CALGARY, Sept. 21 /CNW/ - Enerplus Resources Fund ("Enerplus") (TSX - ERF.un, NYSE - ERF) is pleased to announce the execution of a series of acquisitions and divestments in support of our strategy to reposition our portfolio and improve the focus and profitability of Enerplus. Over the past 18 months, Enerplus has added approximately 450,000 net acres of highly prospective land in both Canada and the U.S. creating new growth areas that are expected to add production and reserves in the years ahead.
"We have made tremendous progress on our strategy this year", says Gordon J. Kerr, President & Chief Executive Officer of Enerplus. "We have invested over $1.3 billion in two of the best resource plays in North America - the Bakken light crude oil play and the Marcellus shale gas play - expanding our portfolio and significantly improving the future growth prospects of Enerplus. In addition, the sale of the Kirby Oil Sands lease and other non-core conventional assets has allowed us to keep our balance sheet strong and will enable our people to focus on activities that will improve our operations and the bottom line".
<< Acquisition of Additional Bakken Properties in North Dakota ----------------------------------------------------------- >>
Building on our existing Bakken land base in North Dakota, Enerplus has entered into an agreement to acquire an additional 46,500 net acres (72 sections) of land in the Fort Berthold area of Dunn and McKenzie counties in North Dakota. These lands are directly adjacent to our existing land holdings in this area and are prospective for light crude oil in the Bakken and Three Forks formations. The acquisition materially expands our current position to over 70,000 net acres (109 sections) in the Fort Berthold area, the majority of which will be operated by Enerplus with a greater than 90% working interest. Enerplus has proven expertise in this area and recent drilling results have been above expectations. With this acquisition, we now have over 210,000 net acres of undeveloped land with early stage Bakken and Three Forks potential in North Dakota and Saskatchewan in addition to our core Bakken field at Sleeping Giant in Montana.
The acquisition includes approximately 800 bbls/day of light crude oil production and proved plus probable reserves of 10 million BOE primarily attributable to the Bakken formation based upon our internal evaluation. This compliments our existing estimate of eight million BOE of unbooked proved plus probable reserves in this area. The purchase price before closing adjustments is US$456 million and will be funded through Enerplus' existing credit facility. The acquisition is expected to close in October 2010.
Enerplus has been active in the Fort Berthold area since late 2009 and over the past year we have participated in the drilling of nine operated horizontal wells, six of which have been completed to date. The lateral length of these wells has ranged from 4,300 feet with 12 frac stages for the short lateral wells to 9,000 feet with 24 frac stages for the long lateral wells.
<< 30 Day Average 60 Day Average Production Rate/well Production Rate/well -------------------- -------------------- Short Lateral Wells (4 wells) 800 bbls/day 650 bbls/day Long Lateral Wells (2 wells) 1,190 bbls/day 1,100 bbls/day >>
Production from the long lateral wells has been limited due to fluid handling capacity.
Our internal assessment of the Bakken potential in this area is approximately five to six million barrels of original oil in place per section. Based upon a drilling density of two wells per section (two long lateral wells per 1,280 acres or two short lateral wells per 640 acres) with an approximate 15% recovery factor, we estimate an additional 50 million barrels of best estimate contingent resources on our combined working interest lands in the Fort Berthold area in addition to the 18 million BOE of proved plus probable reserves. We also believe the lands are prospective for the Three Forks formation for which we have estimated four to five million barrels of original oil in place per section. However, given the limited production data available, we are in the process of evaluating the potential recoveries and development opportunity that may exist in the Three Forks.
