ARC Energy Trust releases 2009 year-end reserves information
Feb 9, 2010
<<
HIGHLIGHTS
- Proved reserves increased by 11 per cent to 270 mmboe and proved plus
probable reserves increased by 18 per cent to 379 mmboe, compared to
year-end 2008 levels. On a per-unit basis at year-end 2009, proved
reserves increased by two per cent and proved plus probable reserves
increased by eight per cent relative to year-end 2008.
- ARC replaced 347 per cent of annual production at an all-in annual
Finding, Development and Acquisition ("FD&A") cost of $6.44 per
barrel of oil equivalent ("boe") before consideration of future
development capital ("FDC") for the proved plus probable reserves
category. This is the third consecutive year of reducing FD&A costs
and brings our three year average FD&A prior to FDC down to $9.57 per
boe. FD&A costs including FDC were $11.57 per boe, a 32 per cent
reduction from the $17 per boe achieved in 2008.
- ARC has realized its lowest proved plus probable F&D cost in a decade
of $5.45 per boe prior to FDC.
- Net acquisition spending was $158 million resulting in a net
acquisition cost of $10.97 per boe for the proved plus probable
category and $19.87 per boe for the total proved category, prior to
FDC.
- These reserves additions result in a one year recycle ratio of 3.8
times, using our $6.44 per boe proved plus probable FD&A cost prior
to FDC, and 2.6 times using our $9.57 per boe three year average
FD&A, based on the 2009 operating netback of $24.72 per boe.
- Total proved plus probable reserves for the Upper Montney in the
Dawson and West Montney areas have increased to 784 Bcf, a 73 per
cent increase over year-end 2008 and a 333 per cent increase from
year-end 2007.
- The proved plus probable reserve life index ("RLI") increased to 14.5
years with the proved RLI remaining effectively unchanged at 10.3
years based on the mid-point 2010 production guidance of 71,500 boe
per day.
>>
RESERVES
Reserves included herein are stated on a company interest basis (before royalty burdens and including royalty interests) unless noted otherwise. All reserves information has been prepared in accordance with National Instrument ("NI") 51-101. This news release contains several cautionary statements that are specifically required by NI 51-101 under the heading "Resources and Operational Information". In addition to the detailed information disclosed in this news release more detailed information on a company gross basis (working interest before deduction of royalties without including any royalty interests) will be included in ARC's Annual Information Form ("AIF"). Numbers presented may not add due to rounding.
Based on an independent reserves evaluation conducted by GLJ Petroleum Consultants Ltd. ("GLJ") effective
<<
RESERVES SUMMARY Using GLJ January 1, 2010 Forecast Prices and Costs
-------------------------------------------------------------------------
Company Interest (Gross + Royalties Receivable)
Oil Oil
Light and Heavy Total Total Equi- Equi-
Medium Crude Crude Natural valent valent
Crude Oil Oil Oil NGLs Gas 2009 2008
(mbbl) (mbbl) (mbbl) (mbbl) (bcf) (mboe) (mboe)
-------------------------------------------------------------------------
Proved
Producing 93,137 2,353 95,490 8,443 490.1 185,623 180,777
Proved
Developed
Non-
Producing 1,113 13 1,126 420 37.9 7,863 7,794
Proved
Undeveloped 8,667 0 8,667 2,636 388.5 76,048 54,719
Total
Proved 102,917 2,366 105,284 11,500 916.5 269,535 243,292
Proved
plus
Probable 134,570 3,027 137,598 15,815 1,353.2 378,953 321,723
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Company Gross
Oil Oil
Light and Heavy Total Total Equi- Equi-
Medium Crude Crude Natural valent valent
Crude Oil Oil Oil NGLs Gas 2009 2008
(mbbl) (mbbl) (mbbl) (mbbl) (bcf) (mboe) (mboe)
-------------------------------------------------------------------------
Proved
Producing 92,989 2,199 95,187 8,299 481.1 183,663 178,659
