Enerplus announces 2009 year end results and reserves information
This news release includes forward-looking information and statements within the meaning of applicable securities laws. Readers are referred to "Forward-Looking Information and Statements" at the end of this news release for further information. Readers are also referred to "Information Regarding Reserves, Resources and Operational Information in this News Release", "Notice to U.S. Readers" and "Non-GAAP Measures" at the end of this news release for information regarding the presentation of the financial, reserves, contingent resources and operational information in this news release and the use of the terms "BOE", "Mcfe", "MMcfe", "Bcfe" and "Tcfe" and similar terms in this news release. A full copy of our 2009 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, Feb. 25 /CNW/ - 2009 was a transition year for Enerplus Resources Fund ("Enerplus") (TSX - ERF.un, NYSE - ERF) as we continued to move from an income model to a hybrid growth and income-oriented model. During this transition, we have been focused on delivering on operational targets, repositioning the asset base, adding key leadership and technical skills and ensuring a balance of distributions and capital reinvestment in line with cash flows. We made significant progress with respect to these strategies and we believe we are well positioned for success beginning in 2010 as the performance from our new growth plays begin to contribute to our results.
We are realigning our asset base to include not only mature income-oriented assets but also early stage, growth-oriented assets such as the Marcellus shale gas play in the U.S., Bakken/tight oil on both sides of the border and Deep Basin tight gas in Canada. We have begun to build a meaningful portfolio of growth prospects and expect to continue adding these types of properties to our portfolio. We also believe a greater concentration of assets will allow us to focus our activities on a fewer number of high impact properties and create the greatest value for our unitholders. We completed an initial $100 million divestment in 2009 and plan to market and potentially divest up to 14,000 BOE/day of non-core assets, representing roughly 15% of our current production volumes. We have also been adding key skills within our organization to support this strategy at both the leadership and technical level.
In 2009, we managed our development capital spending and distributions within cash flows while meeting our production targets and advancing our growth strategy. We deferred our oil sands program to focus our capital in our other growth plays.
BUILDING FUTURE GROWTH POTENTIAL:
- Enerplus invested over $500 million in 2009 acquiring over 226,000 net acres (approximately 350 net sections) of early stage growth lands in the Marcellus shale gas (approximately 200 net sections), Bakken/tight oil in Saskatchewan and North Dakota (approximately 78 net sections), Deep Basin tight gas in Alberta and British Columbia (approximately 29 net sections) and other various plays.
- We added over 2.1 trillion cubic feet equivalent ("Tcfe") of contingent resources associated with our Marcellus shale gas assets, providing the opportunity to more than triple our current total natural gas proved plus probable reserves.
- We invested $82 million on assessment activities associated with early-stage resource plays including land, seismic and drilling.
- We increased the best estimate of contingent resources associated with our Kirby Oil Sands lease by 20% to 497 million barrels, adding 83 million barrels from the estimate at year end 2008. Since acquiring the lease in 2007, we have increased the contingent resource estimate by over 100%.
PRESERVING FINANCIAL STRENGTH:
- Through our disciplined approach to capital spending and distributions, we maintained a strong balance sheet and exited 2009 with a trailing debt-to-cash flow ratio of 0.6x.
- Our unused debt facility of approximately $1.4 billion should provide meaningful credit capacity to fund additional acquisitions and further transition the asset base.
- Cash flow from operating activities was down considerably in 2009 to $776 million from $1,263 million in 2008 as a result of decreased commodity prices.
- Cash distributions paid to unitholders were reduced by 56% and totaled $2.23 per trust unit. In total, 47% of cash flow was paid to unitholders.
- Cash distributions and development capital spending combined represented 87% of cash flow for the year.
- Our oil and natural gas hedging program generated cash gains of $155.8 million during 2009.
OPERATIONAL PERFORMANCE:
- Production averaged 91,569 BOE/day, slightly ahead of our full-year guidance of 91,000 BOE/day.
- Average December production volumes were 85,400 BOE/day, 3% below our exit target as a result of unexpected downtime related to cold weather, unplanned turn-arounds at two non-operated facilities and delays in capital spending. After adjusting for weather and unplanned downtime, our exit rate would have been 87,200 BOE/day.
- Capital spending was $299 million, approximately 5% less than our guidance of $315 million excluding the carry capital associated with our Marcellus shale gas assets.
- A total of 313 net wells were drilled with a 99% success rate.
- Operating costs were $9.79/BOE, 4% lower than our guidance of $10.20/BOE.
- General and Administrative ("G&A") expenses were impacted by one-time costs in 2009 and averaged $2.64/BOE, approximately 8% higher than our guidance of $2.45/BOE. After adjusting for one-time costs, our G&A costs were $2.31/BOE, approximately 6% better than guidance.
- We sold approximately 4.5 net sections of low working interest, non-core property interests in southeast Saskatchewan for approximately $100 million as part of our strategy to focus our activities on a fewer number of high impact resource plays.
- We are well positioned to begin marketing and potentially divest up to 14,000 BOE/day of non-core assets to further focus our asset base.
- Our reserve volumes were impacted by negative revisions associated with changes in evaluation methodology, the removal of undeveloped drilling locations due to changes to our capital spending plans, lower natural gas prices along with reservoir performance.
- Total proved plus probable reserves declined to 345 million BOE, a decrease of approximately 20% over year-end 2008, primarily in our shallow natural gas assets.
- Our 2009 acquisition activities were focused primarily on acquiring land positions in key resource plays that provide growth prospects for the future. While these acquisitions did not add any significant proved plus probable reserves in the current year, they did add significant contingent resources and growth potential for future years.
- The negative reserve revisions more than offset the reserves added through our capital spending and acquisition activities. As a result, our Finding & Development ("F&D") and Finding, Development & Acquisition ("FD&A") costs and recycle ratios were negative in 2009 and consequently incalculable.
- Excluding revisions, our capital program added 13.6 million BOE of new reserves resulting in F&D costs of approximately $20/BOE with a 1.3x recycle ratio.