<< Expected Future Bakken Drilling Metrics: ---------------------------------------- Short Lateral Wells Long Lateral Wells ------------------- ------------------ Average Length 4,300 feet 9,000 feet Number of Frac Stages 12 24 30 Day Average Production Rates 650 bbls/day 1,200 bbls/day Expected Ultimate Recovery/Well 300 - 400 Mbbls 600 - 800 Mbbls Costs/Well (US$) $6.0 million $8.0 million >>
The breakeven supply cost to provide a minimum 12% rate of return in this area varies from US$40 WTI to US$60 WTI depending upon the lateral length of wells and recovery. Using current commodity prices and costs, we estimate the internal rates of return on this project range from 40% to over 100%. Based upon these economics, Enerplus will focus on maximizing the number of long lateral length wells. Our type curve assumes that the first 30 day average initial production rate will decline by approximately 80% in the first year.
Current production from our North Dakota properties, including the recent acquisition, is approximately 3,300 bbls/day of light sweet crude excluding the associated natural gas volumes which are not being captured at this time. We expect production volumes to increase to over 5,000 bbls/day by year-end. As the operator, Enerplus has the flexibility to manage the pace of development in this region due to the long tenure of the leases (average remaining life of 7.5 years). We expect to increase our spending in this area by approximately $25 million on drilling and completion activities through the remainder of 2010. We plan to have two rigs actively working in the area. We now estimate that our total capital expenditures in North Dakota in 2010 will be approximately $85 million. As we execute our drilling plans over the next five years, we would expect to see production grow to over 20,000 BOE/day from the Fort Berthold area.
<< Acquisition of Additional Operated Marcellus Properties ------------------------------------------------------- >>
On August 23, 2010, Enerplus closed the acquisition of 58,500 net acres of undeveloped land in the Marcellus shale natural gas play in northwest West Virginia and Maryland. The acreage is predominantly located in Preston County in West Virginia and Garret County in Maryland creating a new, concentrated land position that Enerplus will operate with an average 90% working interest. Enerplus has now invested over $150 million in the Marcellus shale gas play in 2010 acquiring two key operated areas comprised of approximately 70,000 net acres in addition to the 127,000 net acres of non-operated land that has been acquired since 2009.
These new lands in West Virginia and Maryland are in emerging areas with limited existing development however we believe that the geologic characteristics are similar to Fayette and Somerset counties of Pennsylvania. Early results from offset operators including those of our joint venture interests have been encouraging. While no proved or probable reserves have been acquired, we estimate original gas in place on this acreage of approximately 50 to 60 Bcf per 640 acres.
The concentrated nature of this operated position, together with the long tenure of the leases provides Enerplus the opportunity to control the pace of development and spending. A majority of the leases have two to three years remaining on the original five-year term with an additional five-year extension option at nominal cost. Our initial plans are to shoot seismic and begin the permitting process this fall and we expect to begin drilling in 2011.
Enerplus has captured a meaningful position in one of the best shale gas plays in North America that we believe will provide us with significant production growth over the next four years. To date, we are encouraged by the results of our development plans and current production is approximately 15 MMcf/day. We intend to continue to manage the commodity and asset mix of our portfolio to ensure we have flexibility in our capital spending. We are evaluating the possibility of reducing our non-operated acreage position given the addition of our new operated acreage and in order to maintain a desired level of exposure.
<< Sale of Kirby Oil Sands Lease ----------------------------- >>
Enerplus has entered into an agreement to sell 100% of its Kirby steam-assisted gravity drainage oil sands lease for gross proceeds of $405 million. We acquired a 100% working interest in the Kirby lease in 2007 for $203 million and since that time have invested an additional $58 million in Kirby to further delineate and identify the bitumen resource on the lease. The "best estimate" of contingent resources associated with the lease at December 31, 2009 was 497 million barrels of bitumen. The sale is subject to the satisfaction of customary closing conditions and obtaining the necessary regulatory approvals and is expected to close in early October 2010. Proceeds from the sale will be used to retire outstanding bank debt. TD Securities Inc. acted as exclusive advisor to Enerplus on this transaction.
Upon the conclusion of this sale, Enerplus' remaining oil sands portfolio will consist primarily of our equity ownership of 4.3 million shares in Laricina Energy, a private in-situ oil sands company that recently completed an equity financing at $30 per share.
