and "Information Regarding Disclosure in this News Release" at the end of this news release.


During the remainder of 2009, Enerplus plans to spend approximately US$27 million on the acquired interests to drill 15 gross wells including the vendor carry provisions of a Joint Development Agreement ("JDA") to be entered into upon closing of the acquisition. Since acquiring the land in 2007, Chief has drilled 10 vertical and 21 horizontal natural gas wells of which nine are currently producing. Chief currently has three drilling rigs contracted and we expect the number of rigs employed would be increased to 10 by 2012 under the current development plans. For the period from 2010 to 2014, Enerplus anticipates investing approximately US$800 million in development capital, including the vendor carry obligations.

Enerplus expects the average well costs to be between US$3.5 million to US$4.0 million per horizontal well, with an average drilling time of 30 days or less. The development program will utilize horizontal drilling technology with multi-stage, slickwater fracs. We expect initial production rates of 3.5 MMcfe/day to 4.0 MMcfe/day gross and expected ultimate recovery of approximately 3.0 Bcfe to 3.5 Bcfe of natural gas gross per well.

Within the context of current forward natural gas markets, we have assumed an operating netback of US$3.49/Mcfe for 2010, reflecting a Henry Hub price of US$5.77/Mcf, a combined heat content and location basis premium of US$0.49/Mcfe, royalties of US$1.20/Mcfe, operating and gathering costs of US$1.32/Mcfe, and proposed state severance taxes of US$0.25/Mcfe.


Chief is an experienced shale gas producer. Their involvement in unconventional shale gas began in the Texas Barnett shale in 1997 where they drilled and completed over 400 wells and developed 1.1 Tcf of proved reserves before selling their Barnett interests in 2006 and 2008. Chief has been building their acreage position in the Marcellus play over the past few years by applying their considerable shale gas experience to this emerging shale gas play.

Chief will continue to operate the properties in which Enerplus has acquired interests. Chief has added technical personnel to augment the seasoned team that was responsible for the success in the Barnett shale. Enerplus expects to have opportunities for meaningful information sharing and participation through the JDA and will have an agreement to place our technical staff within the Chief organization to build our knowledge and expertise of the Marcellus play. Enerplus has a proven track record of resource play development in the U.S. through our Sleeping Giant Bakken oil shale property in Montana. Since acquiring this asset in 2005, we have established and staffed our office in Denver, drilled over 100 successful horizontal wells and increased production and reserves substantially from this field.

As part of the transaction, Enerplus will enter into a long-term agreement with Chief Gathering LLC, an affiliate of Chief Oil & Gas LLC, for the gathering, dehydration and compression of Enerplus' share of production. Chief Gathering LLC is one of the leaders in the building of gathering infrastructure to handle Marcellus production, using its expertise gained in the Barnett shale region of Texas. This agreement will provide Enerplus with cost and market access certainty and direct ties to the northeastern United States natural gas markets through Chief Gathering LLC's existing and in-progress interconnections with the major interstate pipelines.

RBC Capital Markets and Tudor Pickering Holt & Co. acted as financial advisors to Enerplus on this transaction. Bank of America Merrill Lynch acted as the exclusive financial advisor to Chief and Tug Hill with respect to the transaction.


Enerplus expects that development capital spending for 2009 will increase from our previously announced guidance of CDN$300 million to approximately CDN$330 million including the additional capital required to fund the drilling program in the Marcellus. We plan to invest approximately US$100 million including the vendor carry obligations in 2010 to continue to develop the Marcellus play, drilling approximately 54 gross wells and expect to provide an estimate of our complete 2010 capital investment program in December. It is our expectation that we will fund the future capital requirements of this program through a combination of cash flow and/or debt.


Concurrent with the acquisition, Enerplus has entered into an agreement to issue, to a syndicate of Canadian underwriters on a bought deal basis, 9,250,000 trust units at a price of $21.65 per trust unit for gross proceeds of $200 million. Enerplus has granted the underwriters an option, exercisable in whole or in part until 30 days following closing, to purchase up to 1,156,250 additional trust units at the same offering price, to cover over-allotments and for market stabilization purposes if necessary. Should the underwriters' over-allotment option be fully exercised, the total gross proceeds of the financing will be $225 million. We expect the equity issue to close on September 9, 2009 and the new trust units issued would be eligible for the cash distribution paid to unitholders of record at the close of business on September 10, 2009. The completion of the equity offering and the closing of the Chief acquisition are independent of each other.