SELECTED FINANCIAL AND OPERATING HIGHLIGHTS
SELECTED FINANCIAL RESULTS Three months ended Twelve months ended
December 31, December 31,
(in Canadian dollars) 2009 2008 2009 2008
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Financial (000's)
Cash Flow from
Operating Activities $188,579 $258,536 $775,786 $1,262,782
Cash Distributions to
Unitholders(1) 95,550 167,017 368,201 786,138
Excess of Cash Flow
Over Cash Distributions 93,029 91,519 407,585 476,644
Net Income 2,718 189,495 89,117 888,892
Debt Outstanding -
net of cash 485,349 657,421 485,349 657,421
Capital Spending 118,889 200,254 299,111 577,739
Acquisitions 49,100 1,443 271,977 1,772,826
Divestments 102,070 162 104,325 504,859
Actual Cash Distributions
to Unitholders per
Trust Unit $0.54 $1.23 $2.23 $5.06
Financial per Weighted
Average Trust Unit(2)
Cash Flow from
Operating Activities $1.07 $1.56 $4.58 $7.86
Cash Distributions(1) 0.54 1.01 2.17 4.89
Excess of Cash Flow
Over Cash Distributions 0.53 0.55 2.41 2.97
Net Income 0.02 1.15 0.53 5.54
Payout Ratio(3) 51% 65% 47% 62%
Adjusted Payout Ratio(3) 114% 144% 87% 109%
Selected Financial Results
per BOE(4)
Oil & Gas Sales(5) $41.75 $46.54 $36.89 $65.79
Royalties (6.56) (8.61) (6.21) (12.27)
Commodity Derivative
Instruments 3.34 3.54 4.66 (2.94)
Operating Costs (9.27) (9.46) (9.71) (9.51)
General and
Administrative Expenses (3.30) (1.71) (2.44) (1.68)
Interest and Other
Expenses (0.72) (2.73) (0.34) (1.59)
Taxes 0.66 0.92 (0.01) (0.65)
Asset retirement
obligations settled (0.63) (0.53) (0.41) (0.52)
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Cash Flow from Operating
Activities before changes
in non-cash working
capital $25.26 $27.96 $22.43 $36.63
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Weighted Average Number
of Trust Units
Outstanding(2) 176,872 165,373 169,280 160,589
Debt to Trailing 12 Month
Cash Flow Ratio(6) 0.6x 0.5x 0.6x 0.5x
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SELECTED OPERATING RESULTS Three months ended Twelve months ended
December 31, December 31,
2009 2008 2009 2008
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Average Daily Production
Natural gas (Mcf/day) 305,691 346,439 326,570 338,869
Crude oil (bbls/day) 31,590 35,434 32,984 34,581
NGLs (bbls/day) 4,238 4,529 4,157 4,627
Total (BOE/day) 86,777 97,702 91,569 95,687
% Natural gas 59% 59% 59% 59%
Average Selling Price(5)
Natural gas (per Mcf) $4.06 $6.92 $3.91 $8.17
Crude oil (per bbl) 67.90 55.16 58.54 91.31
NGLs (per bbl) 56.96 43.55 41.54 68.93
CDN$/US$ exchange rate 0.95 0.82 0.88 0.94
Net Wells drilled 156 174 313 643
Success Rate(7) 99% 99% 99% 99%
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(1) Calculated based on distributions paid or payable.
(2) Weighted average trust units outstanding for the period, includes the
equivalent exchangeable limited partnership units.
(3) Payout ratio is calculated as cash distributions to unitholders
divided by cash flow from operating activities. Adjusted payout ratio
is calculated as the sum of cash distributions to unitholders plus
development capital and office expenditures divided by cash flow from
operating activities. See "Non-GAAP Measures" below.
(4) Non-cash amounts have been excluded.
(5) Net of oil and gas transportation costs, but before the effects of
commodity derivative instruments.
(6) Including the cash flow of Focus Energy Trust for 2008.
(7) Based on wells drilled, cased and tied in, excluding any wells
pending completion/tie-in.
Trust Unit Trading Summary
For the twelve months ended TSX - ERF.un U.S.* - ERF
December 31, 2009 (CDN$) (US$)
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High $28.00 $25.13
Low $16.75 $12.85
Close $24.21 $23.06
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* U.S. Composite Exchange Data including NYSE.
2009 Cash Distributions Per Trust Unit
(Based on Month of Payment) CDN$ US$
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First Quarter Total $0.61 $0.49
Second Quarter Total $0.54 $0.46
Third Quarter Total $0.54 $0.49
Fourth Quarter Total $0.54 $0.51
Total Year-to-Date $2.23 $1.95
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FUTURE GROWTH POTENTIAL
A key element of our business strategy in 2009 was to add more early-stage resource plays to our portfolio through both acquisitions and organic development. We believe the addition of these types of plays will help to improve the profitability of our business and position us to show meaningful growth in both reserves and production. Enerplus invested over $550 million to build our inventory of early stage resource plays in 2009 and begin assessment of these lands. In total, we acquired approximately 226,000 net acres of prospective land the majority of which was in three key growth areas.
In 2009, Enerplus made a strategic investment in the Marcellus shale gas fairway, acquiring approximately 126,000 net acres of land and gaining entry into one of the most economic and prolific shale gas resource plays in North America. This investment provides us with a significant new growth area containing over 2.1 Tcfe of best estimate contingent resources net to Enerplus. To put this acquisition in context, this could more than triple our proved plus probable natural gas reserves. Current plans are expected to grow production to over 100 million cubic feet ("MMcf") per day of natural gas from the Marcellus net to Enerplus over the next four years with production increasing from 2.1 MMcfe/day at the end of 2009 to over 18 MMcfe/day by year end 2010. With close proximity to the largest consuming region of natural gas in North America, the Marcellus play has one of the highest netbacks, best breakeven costs and superior economic returns compared to other natural gas developments.
We also added to our Bakken/tight oil portfolio and have now accumulated in the order of 100 net sections of undeveloped Bakken land in both Canada and the U.S. In May, we purchased a 25% working interest in 44 gross sections of prospective Bakken land in southeast Saskatchewan for $25 million and followed with the purchase of a 50% working interest in approximately 34 gross sections of prospective Bakken land in North Dakota for US$27 million in October. Through our upcoming capital program this year, we expect production from our Bakken/tight oil assets to increase by approximately 40% in 2010.
A significant portion of our assessment capital was directed toward our tight gas resource play where we are pursuing a number of plays such as the Montney, Nordegg and Mannville formations in the Deep Basin region in western Canada where we now have approximately 50 net sections of undeveloped land. This capital was directed at acquiring Crown land and seismic data and drilling assessment wells.
We have also added to our internal technical skill sets to improve our understanding and exploit our existing waterflood assets and other oil properties through the use of horizontal drilling, multi-stage fracture stimulation and enhanced oil recovery ("EOR") techniques. These mature properties have been on production for many years but we believe they still have a tremendous amount of recoverable oil. Through the application of various techniques we believe we can improve the ultimate recovery from many of these fields adding incremental reserves and production.
OPERATIONS
Production
Daily production in 2009 averaged 91,569 BOE/day, slightly ahead of our guidance of 91,000 BOE/day. As expected, our average daily volumes were lower than 2008 by approximately 4% as our reduced capital spending program did not completely replace reservoir declines during the year.
We exited 2009 with production of approximately 85,400 BOE/day, roughly 3% lower than our guidance of 88,000 BOE/day. Approximately 1,300 BOE/day was off line due to freeze ups and another 500 BOE/day was shut in due to unplanned downtime at two non-operated facilities impacting our Pembina Brazeau and Tommy Lakes properties. Production shut-ins due to weather have since been brought back on stream. After adjusting for weather and unplanned downtime, our exit rate would have been approximately 87,200 BOE/day.
2009 Production and Capital Spending
2009
2009 Incremental
Average 2009 Initial
Annual Capital Production
Play Type Production ($ millions) (BOE/day)
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Bakken/Tight Oil (BOE/day) 10,075 49 1,782
Crude Oil Waterfloods (BOE/day) 16,329 37 1,025
Conventional Oil (bbls/day) 10,777 16 1,553
Oil Sands (bbls/day) - 15 -
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Total Crude Oil (BOE/day) 37,181 $117 4,360
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Shallow Gas (Mcfe/day) 140,008 61 17,094
Tight Gas (Mcfe/day) 98,452 95 24,105
Marcellus Shale Gas (Mcfe/day) 514 12 -
Conventional Gas (Mcfe/day) 87,352 14 1,748
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Total Gas (Mcfe/day) 326,326 $182 42,947
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Company Total (BOE/day) 91,569 $299* 11,518
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* Net of $22 million in Alberta drilling royalty credits
Capital Activities
We invested approximately $299 million through our capital program in 2009, net of $22 million in Alberta drilling royalty credits ("DRC"). This was $16 million below our guidance of $315 million and approximately 45% less than our capital program in 2008. Spending was lower than anticipated in 2009 due primarily to delays caused by cold weather in December and lower spending associated with our Marcellus activities.