<< Sale of Non-Core Conventional Assets ------------------------------------ >>
Enerplus has also made further progress on our strategy to sell non-core conventional assets in order to improve our focus and operational efficiency. As previously stated, we identified approximately 14,000 BOE/day of production for sale with approximately 3,400 BOE/day sold to date. We recently entered into agreements to sell an additional 2,500 BOE/day of production and 9.3 million BOE of proved plus probable reserves for approximately $158.5 million. This represents sale metrics of approximately $63,400 per flowing BOE of production and $17.00/BOE of proved plus probable reserves including future development costs. This production was comprised of 54% crude oil and natural gas liquids and 46% natural gas located primarily in British Columbia and Alberta from approximately 70 properties. The average operating cost of these properties was over $23.00/BOE with a netback in the range of $19.40/BOE. These sales are expected to close on or about September 30, 2010. FirstEnergy Capital Corp. and RBC Rundle have acted as exclusive advisors to Enerplus on these divestment packages.
We are also in the process of marketing a third package of non-core assets. This package primarily consists of a number of smaller non-operated properties that are gas weighted with lower working interests. Although negotiations are on-going, we believe we will sell a portion of these assets this year through a series of transactions representing approximately 4,500 BOE/day of current production and realize proceeds in the order of $140 million. Scotia Waterous Inc. is acting as exclusive advisor to Enerplus on this divestment package.
We will continue to evaluate opportunities to improve our portfolio however we would expect these last sales will complete the majority of our divestment activities this year. Upon completion of these divestments, Enerplus will have sold over 10,000 BOE/day of non-core production in 2010 for estimated total proceeds of over $900 million including the sale of Kirby.
<< Impact on 2010 Production Rates and Capital Spending ---------------------------------------------------- >>
As a result of these recent acquisition and divestment activities (including the prospective third divestment package) we are adjusting our 2010 production and capital spending guidance. We now expect to exit 2010 with production in the range of 80,000 BOE/day to 82,000 BOE/day with annual average production of 83,000 BOE/day to 84,000 BOE/day depending upon the timing and execution of our development capital plans and divestment activities. Capital spending is expected to increase by $30 million, totaling $515 million for 2010 with expected outstanding debt at year-end of $850 million. Our financial position remains strong providing us with the flexibility to manage our future capital spending and acquisition plans. Further details on our 2011 spending plans and production outlook will be provided in our 2011 guidance release expected in mid-December.
As a result of our acquisition and divestment activities over the past 18 months, Enerplus has significantly changed not only the composition of our asset base, but also the future growth potential of the company. We continue to evaluate strategic opportunities to enhance our portfolio and intend to maintain a disciplined approach to both our capital spending and our balance sheet.
INFORMATION REGARDING DISCLOSURE IN THIS NEWS RELEASE
All amounts in this news release are stated in Canadian dollars unless otherwise specified.
Where applicable, natural gas has been converted to barrels of oil equivalent ("BOE") based on 6 Mcf:1 BOE. The BOE rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. Use of BOE in isolation may be misleading.
In accordance with Canadian practice, production volumes and revenues are reported on a gross basis, before deduction of Crown and other royalties, unless otherwise stated. Unless otherwise specified, all reserves volumes in this news release (and all information derived therefrom) are based on "company interest reserves" using forecast prices and costs. "Company interest reserves" consist of "gross reserves" (as defined in National Instrument 51-101 adopted by the Canadian securities regulators ("NI 51-101")) plus Enerplus' royalty interests in reserves. "Company interest reserves" are not a measure defined in NI 51-101 and do not have a standardized meaning under NI 51-101. Accordingly, our company interest reserves may not be comparable to reserves presented or disclosed by other issuers.
This news release also contains internal estimates of "original oil-in-place" and "original gas-in-place". These estimates are the quantities of oil and gas, respectively, that are estimated to exist originally in naturally occurring accumulations and include the quantity of oil and gas, respectively, that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. These estimates do not constitute recoverable volumes. There is no certainty that all of these quantities will be discovered or, if discovered, that it will be commercially viable to produce any portion of these quantities.