The underwriting syndicate is jointly led by CIBC World Markets Inc. and RBC Capital Markets, and includes BMO Capital Markets, Scotia Capital Inc., TD Securities Inc., National Bank Financial Inc., FirstEnergy Capital Corp., HSBC Securities (Canada) Inc., Raymond James Ltd., Canaccord Capital Corporation, Peters & Co Limited and Tristone Capital Inc.


Unless otherwise indicated, all dollar amounts in the news release are in Canadian dollars. This news release contains references to "Mcfe" (thousand cubic feet of gas equivalent), "MMcfe" (million cubic feet of gas equivalent), "Bcfe" (billion cubic feet of gas equivalent) and "Tcfe" (trillion cubic feet of gas equivalent). Enerplus has adopted the standard of one barrel of oil to six thousand cubic feet of gas (1 bbl: 6 Mcf) when converting oil to Mcfe, MMcfe, Bcfe or Tcfe. Mcfes, MMcfes, Bcfes and Tcfes may be misleading, particularly if used in isolation. A conversion ratio of 1 bbl: 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

This new release also uses the term "recycle ratio". A recycle ratio is calculated by dividing operating netback per Mcfe by the projected FD&A cost per Mcfe. The term "recycle ratio" is an operational measure presented by Enerplus that does not have a standardized meaning or definition prescribed by Canadian generally accepted accounting principles and may not be comparable to similar measures presented by other issuers.


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" 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: the completion and timing of the acquisition by Enerplus of the Marcellus properties; future production and reserves growth and associated costs; future capital and development expenditures and future acquisitions; development and drilling activities, projected FD&A costs, recycle ratios, netbacks and other operational results; Enerplus' ongoing strategy; and the completion, use of proceeds and timing of Enerplus' equity offering. This news release also contains estimates of reserves, contingent resources, original gas-in-place, technically recoverable resources and other estimated volumes, which are by their nature estimates that the quantities described exist in the amounts indicated. See "Information Regarding Contingent Resource and Other Estimates" below.

The forward-looking information contained in this news release reflects several material factors and expectations and assumptions made by Enerplus including, without limitation: the satisfaction of all conditions required to complete the acquisition of the interests in the Marcellus properties and the equity offering; the ability of Enerplus to fund its required vendor carry cost obligations and the ability of Enerplus and its industry partners to develop the properties in the manner currently contemplated; the general continuance of current or, where applicable, assumed industry conditions; availability of cash flow, debt and/or equity sources to fund Enerplus' capital and operating requirements as needed; the accuracy of the estimates of the reserves and resources volumes; and certain commodity price and other cost assumptions. Enerplus believes the material factors, expectations and assumptions reflected in the forward-looking information 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 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 including, without limitation: failure to satisfy the conditions to complete the Marcellus acquisition or the equity offering; failure of Enerplus to fund its vendor carry cost obligations to maintain certain of its ownership interests in the properties; changes in commodity prices; unanticipated operating results or production declines; changes in tax or environmental laws or royalty rates; increased debt levels or debt service requirements; inaccurate estimation of reserves and resources volumes; limited, unfavourable or no access to debt or equity capital markets; increased costs and expenses; 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 MD&A for the year ended December 31, 2008 and in our Annual Information Form for the year ended December 31, 2008, copies of which are available on Enerplus' SEDAR profile at www.sedar.com and which also form part of Enerplus' Form 40-F for the year ended December 31, 2008 filed with the SEC, a copy of which is available at www.sec.gov.

The forward-looking information contained in this news release speaks only as of the date of this news release, and Enerplus assumes no 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.