Mature cash generating properties continue to be a core part of our business. Over 60% of our capital spending in 2009 was invested in mature properties in our waterflood, shallow gas, tight gas and Bakken/tight oil resource plays. Our investment in growth projects grew in 2009 to roughly $82 million, up from $55 million in 2008. This spending helped to advance projects in our Bakken/tight oil, tight gas, oil sands and Marcellus Shale gas plays. We invested approximately $30 million on undeveloped land and $30 million in drilling seven net assessment wells in various plays. In total, we drilled 313 net wells in 2009 including 138 net wells (primarily shallow gas) utilizing the DRC program.
2009 Drilling Activity (net wells)
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Wells
Pending Dry & Drill-
Hori- Verti- Comple- Wells Aband- ing
zontal cal Total tion/ On- oned Success
Play Type Wells Wells Wells tie-in stream Wells Rate%
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Bakken/
Tight Oil 6.2 - 6.2 4.7 1.5 - 100%
Crude Oil
Waterfloods 7.0 4.0 11.0 7.8 3.2 - 100%
Conventional
Oil 6.7 - 6.7 0.1 6.6 - 100%
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Total Oil 19.9 4.0 23.9 12.6 11.3 - 100%
Marcellus
Shale Gas 2.3 0.2 2.5 2.5 - - 100%
Shallow Gas - 258.9 258.9 98.0 160.9 - 100%
Tight Gas 1.0 13.1 14.1 3.1 11.0 0.1 99%
Conventional
Gas 0.1 13.5 13.6 12.5 1.1 - 100%
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Total Gas 3.4 285.7 289.1 116.1 173.0 0.1 99%
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Company
Total 23.3 289.7 313.0 128.7 184.3 0.1 100%
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Pending/tie-in and on-stream wells measured as at December 31, 2009.
Success rate based upon wells drilled, cased and tied-in excluding wells
pending completion/tie-in.
Resource Play Activity
Bakken/Tight Oil
Our Bakken/tight oil capital spending was associated with the on-going development of our Sleeping Giant property in Montana and assessment drilling in our new areas.
In late 2008, we suspended our drilling program at Sleeping Giant due to the significant drop in crude oil prices but continued with our refrac program given the attractive economic returns. As oil prices stabilized in the latter half of the year, we resumed our drilling program and drilled two wells by year end along with a total of 19 refracs for total spending of approximately $25 million. We also spent another $14 million primarily in assessment work in our new areas.
In 2010, we have allocated $117 million in development capital to our Bakken/Tight Oil plays with approximately $58 million to be invested in development activities at Sleeping Giant with another $54 million on assessment activities in our new areas. We plan to drill 31 net wells across the entire Bakken portfolio and expect to refrac 11 net wells at Sleeping Giant. We also plan to continue testing multi-well, simultaneous fracturing and increasing the number of fracture stages per well at Sleeping Giant with up to six simultaneous fracs and up to 12 frac stages. We also plan to test a number of higher stage fracture stimulation projects in our new areas.
Marcellus Shale Gas
Enerplus entered the Marcellus shale gas play in September 2009 and since then we have invested a total of $29 million - $12 million representing Enerplus' share of capital, $12 million in carry capital which covers 50% of our partner's capital, and $5 million in the purchase of additional acreage and seismic data. At year end, Enerplus held an average 23.6% working interest in over 126,000 net acres of Marcellus prospect land.
Our capital expenditures to the end of 2009 were $11 million lower than anticipated due to fewer than expected wells drilled and completed and a lower working interest on those wells that were drilled and completed. We had planned to drill 15 wells and complete 7 wells by year end, however only 12 wells were drilled and 5 wells were completed due to scheduling and availability of services at the end of the year. Completion times have been averaging 12 to 14 days but some completions are being deferred until gathering infrastructure nears completion in key areas. We anticipate substantial progress in the installation of gathering infrastructure in Lycoming County, Pennsylvania and Marshall County, West Virginia by early in the second quarter of 2010. Our partner, Chief Oil & Gas, is focused on securing the required services to advance the completion programs. However, continued increases in industry activity could put additional pressure on costs and the timing of our programs going forward.
At year end we had a total of 43 wells drilled with 11 wells on production, 22 wells waiting to be completed and 10 wells awaiting tie-in. Daily production averaged 2.1 MMcfe/day net to Enerplus during the month of December. We currently have four rigs working in the play with a fifth rig expected early in the second quarter of 2010. We plan to drill and complete 12 gross wells and tie-in 8 additional wells during the first quarter and expect to catch up on our completion activities during the year as infrastructure is put in place.
Although only a limited number of wells have been brought on production since our acquisition, we are seeing encouraging tests which support higher production profiles than used in our original assumptions. Total well costs are currently $4.6 million, in line with our budget however we have experienced additional cost reductions from the use of pad drilling. Given results to date, we continue to acquire new leases in select prospect areas. Since the acquisition we have added 10,000 net acres to our position and have swapped acreage to consolidate our position. We continue to pursue other opportunities to increase and consolidate our acreage and add an operated position.
As previously announced, our independent reserve engineer's best estimate of natural gas contingent resources in our Marcellus acreage increased 0.7 Tcfe from our original internal estimate of 1.4 Tcfe to approximately 2.1 Tcfe at December 31, 2009. This increase is based on area results which support higher type curve recoveries and higher well density and overall recoveries per section. We continue to assume a land utilization rate of 55% as per our original estimate and that the average type well recoveries may increase from an average of 3.2 billion cubic feet ("Bcf") per well to approximately 3.4 Bcf per well with the higher prospective areas showing approximately 5 Bcf per well. We also expect recoveries to increase to approximately 30% from 12 to 20% with an average well density of 4 to 8 wells per section versus 4 to 6 wells per section in the original analysis. The Marcellus play is still in its early days, but our results and industry results are supporting higher expectations. In addition, we continue to see upside in the amount of land that could be developed over time as delineation results continue to come in.
We booked 25 Bcfe of natural gas proved plus probable reserves at year end, an increase of over 200% from the proved plus probable reserves acquired effective July 2009.
Tight Gas
Capital spending in our tight gas properties increased to $94 million in 2009. At Tommy Lakes, we completed a 14-well program which was started in late 2008 spending approximately $30 million. Approximately $40 million was invested to acquire 29 net sections of prospective land, seismic and assessment drilling activities in the Deep Basin region of Alberta and British Columbia targeting the Montney, Nordegg and Manville formations.
We expect to reduce spending in 2010 to approximately $56 million as we are not planning a development program at Tommy Lakes given the current outlook for natural gas prices. We have plans to drill a number of assessment wells along with some seismic work on our newly acquired lands targeting formations with potential for multi-frac horizontal well drilling.
Crude Oil Waterfloods
Capital spending within our waterflood portfolio was largely focused at Freda Lake, Virden, Giltedge, Pembina and Medicine Hat. Approximately $14 million was spent on drilling 11 net wells, including 7 horizontal wells. Maintenance projects including facility and pipeline integrity upgrades were also a significant part of our activities. In total, we invested $37 million in this resource play and essentially maintained production year-over-year.