Proved
Developed
Non-
Producing 1,112 13 1,125 420 37.9 7,862 7,793
Proved
Undeveloped 8,655 0 8,655 2,636 388.4 76,018 54,700
Total
Proved 102,756 2,212 104,968 11,355 907.3 267,543 241,154
Proved
plus
Probable 134,363 2,834 137,197 15,637 1,342.3 376,543 319,114
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Interest
Oil Oil
Light and Heavy Total Total Equi- Equi-
Medium Crude Crude Natural valent valent
Crude Oil Oil Oil NGLs Gas 2009 2008
(mbbl) (mbbl) (mbbl) (mbbl) (bcf) (mboe) (mboe)
-------------------------------------------------------------------------
Proved
Producing 79,083 2,157 81,239 5,857 419.2 156,959 152,789
Proved
Developed
Non-
Producing 921 12 933 297 29.8 6,194 5,604
Proved
Undeveloped 7,151 0 7,151 2,062 319.9 62,525 41,350
Total
Proved 87,154 2,168 89,322 8,216 768.8 225,678 199,742
Proved
plus
Probable 112,919 2,745 115,664 11,399 1,123.7 314,350 262,928
-------------------------------------------------------------------------
-------------------------------------------------------------------------
RESERVES RECONCILIATION
Company Interest (Company Gross + Royalties Receivable)
Light and Heavy Total Total Oil
Medium Crude Crude Natural Equiv-
Crude Oil Oil Oil NGLs Gas alent
(mbbl) (mbbl) (mbbl) (mbbl) (mmcf) (mboe)
-------------------------------------------------------------------------
PROVED PRODUCING
Opening
Balance 94,922 2,552 97,474 8,692 447,665 180,777
Exploration
Discoveries 0 0 0 0 0 0
Drilling
Extensions 501 0 501 128 32,136 5,985
Improved
Recovery 3,871 7 3,878 192 8,678 5,516
Infill
Drilling 1,433 12 1,445 301 52,041 10,419
Technical
Revisions 1,775 120 1,895 203 9,271 3,643
Acquisitions 615 0 615 294 14,522 3,330
Dispositions -241 0 -241 -1 -90 -257
Economic
Factors -71 36 -35 -20 -3,258 -598
Production -9,667 -374 -10,041 -1,346 -70,824 -23,191
Closing
Balance 93,137 2,353 95,490 8,443 490,140 185,623
-------------------------------------------------------------------------
TOTAL PROVED
Opening
Balance 105,031 2,561 107,592 11,214 746,914 243,292
Exploration
Discoveries 11 0 11 3 1,267 225
Drilling
Extensions 450 0 450 371 110,976 19,317
Improved
Recovery 1,897 16 1,913 14 807 2,061
Infill
drilling 1,962 12 1,974 456 61,394 12,662
Technical
Revisions 2,176 116 2,292 202 31,824 7,797
Acquisitions 1,369 0 1,369 606 37,535 8,231
Dispositions -241 0 -241 -1 -90 -257
Economic
Factors -70 35 -35 -20 -3,294 -602
Production -9,667 -374 -10,041 -1,346 -70,824 -23,191
Closing
Balance 102,918 2,366 105,284 11,500 916,509 269,535
-------------------------------------------------------------------------
PROBABLE
Opening
Balance 30,168 682 30,850 3,364 265,302 78,431
Exploration
Discoveries 4 0 4 1 435 77
Drilling
Extensions 571 0 571 218 109,540 19,046
Improved
Recovery 371 2 373 5 89 393
Infill
Drilling 442 2 444 294 33,252 6,280
Technical
Revisions -1,516 -36 -1,552 4 3,148 -1,021
Acquisitions 1,843 0 1,843 440 26,205 6,650
Dispositions -183 0 -183 0 -24 -186
Economic
Factors -46 10 -36 -11 -1,210 -251
Production 0 0 0 0 0 0
Closing
Balance 31,653 661 32,314 4,315 436,736 109,419
-------------------------------------------------------------------------
PROVED PLUS
PROBABLE
Opening
Balance 135,199 3,243 138,442 14,578 1,012,216 321,723
Exploration
Discoveries 15 0 15 4 1,702 302
Drilling
Extensions 1,021 0 1,021 589 220,516 38,363
Improved
Recovery 2,268 18 2,286 19 896 2,454
Infill
Drilling 2,404 14 2,418 750 94,646 18,942
Technical
Revisions 660 80 740 206 34,972 6,776
Acquisitions 3,212 0 3,212 1,046 63,740 14,881
Dispositions -424 0 -424 -1 -114 -443
Economic
Factors -116 45 -71 -31 -4,504 -853
Production -9,667 -374 -10,041 -1,346 -70,824 -23,191
Closing
Balance 134,571 3,027 137,598 15,815 1,353,245 378,954
-------------------------------------------------------------------------
>>
Additional reserves reconciliation information on a Company Gross basis is included at the end of this news release.