INFORMATION REGARDING CONTINGENT RESOURCE INFORMATION IN THIS NEWS RELEASE
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 any portion of the volumes currently classified as contingent resources will be produced. The contingent resource estimates contained herein relating to the Kirby Oil Sands lease are presented as the "best estimate" of the quantity that will actually be recovered, effective as of December 31, 2009. Internal contingent resource estimates relating to the Bakken properties are effective as of August 1, 2010. 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.
For information relevant to the contingent resource estimate, see the Fund's Annual Information Form for the year ended December 31, 2009 dated March 12, 2010, a copy of which is available on our SEDAR profile at www.sedar.com and which forms part of our annual report on Form 40-F which is available on EDGAR at www.sec.gov.
NOTICE TO U.S. READERS
The oil and natural gas reserves information contained in this news release has generally been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects to United States or other foreign disclosure standards. Reserves categories such as "proved reserves" and "probable reserves" may be defined differently under Canadian requirements than the definitions contained in the United States Securities and Exchange Commission rules. In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross (or, as noted above, "company interest") volumes, which are volumes prior to deduction of royalty and similar payments. The practice in the United States is to report reserves and production using net volumes, after deduction of applicable royalties and similar payments.
FORWARD-LOOKING INFORMATION AND STATEMENTS
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", "guidance", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends" 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 additions to lands, production and reserves; Enerplus' strategy and future growth potential; future production growth; the volumes of production and potential reserves, resources, original-oil-in-place and original gas-in-place on the properties proposed to be acquired and sold by Enerplus; the anticipated closing dates and purchase and sale prices of certain oil and gas properties; potential future drilling and seismic activities; future drilling results, costs, production rates, break-even costs and internal rates of return; future development of Enerplus' lands; future capital expenditures; Enerplus' commodity and asset mix; potential asset and property dispositions by Enerplus and the timing and proceeds that may be received in connection therewith; Enerplus' 2010 exit production rate and aggregate capital expenditures; and. This press release also contains estimates of reserves, resources, original-oil-in-place and original gas-in-place, which are by their nature estimates that the quantities described exist in the amounts estimated.
The forward-looking information and statements contained in this news release reflect several material factors and expectations and assumptions of Enerplus including, without limitation: that the properties acquired and proposed to be acquired by Enerplus will perform as anticipated; that all conditions to closing of the proposed acquisitions and dispositions will be satisfied or waived, and all necessary regulatory approvals will be obtained, in a timely manner; that buyers will be found for certain oil and gas properties proposed to be sold by Enerplus on terms acceptable to Enerplus; the accuracy of Enerplus' estimates of oil and gas reserves, resources, original oil-in-place and original gas-in-place and production potential for the properties being acquired and disposed of; the general continuance of current or, where applicable, assumed industry conditions and tax and regulatory regimes; availability of cash flow, debt and/or equity sources to fund Enerplus' capital and operating requirements as needed; and certain commodity price and other cost assumptions. Enerplus 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: the failure to complete the proposed acquisitions and dispositions on the timing and terms currently contemplated or at all; inaccurate estimates of oil and gas reserves, resources, original oil-in-place, original gas-in-place, production estimates and drilling results; 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; a lack of capital to conduct planned capital expenditures, including 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 the Fund's public disclosure documents including, without limitation, those risks identified in our management's discussion and analysis for the year ended December 31, 2009 and in the Fund's Annual Information Form for the year ended December 31, 2009, copies of which are available on the Fund's SEDAR profile at www.sedar.com and which also form part of the Fund's Form 40-F for the year ended December 31, 2009, a copy of which is available on EDGAR at www.sec.gov.
The forward-looking information and statements contained in this news release speak only as of the date of this 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.
<< Gordon J. Kerr President & Chief Executive Officer Enerplus Resources Fund >>