Given the improved outlook for crude oil prices relative to gas prices, we expect to significantly increase our capital spending in 2010 on our waterflood assets to approximately $96 million, net of Alberta government DRCs of $10 million. We plan to drill 38 net wells to optimize recovery at our Medicine Hat, Giltedge, Freda Lake, Cadogan and Virden properties. Activities will also be focused on advancing our work on enhanced oil recovery pilots at our most prospective waterflood fields. We plan to initiate at least one field pilot to test the use of polymers to help recover more of the oil.
Shallow Natural Gas
We invested $61 million in our shallow gas assets in 2009, net of DRCs, with most of our spending at Shackleton in Saskatchewan and Bantry, Verger and Hanna Garden in Alberta. Due to weakening gas prices in the second quarter we suspended our summer drilling program at Shackleton, preserving our drilling inventory pending higher sustainable natural gas prices, and with the implementation of the Alberta royalty drilling incentive program, we shifted our shallow gas drilling to Alberta. In total, we drilled 259 net shallow gas wells including 120 net wells that attracted drilling royalty credits of approximately $17 million.
With the current natural gas price outlook, our projected shallow gas spending in 2010 has been reduced to approximately $40 million net of DRCs. We plan to drill approximately 156 net wells with a focus on infill drilling at Shackleton, Hanna Garden, Bantry and Verger where our most attractive opportunities exist and to take advantage of government drilling incentives of approximately $15 million. We anticipate that 60% of our total wells in 2010 will be shallow gas wells targeting the Milk River, Second White Specks and Medicine Hat formations.
Other Conventional Oil & Gas
Approximately 28% of our production is comprised of conventional oil and gas properties throughout western Canada. These properties typically have a smaller working interest and offer limited growth potential. Given our desire to concentrate our capital spending and efforts in our core resource play areas, development capital was reduced by approximately 65% in 2009 to $30 million. A significant number of these properties are targeted for inclusion in our divestment program.
Oil Sands
We invested $15 million in our oil sands portfolio in 2009, the majority of which was spent at Kirby to complete our seismic program and the work associated with obtaining regulatory approval. We continue to expect approval of our application for a 10,000 BOE/day in-situ oil sands project in early 2010. As a result of our seismic program, our independent reserve evaluators increased the best estimate of contingent resources from 414 million barrels of bitumen at year-end 2008 to 497 million barrels of bitumen at year-end 2009, reflecting a 20% increase year-over-year and a 104% increase since acquiring the lease in 2007. While we believe that the geologic characteristics, quality and potential of the Kirby lease are very attractive, the anticipated return on investment when combined with the timeline to positive cash flow is currently not compelling relative to the opportunities in our other resource plays. We are continuing to evaluate our options to maximize the value of this lease and expect only minimal spending in 2010.
For additional information relating to contingent resource estimates, see "Information Regarding Disclosure in this News Release and Oil and Gas Reserves, Resources and Operational Information" at the conclusion of this news release.
RESERVES
As indicated in our 2010 guidance released in December 2009, Enerplus experienced negative reserve revisions in 2009 primarily associated with our shallow natural gas assets. These changes negatively impacted our finding and development ("F&D") costs as they more than offset the positive additions associated with our capital program. With our acquisition activity primarily focused on early stage resource plays which have contingent resources but little proved plus probable reserves at this time, our finding, development & acquisition ("FD&A") costs and recycle ratios were also impacted. Both our F&D and FD&A costs were negative in 2009 and consequently incalculable.
The negative reserve revisions were associated with both our proved and probable reserves and resulted from the removal of undeveloped drilling locations, changes in evaluation methodology, reservoir performance and the decline in natural gas prices. In total, 0.37 Tcf of natural gas reserves representing 25% of our total natural gas bookings and 6 million BOE of crude oil and natural gas liquids reserves representing 3% of our liquids reserves were impacted representing approximately 16% of our total proved plus probable reserves.
Approximately 42% of the revisions were attributable to the removal of approximately 1,400 undeveloped drilling locations and a reduction in the reserves attributable to the remaining undeveloped drilling locations. The majority of these revisions were in our shallow gas properties. In total, 0.15 Tcfe of reserves associated with our natural gas properties and 3 MMBOE of reserves associated with our crude oil properties were impacted. After revisions, Enerplus now has approximately 1,000 future drilling locations in our reserve report with close to 700 of those being shallow gas locations. Although we have not booked many Marcellus or Canadian tight gas locations, the significant reduction in shallow gas locations was driven by the belief that we will direct a majority of our future spending toward these higher impact resource plays. Our oil inventory of undeveloped locations remains at approximately 200 locations with only limited locations related to our Bakken/tight oil growth areas at this time.
Methodology changes used by our new third party reserve evaluators, McDaniel & Associates Consultants Ltd. ("McDaniel"), accounted for approximately 27% of the reduction or 0.10 Tcfe from natural gas properties (primarily shallow gas) and 1.6 MMBOE from crude oil properties. The methodology changes included a different assessment of final economic producing rates and decline factors than previously used. Maintenance capital requirements were also increased to include 10 additional years (from 11 to 20 years) and an increased amount per year, resulting in approximately $140 million ($70 million present value discounted at 10%) of additional future development capital.
Performance issues accounted for 28% of the reduction or 0.10 Tcfe associated primarily with our shallow natural gas and 2.2 MMBOE associated with our crude oil properties. Lower than anticipated infill well performance and increased interference between wells has steepened the decline of our shallow gas properties. These changes did not have a material impact on our current year production as we delivered our expected production targets in 2009.
Reserves totaled 344.9 MMBOE at December 31, 2009, 50% weighted to crude oil and natural gas liquids. Our proved plus probable reserve life index decreased to approximately 11 years, down from 12 years at the end of 2008. Excluding revisions, our capital program delivered 13.6 MMBOE of new proved plus probable reserves resulting in F&D costs of approximately $20/BOE with a 1.3x recycle ratio.
We expect our reserve additions to improve going forward given the changes that we made in 2009 to our asset portfolio and as our growth plays begin to deliver results.
Reserves by Resource Play
Proved P+P
plus Reserve
Probable Probable Life Index
Play Types Proved Reserves Reserves (years)
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Bakken/Tight Oil (MMBOE) 32.0 9.7 41.8 10.9
Crude Oil Waterfloods (MMBOE) 74.4 21.4 95.9 16.1
Other Conventional Oil (MMBOE) 31.5 10.6 42.2 10.3
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Total Oil (MMBOE) 138.0 41.8 179.8 13.0
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Marcellus Shale Gas (Bcfe) 8.1 16.8 24.9 17.6
Tight Gas (Bcfe) 252.8 102.8 355.6 11.1
Shallow Gas (Bcfe) 272.7 95.1 367.8 8.2
Other Conventional Gas (Bcfe) 182.5 59.3 241.9 8.9
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Total Gas (Bcfe) 716.2 274.0 990.2 9.4
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Total Company (MMBOE) 257.4 87.5 344.9 10.9
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Reserve Reporting and Determination Methodologies
All of our reserves, including our U.S. reserves, were evaluated using Canadian National Instrument 51-101 ("NI 51-101") standards. In August 2009, Enerplus contracted McDaniel to replace Sproule Associates Ltd. as our independent reserve evaluator for all our Canadian conventional assets. GLJ Petroleum Consultants Ltd. ("GLJ") continues to evaluate our oil sands assets, Netherland Sewell & Associates Inc. ("NSAI") continues to evaluate our western U.S. assets and Haas Petroleum Engineering Services Inc. ("Haas") have been retained to evaluate our Marcellus shale gas assets.