RESERVE LIFE INDEX ("RLI")
ARC's proved plus probable RLI was 14.5 years at year-end 2009 while the proved RLI was 10.3 years based upon the GLJ reserves and ARC's 2010 production guidance mid-point of 71,500 boe per day. The following table summarizes ARC's historical RLI.
<<
Reserve Life Index
2009 2008 2007 2006 2005 2004
-------------------------------------------------------------------------
Total Proved 10.3 10.4 9.8 9.8 10.3 9.7
Proved Plus Probable 14.5 13.8 12.5 12.4 12.9 12.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
NET PRESENT VALUE ("NPV") SUMMARY
ARC's crude oil, natural gas and natural gas liquids reserves were evaluated using GLJ's product price forecasts effective
<<
NPV of Cash Flow Before Income Taxes Using GLJ January 1, 2010 Forecast
Prices and Costs
NI 51-101
Net Discounted Discounted Discounted Discounted
interest Undiscounted at 5% at 10% at 15% at 20%
$MM $MM $MM $MM $MM
-------------------------------------------------------------------------
Proved Producing 7,164 4,755 3,618 2,956 2,520
Proved Developed
Non-Producing 230 157 119 96 80
Proved
Undeveloped 1,889 1,219 847 615 458
Total Proved 9,283 6,130 4,584 3,666 3,058
Probable 4,285 2,072 1,222 806 569
Proved plus
Probable 13,568 8,202 5,805 4,472 3,627
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
At a 10 per cent discount factor, the proved producing reserves make up 62 per cent of the proved plus probable value while total proved reserves account for 79 per cent of the proved plus probable value.
The following table provides an estimate of the NPV of Cash Flow on an after tax basis assuming that ARC would be subject to the equivalent of corporate income tax on its income beginning in 2011. It should be noted that this estimate does not take into account any corporate tax deductions such as interest and general and administrative expenses or for any tax pools generated by capital expenditures beyond what exists in the GLJ forecast. Details of ARC's tax pools at year-end 2009 are presented in the MD&A section of the year-end financial results news release dated
<<
NPV of Cash Flow After Income Taxes Using GLJ January 1, 2010 Forecast
Prices and Costs
NI 51-101
Net Discounted Discounted Discounted Discounted
interest Undiscounted at 5% at 10% at 15% at 20%
$MM $MM $MM $MM $MM
-------------------------------------------------------------------------
Proved Producing 6,023 4,095 3,173 2,629 2,267
Proved Developed
Non-Producing 177 121 92 74 62
Proved
Undeveloped 1,416 891 598 415 291
Total Proved 7,616 5,107 3,863 3,118 2,621
Probable 3,220 1,548 903 588 409
Proved plus
Probable 10,836 6,655 4,766 3,706 3,030
-------------------------------------------------------------------------
-------------------------------------------------------------------------
GLJ January 1, 2010 Price Forecast
-------------------------------------------------------------------------
West Texas Edmonton Natural
Intermediate Light Gas at Foreign
Crude Oil Crude Oil AECO Exchange
Year ($US/bbl) ($Cdn/bbl) ($Cdn/mmbtu) ($US/$Cdn)
-------------------------------------------------------------------------
2010 80.00 83.26 5.96 0.95
2011 83.00 86.42 6.79 0.95
2012 86.00 89.58 6.89 0.95
2013 89.00 92.74 6.95 0.95
2014 92.00 95.90 7.05 0.95
2015 93.84 97.84 7.16 0.95
2016 95.72 99.81 7.42 0.95
2017 97.64 101.83 7.95 0.95
2018 99.59 103.88 8.52 0.95
2019 101.58 105.98 8.69 0.95