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 (the "COGE 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. The contingent resource estimate for the acquired interests in the Marcellus properties set forth in this news release is presented as Enerplus' internal ''best estimate'' of the quantity that will actually be recovered effective as of July 1, 2009. 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. The primary contingencies which currently prevent the classification of Enerplus' disclosed contingent resources associated with the Marcellus properties as ''reserves'' consist of: additional delineation drilling to establish economic productivity in the development areas, limitations to development based on adverse topography or other surface restrictions, the uncertainty regarding marketing and transportation of natural gas from development areas, all required regulatory permits and approvals to develop the lands, and access to confidential information of other operators in the Marcellus formation. Significant negative factors related to the estimate include: the pace of development, including drilling and infrastructure, is slower than the forecast, risk of adverse regulatory and tax changes, ongoing litigation related to minimum royalties payable to freehold landowners, and other issues related to gas development in populated areas. There are a number of inherent risks and contingencies associated with the development of the acquired interests in the Marcellus properties, including: commodity price fluctuations, project costs, Enerplus' ability to make the necessary capital expenditures to develop the properties, reliance on Enerplus' industry partners in project development, acquisitions, funding and provisions of services and those other risks and contingencies described above and that apply generally to oil and gas operations as described under ''Risk Factors'' in Enerplus' Annual Information Form dated March 13, 2009, a copy of which is available on Enerplus' SEDAR profile at www.sedar.com, and which also forms part of Enerplus' Form 40-F for the year ended December 31, 2008 filed with the SEC, a copy of which is available at www.sec.gov.

Furthermore, this news release includes references to "original gas-in-place" and "technically recoverable resources" with respect to the Marcellus shale resource play, as noted in a report dated April 2009 and entitled "Modern Shale Gas Development in the United States: A Primer" prepared for the U.S. Department of Energy, Office of Fossil Energy and National Energy Technology Laboratory (the "USDE Report"). The USDE Report defines "original gas-in-place" as "the entire volume of gas contained in the reservoir, regardless of the ability to produce it". The USDE Report defines "technically recoverable resources" as "the total amount of resource, discovered and undiscovered that is thought to be recoverable with available technology, regardless of economics." Neither NI 51-101 nor the COGE Handbook contains a definition of "original gas-in-place" or "technically recoverable resources", and, accordingly, such terms do not have a standardized meaning thereunder. The estimates of "original gas-in-place" and "technically recoverable resources" contained in the USDE Report and referenced in this news release may not be comparable to similar estimates presented by other issuers. Furthermore, the USDE Report states that the estimates of "original gas-in-place" and "technically recoverable resources" described therein are presented for general comparative purposes only and the research to obtain such numbers did not include a resource evaluation. Rather, publicly available data was obtained from a variety of sources and presented therein for general characterization and comparison. The USDE Report states that resource estimates for any basin may vary greatly depending on individual company experience, data available at the time the estimate was performed, and other factors, and that these estimates are likely to change as production methods and technologies improve. It is uncertain whether the estimates of "original gas-in-place" and "technically recoverable resources" in the USDE Report were prepared by a qualified reserves evaluator or auditor within the meaning of NI 51-101.

This news release includes a reference to Enerplus' estimate of future "projected FD&A costs" with respect to the interests it is acquiring in the Marcellus properties. These estimated "projected FD&A costs" have been calculated as the total acquisition cost for the Marcellus acquisition (including the vendor carry amount) plus Enerplus' estimate of its future development costs on the acquired interests in the Marcellus properties, divided by Enerplus' best estimate of contingent resources and gross proved plus probable reserves attributable to its acquired interests in the Marcellus properties. The "projected FD&A costs" referenced in this news release is an estimate by Enerplus of future results based on certain assumptions and is by its nature a projection which is different than "finding and development costs" calculated in accordance with NI 51-101, which is an historical calculation. The estimate of "projected FD&A costs" has been provided as Enerplus believes it provides a reasonable estimate of the long-term economics of the acquisition. The measure of "projected FD&A costs" disclosed herein does not have a standardized meaning prescribed by NI 51-101 or the COGE Handbook and therefore this measure, as defined by Enerplus, may not be comparable to similar measures (including "finding and development costs" and "finding, development and acquisition costs") presented by other issuers. The estimate of "projected FD&A costs" constitutes forward-looking information and therefore reflects several material factors, expectations and assumptions and is subject to a number of risk factors. See "Forward-Looking Information and Statements" above for further information.

Gordon J. Kerr, President & Chief Executive Officer

Enerplus Resources Fund

Contact Information