McDaniel has evaluated 90% of the total proved plus probable value (discounted at 10%) of our Canadian conventional year-end reserves and reviewed the remaining 10% of the reserves which were internally evaluated by Enerplus. NSAI evaluated 100% of the reserves associated with our western U.S. assets and Haas evaluated 100% of our Marcellus shale gas assets in the U.S. In addition, GLJ evaluated the resources in our Kirby oil sands project as described above. All reserve engineers utilized McDaniel's forecast price and cost assumptions as of December 31, 2009.
Reserves Summary
The following table sets out our company interest volumes at December 31, 2009 by production type and reserve category under a forecast price scenario. Under different price scenarios, these reserves could vary as a change in price can affect the economic limit and reserves associated with a property.
2009 Reserves Summary - Company Interest Volumes (Forecast Prices)
-------------------------------------------------------------------------
Light & Natural
Medium Heavy Total Gas Natural Shale
Reserves Oil Oil Oil Liquids Gas Gas Total
Category (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MBOE)
-------------------------------------------------------------------------
Proved
Developed
Producing
Canada 57,742 29,613 87,355 9,879 624,588 - 201,332
United
States 21,062 - 21,062 76 39,554 2,914 28,216
-------------------------------------------------------------------------
Total Proved
Developed
Producing 78,804 29,613 108,417 9,955 664,142 2,914 229,548
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Proved
Developed
Non-Producing
Canada 539 438 977 124 13,444 - 3,341
United
States 1,276 - 1,276 4 1,770 626 1,679
-------------------------------------------------------------------------
Total Proved
Developed
Non-
Producing 1,815 438 2,253 128 15,214 626 5,020
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Proved
Undeveloped
Canada 2,772 4,380 7,152 630 58,553 - 17,541
United
States 3,114 - 3,114 40 8,125 4,587 5,273
-------------------------------------------------------------------------
Total Proved
Undeveloped 5,886 4,380 10,266 670 66,678 4,587 22,814
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Proved -
Canada 61,053 34,431 95,484 10,633 696,585 - 222,214
United
States 25,452 - 25,452 120 49,449 8,127 35,168
-------------------------------------------------------------------------
Total Proved 86,505 34,431 120,936 10,753 746,034 8,127 257,382
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Probable
Canada 16,776 12,347 29,123 3,718 250,061 - 74,518
United
States 7,287 - 7,287 36 17,085 16,763 12,964
-------------------------------------------------------------------------
Total
Probable 24,063 12,347 36,410 3,754 267,146 16,763 87,482
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Proved
Plus
Probable
Canada 77,829 46,778 124,607 14,351 946,646 - 296,732
United
States 32,739 - 32,739 156 66,534 24,890 48,132
-------------------------------------------------------------------------
Total Proved
Plus
Probable 110,568 46,778 157,346 14,507 1,013,180 24,890 344,864
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Reserve Reconciliation
The following tables outline the changes in Enerplus' proved, probable and proved plus probable reserves, on a company interest basis, from December 31, 2008 to December 31, 2009.
Proved Reserves - Company Interest Volumes (Forecast Prices)
Light & Natural
Medium Heavy Total Gas Natural Shale
Oil Oil Oil Liquids Gas Gas Total
CANADA (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MBOE)
-------------------------------------------------------------------------
Proved
Reserves
at Dec. 31,
2008 68,425 33,139 101,564 12,939 1,025,866 - 285,481
-------------------------------------------------------------------------
Acquisitions 413 - 413 5 276 - 465
Divestments (1,090) - (1,090) (42) (755) - (1,257)
Discoveries - - - - 358 - 61
Extensions &
Improved
Recovery 921 947 1,868 102 5,941 - 2,959
Economic
Factors 197 (18) 179 (73) (10,072) - (1,572)
Technical
Revisions (2,135) 3,737 1,602 (781) (210,840) - (34,322)
Production (5,678) (3,374) (9,052) (1,517) (114,189) - (29,601)
-------------------------------------------------------------------------
Proved
Reserves
at Dec. 31,
2009 61,053 34,431 95,484 10,633 696,585 - 222,214
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Light & Natural
Medium Heavy Total Gas Natural Shale
UNITED Oil Oil Oil Liquids Gas Gas Total
STATES (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MBOE)
-------------------------------------------------------------------------
Proved
Reserves
at Dec. 31,
2008 26,128 - 26,128 113 40,668 - 33,019
-------------------------------------------------------------------------
Acquisitions - - - - - 5,000 833
Divestments - - - - - - -
Discoveries 434 - 434 - 591 - 532
Extensions &
Improved
Recovery 2,378 - 2,378 4 2,949 3,313 3,425
Economic
Factors - - - - - - -
Technical
Revisions (514) - (514) 16 10,063 2 1,181
Production (2,974) - (2,974) (13) (4,822) (188) (3,822)
-------------------------------------------------------------------------
Proved
Reserves
at Dec. 31,
2009 25,452 - 25,452 120 49,449 8,127 35,168
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Light & Natural
Medium Heavy Total Gas Natural Shale
TOTAL Oil Oil Oil Liquids Gas Gas Total
ENERPLUS (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MBOE)
-------------------------------------------------------------------------
Proved
Reserves
at Dec. 31,
2008 94,553 33,139 127,692 13,052 1,066,534 - 318,500
-------------------------------------------------------------------------
Acquisitions 413 - 413 5 275 5,000 1,298
Divestments (1,090) - (1,090) (42) (755) - (1,257)
Discoveries 434 - 434 - 949 - 593
Extensions &
Improved
Recovery 3,299 947 4,246 106 8,890 3,313 6,384
Economic
Factors 197 (18) 179 (73) (10,072) - (1,572)
Technical
Revisions (2,649) 3,737 1,088 (765) (200,777) 2 (33,141)
Production (8,652) (3,374) (12,026) (1,530) (119,011) (188) (33,423)
-------------------------------------------------------------------------
Proved
Reserves
at Dec. 31,
2009 86,505 34,431 120,936 10,753 746,034 8,127 257,382
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Probable Reserves - Company Interest Volumes (Forecast Prices)
Light & Natural
Medium Heavy Total Gas Natural Shale
Oil Oil Oil Liquids Gas Gas Total
CANADA (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MBOE)
-------------------------------------------------------------------------
Probable
Reserves at
Dec. 31,
2008 19,274 12,790 32,064 4,714 397,651 - 103,053
-------------------------------------------------------------------------
Acquisitions 170 - 170 3 171 - 201
Divestments (279) - (279) (11) (130) - (312)
Discoveries - - - - 89 - 13
Extensions &
Improved
Recovery 269 831 1,100 87 7,918 - 2,508
Economic
Factors (2) 3 1 (19) (4,395) - (751)
Technical
Revisions (2,656) (1,277) (3,933) (1,056) (151,243) - (30,194)
Production - - - - - - -
-------------------------------------------------------------------------
Probable
Reserves at
Dec. 31,
2009 16,776 12,347 29,123 3,718 250,061 - 74,518
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Light & Natural
Medium Heavy Total Gas Natural Shale
UNITED Oil Oil Oil Liquids Gas Gas Total
STATES (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MBOE)
-------------------------------------------------------------------------
Probable
Reserves at
Dec. 31,
2008 6,867 - 6,867 51 23,483 - 10,832
-------------------------------------------------------------------------
Acquisitions - - - - - 2,980 497
Divestments - - - - - - -
Discoveries 657 - 657 - 970 - 819
Extensions &
Improved
Recovery 731 - 731 3 1,289 13,773 3,245
Economic
Factors - - - - - - -
Technical
Revisions (968) - (968) (18) (8,657) 10 (2,429)
Production - - - - - - -
-------------------------------------------------------------------------