Escalate thereafter at +2.0%/yr +2.0%/yr +2.0%/yr
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
NET ASSET VALUE
The following net asset value ("NAV") table shows what is normally referred to as a "produce-out" NAV calculation under which the current value of the Trust's reserves would be produced at forecast future prices and costs and do not necessarily represent a "going concern" value of the Trust. The value is a snapshot in time and is based on various assumptions including commodity prices and foreign exchange rates that vary over time. It should not be assumed that the net present values estimated by GLJ represent the fair market value of the reserves.
<<
NAV at December 31, 2009(a)
-------------------------------------------------------------------------
2009 NAV 2008 NAV
GLJ Price GLJ Price
Forecast Forecast
$Millions, except per unit amounts (2010-01) (2009-01)
-------------------------------------------------------------------------
Value of NI 51-101 Net interest Proved Plus
Probable Reserves discounted at 10% (Before
Tax)(b) $5,805 $5,292
Undeveloped Lands(c) $359 $428
Working Capital Deficit(d) $(56) $(60)
Reclamation Fund $33 $28
Risk Management Contracts(e) $(15) $1
Long-term Debt $(846) $(902)
Asset Retirement Obligation(f) $(27) $(57)
-------------------------------------------------------------------------
Net Asset Value $5,253 $4,732
Units Outstanding (000's)(g) 238,984 219,182
-------------------------------------------------------------------------
NAV/Unit $21.98 $21.59
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(a) Financial information is per ARC's 2009 Consolidated Financial
Statements.
(b) Excludes future income taxes estimated at $1 billion for the GLJ
price forecast using a 10% discount rate and after deducting ARC's
accumulated federal tax pools of $2.1 billion and $0.1 billion of
provincial pools as at Dec 31, 2009 and the pools associated with the
future development capital. The estimated future taxes were
calculated assuming ARC would be subject to the equivalent of
corporate income tax on its income beginning in 2011. Estimated
future taxes do not take into account any corporate tax deductions
such as interest or general and administrative expenses.
(c) Internal estimate taking into account the December 31, 2009 Seaton-
Jordan and Associates Ltd. evaluation.
(d) Working capital deficit excludes risk management contracts and future
income tax asset.
(e) Risk management contracts represent the fair market value of such
contracts as at December 31, 2009 based on the GLJ future pricing
used to arrive at the value of Proved plus Probable reserves. This
amount differs from the value of risk management contracts in the
2009 Consolidated Financial Statements due to differing future
pricing assumptions.
(f) The Asset Retirement Obligation ("ARO") is calculated based on the
same methodology that was used to calculate the ARO on ARC's year-end
financial statements, with the exception that future expected ARO
costs were discounted at 10 per cent. The total discounted ARO at 10
per cent of $75 million was reduced by $48 million, relating to well
abandonment costs, which were incorporated in the Value of the Proved
Plus Probable reserves discounted at 10 per cent pursuant to the
escalated price case as per NI 51-101.
(g) Represents total trust units outstanding and trust units issuable for
exchangeable shares as at December 31, 2009.