Probable
Reserves at
Dec. 31,
2009 7,287 - 7,287 36 17,085 16,763 12,964
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Light & Natural
Medium Heavy Total Gas Natural Shale
TOTAL Oil Oil Oil Liquids Gas Gas Total
ENERPLUS (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MBOE)
-------------------------------------------------------------------------
Probable
Reserves at
Dec. 31,
2008 26,141 12,790 38,931 4,765 421,134 - 113,885
-------------------------------------------------------------------------
Acquisitions 170 - 170 3 171 2,980 698
Divestments (279) - (279) (11) (130) - (312)
Discoveries 657 - 657 - 1,059 - 832
Extensions &
Improved
Recovery 1,000 831 1,831 90 9,207 13,773 5,753
Economic
Factors (2) 3 1 (19) (4,395) - (751)
Technical
Revisions (3,624) (1,277) (4,901) (1,074) (159,900) 10 (32,623)
Production - - - - - - -
-------------------------------------------------------------------------
Probable
Reserves at
Dec. 31,
2009 24,063 12,347 36,410 3,754 267,146 16,763 87,482
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Proved Plus Probable Reserves - Company Interest Volumes (Forecast Prices)
Light & Natural
Medium Heavy Total Gas Natural Shale
Oil Oil Oil Liquids Gas Gas Total
CANADA (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MBOE)
-------------------------------------------------------------------------
Proved Plus
Probable
Reserves at
Dec. 31,
2008 87,699 45,929 133,628 17,653 1,423,517 - 388,534
-------------------------------------------------------------------------
Acquisitions 583 - 583 8 447 - 666
Divestments (1,369) - (1,369) (53) (885) - (1,569)
Discoveries - - - - 447 - 74
Extensions &
Improved
Recovery 1,190 1,778 2,968 189 13,859 - 5,467
Economic
Factors 195 (15) 180 (92) (14,467) - (2,323)
Technical
Revisions (4,791) 2,460 (2,331) (1,837) (362,083) - (64,516)
Production (5,678) (3,374) (9,052) (1,517) (114,189) - (29,601)
-------------------------------------------------------------------------
Proved Plus
Probable
Reserves at
Dec. 31,
2009 77,829 46,778 124,607 14,351 946,646 - 296,732
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Light & Natural
Medium Heavy Total Gas Natural Shale
UNITED Oil Oil Oil Liquids Gas Gas Total
STATES (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MBOE)
-------------------------------------------------------------------------
Proved Plus
Probable
Reserves at
Dec. 31,
2008 32,995 - 32,995 164 64,151 - 43,851
-------------------------------------------------------------------------
Acquisitions - - - - - 7,980 1,330
Divestments - - - - - - -
Discoveries 1,091 - 1,091 - 1,561 - 1,351
Extensions &
Improved
Recovery 3,109 - 3,109 7 4,238 17,086 6,670
Economic
Factors - - - - - - -
Technical
Revisions (1,482) - (1,482) (2) 1,406 12 (1,248)
Production (2,974) - (2,974) (13) (4,822) (188) (3,822)
-------------------------------------------------------------------------
Proved Plus
Probable
Reserves at
Dec. 31,
2009 32,739 - 32,739 156 66,534 24,890 48,132
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Light & Natural
Medium Heavy Total Gas Natural Shale
TOTAL Oil Oil Oil Liquids Gas Gas Total
ENERPLUS (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MBOE)
-------------------------------------------------------------------------
Proved Plus
Probable
Reserves at
Dec. 31,
2008 120,694 45,929 166,623 17,817 1,487,668 - 432,385
-------------------------------------------------------------------------
Acquisitions 583 - 583 8 447 7,980 1,996
Divestments (1,369) - (1,369) (53) (885) - (1,569)
Discoveries 1,091 - 1,091 - 2,008 - 1,425
Extensions &
Improved
Recovery 4,299 1,778 6,077 196 18,097 17,086 12,137
Economic
Factors 195 (15) 180 (92) (14,467) - (2,323)
Technical
Revisions (6,273) 2,460 (3,813) (1,839) (360,677) 12 (65,764)
Production (8,652) (3,374) (12,026) (1,530) (119,011) (188) (33,423)
-------------------------------------------------------------------------
Proved Plus
Probable
Reserves at
Dec. 31,
2009 110,568 46,778 157,346 14,507 1,013,180 24,890 344,864
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Present Value of Future Production Revenue
The following tables provide an estimate of the net present value of Enerplus' future production revenue before provision for interest and general and administrative expenses and after deduction of royalties and estimated future capital expenditures, both before and after income taxes. It should not be assumed that the present value of estimated future cash flows shown below is representative of the fair market value of the reserves.
The estimated net present value of all future net revenues at December 31, 2009 was based upon forecast crude oil and natural gas pricing assumptions prepared by McDaniel as of January 1, 2010. These prices were applied to the reserves evaluated by McDaniel, NSAI and Haas. The base reference prices and exchange rates used by McDaniel are detailed below:
McDaniel January 2010 Forecast Price Assumptions
-------------------------------------------------------------------------
Hardisty
WTI Light Crude Heavy Oil Natural Gas
Crude Oil(1) 12 degrees Henry Hub 30 day spot Exchange
Oil Edmonton API Gas Price @ AECO Rate
US$/bbl CDN$/bbl CDN$/bbl US$/MMBtu CDN$/MMBtu US$/CDN$
-------------------------------------------------------------------------
2010 80.00 83.20 68.10 6.05 6.05 0.95
2011 83.60 87.00 67.60 6.90 6.75 0.95
2012 87.40 91.00 68.00 7.30 7.15 0.95
2013 91.30 95.00 68.10 7.70 7.45 0.95
2014 95.30 99.20 71.10 8.15 7.80 0.95
There-
after (xx) (xx) (xx) (xx) (xx) 0.95
-------------------------------------------------------------------------
(1) Edmonton Light Sweet 40 degree API, 0.3% sulphur content crude
(xx) Escalation varies after 2014
Net Present Value
Net Present Value of Future Production Revenue - Forecast Prices and
Costs (Before Tax)
At December 31, 2009
-------------------------------------------------------------------------
Conventional Reserves
($ millions, discounted at) 0% 5% 10% 15%
-------------------------------------------------------------------------
Proved developed producing 8,053 5,477 4,205 3,446
Proved developed non-producing 182 137 108 89
Proved undeveloped 555 349 231 155
-------------------------------------------------------------------------
Total Proved 8,790 5,963 4,544 3,690
Probable 3,695 1,775 1,067 730
-------------------------------------------------------------------------
Total Proved Plus Probable
Reserves 12,485 7,738 5,611 4,420
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Present Value of Future Production Revenue - Forecast Prices and
Costs (After Tax)
At December 31, 2009
-------------------------------------------------------------------------
Conventional Reserves
($ millions, discounted at) 0% 5% 10% 15%
-------------------------------------------------------------------------
Proved developed producing 6,734 4,702 3,676 3,053
Proved developed non-producing 125 94 76 62
Proved undeveloped 348 209 129 80
-------------------------------------------------------------------------
Total Proved 7,207 5,005 3,881 3,195
Probable 2,645 1,273 758 516
-------------------------------------------------------------------------
Total Proved Plus Probable
Reserves 9,852 6,278 4,639 3,711
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Asset Value
Enerplus' estimated net asset value is measured with reference to the estimated net present value of all future net revenue from our reserves, before taxes, as estimated by our independent reserve engineers (McDaniel, NSAI and Haas) plus land values, adjusted for working capital and long-term debt at year-end. This calculation can vary significantly depending on the oil and natural gas price assumptions used by the independent reserve engineers. In addition, this calculation ignores "going concern" value and assumes only the reserves identified in the reserve reports with no further acquisitions or incremental development.
Forecast Prices and Costs at December 31, 2009
($ millions except trust unit
amounts, discounted at) 0% 5% 10% 15%
-------------------------------------------------------------------------
Total net present value of
proved plus probable
reserves (before tax) $12,485 $7,738 $5,611 $4,420
Undeveloped acreage (2009
Year End)(1)
Canada (856,640 Acres) 144 144 144 144
USA West (70,506 Acres) 31 31 31 31
USA Marcellus Shale
(125,162 Acres) 442 442 442 442
Asset retirement
obligations(2) (311) (206) (78) (47)
Long-term debt (net of
cash)(3) (485) (485) (485) (485)
Net Working Capital excluding
deferred financial assets
and credits, future income
taxes, and current portion
of long-term debt (142) (142) (142) (142)
Marcellus Carry Commitment (248) (248) (248) (248)
Other Equity Investments(4) 25 25 25 25
-------------------------------------------------------------------------
Net Asset Value of Assets
Excluding Oil Sands 11,941 7,299 5,300 4,140
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Asset Value per Trust Unit
- Excluding Oil Sands(5) $67.44 $41.22 $29.93 $23.38
-------------------------------------------------------------------------
Oil Sands
Kirby Oil Sands Lease(6) $261 $261 $261 $261
Laricina Equity Investment(7) 65 65 65 65
Undeveloped Oil Sands
acreage(8) 12 12 12 12
-------------------------------------------------------------------------
Net Asset Value of Oil Sands
Assets $338 $338 $338 $338
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Asset Value per Trust
Unit - Oil Sands $1.91 $1.91 $1.91 $1.91
-------------------------------------------------------------------------
Total Net Asset Value per
Trust Unit(5) $69.35 $43.13 $31.84 $25.29
-------------------------------------------------------------------------
(1) Undeveloped resource play acreage valued at cost, balance of
conventional acreage valued at $100/acre
(2) Asset retirement obligations ("ARO") do not equal the amount on the
balance sheet ($230.5 million) as the balance sheet amount uses a
6.4% discount rate and a portion of the ARO costs are already
reflected in the present value of reserves computed by the
independent engineers
(3) Long-term debt includes the current portion of long-term debt
(4) Other equity investment value based on carrying value
(5) Based on 177,061,000 Trust Units and equivalent Exchangeable
Partnership units outstanding as at December 31, 2009
(6) Kirby valuation represents $203.1 million purchase price plus capital
spending of $57.9 million since acquisition
(7) Laricina value based on the latest equity financing completed at $15
per share
(8) Undeveloped oil sands acreage valued at cost of land acquisitions and
development capital spent on those lands
2010 Production and Capital Spending Plans
We expect to invest approximately $425 million in our assets in 2010, net of $33 million in DRCs or carry capital commitments, representing a 35% increase over 2009 given the improvement in crude oil prices and economic conditions, the strength of our balance sheet and increased opportunities associated with early stage growth-oriented assets.
The increase in capital spending is primarily related to more oil project spending in Bakken oil and our waterflood properties. We are also reallocating a significant portion of our gas related spending to the Marcellus shale gas play although total gas spending year-over-year is down slightly. We anticipate that approximately $260 million of our 2010 budget will be spent on our Canadian assets and $165 million on our U.S. operations. We currently expect approximately 55% of our spending will be directed at oil opportunities with the remainder on natural gas opportunities. We expect this capital program will provide compelling economic returns at WTI prices of US$60/bbl, AECO natural gas prices of CDN$4.20/Mcf ($4.00/GJ) and NYMEX gas prices of US$4.50/Mcf.
Our capital spending plans include approximately $125 million on assessment activities including drilling, seismic and minor land purchases associated with existing growth properties. This is up significantly from $82 million in 2009 due to the greater number of early stage resource plays in our portfolio. Our guidance does not include any acquisition activity or large undeveloped land purchases as these are opportunistic and difficult to predict. With $1.4 billion of unutilized credit capacity, we plan to continue to pursue acquisition opportunities. We expect to spend approximately $64 million (US$61 million) in capital carry commitments associated with our Marcellus shale gas acquisition. This capital carry commitment is considered part of the original cost of the acquisition and is not included in our development capital spending guidance.
We will review our 2010 capital investment plans throughout the year in the context of prevailing economic conditions considering any potential acquisitions and divestments, and we will make adjustments as deemed necessary. We anticipate our spending will be evenly distributed throughout the year.
Projected 2010 Capital Expenditures
Spending* Number of net wells
Resource Play ($ millions) to be drilled
-------------------------------------------------------------------------
Bakken/Tight Oil $117 31
Crude Oil Waterfloods 96 38
Other Conventional Oil 18 6
-------------------------------------------------------------------------
Total Oil $231 75
Marcellus Shale Gas $80 11
Tight Gas 56 7
Shallow Gas 41 156
Other Conventional Gas 17 9
-------------------------------------------------------------------------
Total Gas $194 183
Company Total $425 258
-------------------------------------------------------------------------
-------------------------------------------------------------------------
% crude oil 55% 29%
* Capital spending total is net of the estimated recovery of
$33 million of Alberta drilling royalty credits; includes drilling,
facilities, maintenance and capitalized G&A
2010 Production Guidance
Based upon our capital spending plans for 2010, we expect to produce an average of approximately 37,000 bbls/day of crude oil and natural gas liquids and 296 MMcf/day of natural gas, totaling approximately 86,000 BOE/day. Crude oil and natural gas liquids production is expected to increase throughout 2010 and represent approximately 45% of our exit rate volumes versus 40% at the end of 2009. As the results of our capital program are realized, we expect our exit production rate will increase to approximately 88,000 BOE/day setting the stage for continued growth in 2011. The key growth areas are the Marcellus and Bakken/tight oil. Our tight gas spending is considerably lower given the limited investment in Tommy Lakes which makes up a meaningful component of this play today. Our production forecast does not reflect any acquisition or divestment activities in 2010.
We plan to divest various non-core properties in 2010 that do not fit our resource play focus. We have identified up to 14,000 BOE/day of non-core conventional oil and gas production in western Canada for marketing and potential sale. We anticipate these properties will be separated into multiple packages and, depending on the value we see in the marketplace for these assets, there is no guarantee that any or all of these properties will be sold in 2010. Therefore, we have not adjusted our 2010 production guidance for this divestment activity however we would expect to sell a portion of this non-core portfolio in 2010 and realize proceeds of at least $200 million which we would target for redeployment into new acquisitions.