>>
In the absence of adding reserves to the Trust, the NAV per unit will decline as the reserves are produced out. The evaluation includes future capital expenditure expectations required to bring undeveloped reserves on production. ARC works continuously to add value, improve profitability and increase reserves, which enhances the Trust's NAV.
At inception of the Trust on
<<
Historical NAV - Discounted at 10 Per Cent
-------------------------------------------------------------------------
$Millions, except
per unit
amounts 2009 2008 2007 2006 2005 2004
-------------------------------------------------------------------------
Value of NI
51-101 Net
interest
Proved plus
Probable
reserves $5,805 $5,292 $4,651 $4,056 $3,891 $2,389
Undeveloped
lands 359 428 229 109 59 48
Reclamation fund 33 28 26 31 23 21
Risk Management
Contracts (15) 1 (36) (9) (2) (12)
Long term-debt,
net of working
capital (902) (962) (753) (739) (578) (265)
Asset retirement
obligation (27) (57) (26) (62) (35) (23)
-------------------------------------------------------------------------
Net asset
value $5,253 $4,732 $4,091 $3,386 $3,358 $2,158
Units
outstanding
(000's) 238,984 219,182 213,179 207,173 202,039 188,804
-------------------------------------------------------------------------
NAV per unit $21.98 $21.59 $19.19 $16.34 $16.62 $11.43
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
FINDING, DEVELOPMENT AND ACQUISITION ("FD&A") COSTS
Under NI 51-101, the methodology to be used to calculate FD&A costs includes incorporating changes in future development capital ("FDC") required to bring the proved undeveloped and probable reserves to production. For continuity, ARC has presented herein FD&A costs calculated both excluding and including FDC.
The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.
FINDING AND DEVELOPMENT COSTS ("F&D")
During 2009 ARC spent
ARC's 2009 capital program was focused on resource play development with the Montney in northeastern British Columbia accounting for 53 per cent of the spending. At Dawson, record average production of 52 mmcf per day of gas and 230 bbl per day of liquids was achieved in 2009. A total of 22 horizontal wells were drilled and significant progress was made towards the completion of the 60 mmcf per day Dawson Phase One gas plant, which is currently expected to be onstream early in May of 2010. Only eight of the 22 wells drilled in 2009 were on production at year-end, with the remaining 14 horizontal wells ready to be brought on production with the completion of the gas plant. The 2010 capital budget calls for the drilling of three step out vertical wells along with the drilling of 30 Montney horizontal wells and the substantial completion of an additional Phase Two 60 mmcf per day gas plant at Dawson. ARC will also be testing the Lower Montney zone that has proven to be productive elsewhere.
In the West Montney assets, ARC participated in a partner operated four well Montney horizontal drilling program at Sunrise, drilled one vertical well at Sunset and one in Sundown in 2009. The four Sunrise horizontal wells have recently been brought on production and are expected to average 10 mmcf per day net to ARC's 50 per cent interest in the first quarter of 2010. ARC's 2010 drilling plans in the West Montney include the drilling of nine gross horizontal wells with a portion of funds specifically targeted towards the assessment of the Lower Montney zone. Spending will also be devoted to the initial procurement of equipment for a new Sunrise gas plant, currently planned for early 2012.
In Ante Creek, ARC drilled four horizontal Montney wells targeting a mixture of oil and gas production. With the success of these wells and a late year acquisition of approximately 1,000 boe per day, ARC was able to grow Ante Creek production to a record 7,000 boe per day at year-end 2009. ARC has allocated
At Redwater, ARC drilled three horizontal wells, only two of which were on production prior to year-end. Carbon dioxide injection into the enhanced oil recovery ("EOR") pilot area continued successfully through the end of 2009 with plans to continue optimization and evaluation of the pilot into 2010.
The Pembina area development included nine successful Cardium drills, including four horizontal wells coming on at stable one month production rates averaging over 150 boe per day per well. The 2010 capital budget will build on 2009 success with 17 more planned horizontal Cardium wells.