2010 % change
2009 Average 2010 2010 Exit
Exit Rate Annual Exit Rate vs
Play Type Production Production Production 2009 Exit
-------------------------------------------------------------------------
Bakken/Tight Oil (BOE/day) 8,750 11,200 12,200 39%
Crude Oil Waterfloods
(BOE/day) 16,125 15,800 16,800 4%
Other Conventional Oil
(BOE/day) 10,150 9,500 9,300 -8%
-------------------------------------------------------------------------
Total Oil 35,025 36,500 38,300 9%
Marcellus Shale Gas
(Mcf/day) 2,100 10,800 18,400 776%
Tight Gas (Mcf/day) 91,500 85,200 86,500 -5%
Shallow Gas (Mcf/day) 131,100 121,800 117,000 -11%
Conventional Gas (Mcf/day) 77,550 79,200 76,200 -2%
-------------------------------------------------------------------------
Total Gas (Mcf/day) 302,250 297,000 298,200 -1%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Company Total (BOE/day) 85,400 86,000 88,000 3%
-------------------------------------------------------------------------
Corporate Conversion
We remain committed to having an income-orientation to our business model. Enerplus has a 25 year history as an income fund and we believe there continues to be investor demand to support a yield-oriented strategy. We recognize that in order to be competitive within the oil and gas industry, we must have a growth orientation to our business as well. We are positioning ourselves to offer investors both.
We expect to continue to distribute a significant portion of our cash flow to our unitholders once we are a corporation. We believe we will be able to utilize our tax pools to meet the new tax obligations, providing us shelter from cash taxes for two to three years beyond 2010. While our cash flows and the amount we distribute to unitholders will vary depending upon commodity prices, production volumes and costs, we do not expect to adjust our monthly cash distributions as a result of conversion to a corporation.
Subject to the approval of our corporate conversion plan by the Board of Directors, we expect to proceed with a Special Meeting of Unitholders in December of this year and ultimately convert to a corporation on or about January 1, 2011.
Enerplus is one of Canada's oldest and largest independent oil and gas producers with a portfolio of both early stage resource plays and mature cash generating properties. We are focused on creating value for our investors through the successful development of our properties and the disciplined management of our balance sheet. Through these activities, we strive to provide investors with a competitive return comprised of both growth and income.
INFORMATION REGARDING RESERVES, RESOURCES AND OPERATIONAL INFORMATION IN THIS NEWS RELEASE
All amounts in this news release are stated in Canadian dollars unless otherwise specified.
This news release also contains references to "BOE" (barrels of oil equivalent), "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 six thousand cubic feet of gas to one barrel of oil (6 Mcf: 1 bbl) when converting natural gas to BOEs, and one barrel of oil to six thousand cubic feet of gas (1 bbl: 6 Mcf) when converting oil to Mcfes, MMcfes, Bcfes and Tcfes. BOEs, Mcfes, MMcfes, Bcfes and Tcfes 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. "MBOE" and "MMBOE" mean "thousand barrels of oil equivalent" and "million barrels of oil equivalent", respectively.
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. Our oil and gas reserves statement for the year ended December 31, 2009, which will include complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, will be contained within our Annual Information Form for the year ended December 31, 2009 ("our AIF") which will be available on or about March 12, 2010 on our website at www.enerplus.com and on our SEDAR profile at www.sedar.com. Additionally, the Annual Information Form will form part of our Form 40-F that will be filed with the U.S. Securities and Exchange Commission and will be available on EDGAR at www.sec.gov. Readers are also urged to review the Management's Discussion & Analysis and financial statements filed on SEDAR and EDGAR concurrently with this news release for more complete disclosure on our operations.
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 Enerplus will produce any portion of the volumes currently classified as contingent resources or that Enerplus will produce any portion of the volumes currently classified as contingent resources. The contingent resource estimates contained herein are presented as the "best estimate" of the quantity that will actually be recovered, effective as of December 31, 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.
For information regarding the primary contingencies which currently prevent the classification of Enerplus' disclosed contingent resources associated with the Kirby oil sands project as reserves and the positive and negative factors relevant to the contingent resource estimate, see the Fund's Annual Information Form for the year ended December 31, 2008 (and corresponding Form 40-F) dated March 13, 2009, a copy of which is available on our SEDAR profile at www.sedar.com and a copy of the Form 40-F is available on EDGAR at www.sec.gov. For information regarding the primary contingencies which currently prevent the classification of Enerplus' disclosed contingent resources associated with its Marcellus shale gas assets as reserves and the positive and negative factors relevant to the contingent resource estimate, see the Fund's material change report dated August 27, 2009, copies of which are available on SEDAR and EDGAR as described above.
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 (the "SEC") 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. Canadian disclosure requirements require that forecasted commodity prices be used for reserves evaluations, while the SEC mandates the use of an average of first day of the month price for the 12 months prior to the end of the reporting period. Additionally, the SEC prohibits disclosure of oil and gas resources, whereas Canadian issuers may disclose oil and gas resources. Resources are different than, and should not construed as reserves. For a description of the definition of, and the risks and uncertainties surrounding the disclosure of, contingent resources, see "Information Regarding Reserves, Resources and Operational Information in this News Release" above.
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: Enerplus' strategy; the performance of Enerplus' assets and operations; future growth prospects, acquisitions and dispositions; future cash distributions and dividends to securityholders; capital and development expenditures and the timing and allocation thereof; the volumes and estimated value of the Fund's oil and gas reserves and contingent resource volumes; the life of the Fund's reserves; the volume and product mix of the Fund's oil and gas production; future results from operations; future development and drilling locations and plans; the installation of infrastructure; receipt of regulatory approvals; commodity prices and foreign exchange rates; the amount of future asset retirement obligations; returns on the Fund's capital program; the conversion from an income trust to a corporation and the timing thereof; Enerplus' tax position; and future costs, expenses and royalty rates.
The forward-looking information contained in this news release reflect several material factors and expectations and assumptions of the Fund including, without limitation: that the Fund will continue to conduct its operations in a manner consistent with past operations; the general continuance of current or, where applicable, assumed industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; the accuracy of the estimates of the Fund's reserve and resource volumes; certain commodity price and other cost assumptions; the continued availability of adequate debt and/or equity financing and cash flow to fund its capital and operating requirements as needed; and the extent of its liabilities. The Fund 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 are not guarantees of future performance and should not be unduly relied upon. Such information and 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 the Fund's products; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans the Fund or by third party operators of the Fund's properties, increased debt levels or debt service requirements; inaccurate estimation of the Fund's oil and gas reserve and resource volumes; limited, unfavourable or a lack of access to capital markets; 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 the Fund's public disclosure documents (including, without limitation, those risks identified in the Fund's Annual Information Form and Form 40-F described above).
The forward-looking information 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.
NON-GAAP MEASURES
In this news release, the Fund uses the terms "payout ratio" and "adjusted payout ratio" to analyze operating performance, leverage and liquidity, and the terms "recycle ratio" and "F&D costs" as measures of operating performance. The Fund calculates "payout ratio" by dividing cash distributions to unitholders by cash flow from operating activities, both of which are measures prescribed by Canadian generally accepted accounting principles ("GAAP") and which appear on the Fund's consolidated statements of cash flow. "Adjusted payout ratio" is calculated as cash distributions to unitholders plus development capital and office expenditures, divided by cash flow from operating activities. "Recycle ratio" is calculated by dividing operating netback per BOE (calculated by subtracting Enerplus' royalties, state severance taxes and operating and gathering costs from its revenues) by the F&D cost per BOE.
Enerplus believes that, in addition to net earnings and other measures prescribed by GAAP, the terms "payout ratio", "adjusted payout ratio", "recycle ratio" and "F&D costs" are useful supplemental measures as they provide an indication of the results generated by Enerplus' principal business activities. However, these measures are not measures recognized by GAAP and do not have a standardized meaning prescribed by GAAP. 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 Resources Fund
%CIK: 0001126874
For further information: Investor Relations at 1-800-319-6462 or email [email protected]
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