In the central Alberta area, ARC continued to develop the Natural Gas from Coal prospects with the drilling of 38 more wells. The other key strategic investment in 2009 was the drilling of two horizontal Cardium wells in the Garrington area, which should be on production in early 2010.
In ARC's shallow gas regions in southeastern Alberta and southwestern Saskatchewan there were 44 shallow gas wells drilled with 23 of them coming on production before year-end.
ARC experienced significant drilling success in southeast Saskatchewan and Manitoba with 15 new horizontal oil wells. Some of the key areas that will receive continued development focus into 2010 are Elmore, Lougheed, Midale, Weyburn and Goodlands.
MONTNEY UPDATE
The Dawson gas field was the center piece of the Star Oil and Gas purchase made by ARC in April of 2003, at that time production was approximately 17 mmcf per day and the proved plus probable reserves were just 110 Bcf. Since then ARC has added to its land base in the area, drilled 77 vertical wells and 41 horizontal wells and increased production to 55 mmcf per day. As a result of the development activities, advances in technology and knowledge gained through the longer production history, proved plus probable reserves have increased to 593 Bcf. See "Information Regarding Disclosure on Oil and Gas Resources and Operational Information". The majority of the reserve additions have come in the past two years - 254 Bcf were added in 2008 and a further 205 Bcf were added in 2009, as successful development with horizontal wells lead to the implementation of a major development project at Dawson. Despite this success, ARC still believes that there are significant volumes of gas that can be added to reserves in the future assuming continued successful development of the field.
This discussion on the Montney resource at Dawson and West Montney is subject to a number of cautionary statements, assumptions and risks, some of which are included below and others under "Information Regarding Disclosure on Oil and Gas Resources and Operational Information".
DAWSON
ARC has 105 net sections of land at Dawson on which GLJ have assigned a best estimate of 3.4 Tcf of gas identified as Discovered Petroleum Initially In Place ("DPIIP") net to ARC in the Upper Montney as at
WEST MONTNEY
In the West Montney area, the Upper Montney section thickens and a second porous and permeable zone referred to as the Montney B is present. To date, all of the production has come from the Montney A. While gas has been tested from the Montney B by ARC, current development plans are focused on the Montney A. There is a deeper zone, referred to as the Lower Montney that also has shown development potential in the region, but DPIIP has not been evaluated in the Lower Montney zone due to insufficient data on ARC lands.
<<
Sunrise/Sunset Area (Sunrise)
------------------------------
>>
In the greater Sunrise / Sunset area ARC has 32 net sections of land on which GLJ have assigned a best estimate of 2.9 Tcf of gas classified as DPIIP net to ARC as at
<<
Saturn/Monias (Septimus) and Sundown
-------------------------------------
>>
ARC also owns 19 net sections of land in the Septimus area and 18 net sections of land in the Sundown area on which GLJ have assigned a best estimate of 2.1 Tcf of gas currently classified as DPIIP net to ARC in the Upper Montney. Approximately 60 per cent of the DPIIP are attributed to the Septimus area where considerable industry activity is taking place. A very small amount of reserves have been assigned at Septimus, with no reserves currently assigned to the Sundown property. Additional drilling will be required to explore and delineate these properties before it will be possible to define the timing of potential development projects.
All estimates of DPIIP of GLJ are as at
ARC's belief that it will recognize significant additional reserves in Dawson and the West Montney assets is based on a combination of historic recoveries of the more fully developed Montney acreage, abundant well log and production test data, and the application of drilling densities of ARC and third parties in the area and assume continuous development through multi-year exploration and development programs, changing economic circumstances and further development and completion refinements. The principal risks of not achieving the reserve additions relate to the potential for variations in the quality of the Montney formation where no current well data exists, access to capital, low gas prices that would impact the economics of development, and the future performance of wells. Unless otherwise indicated, all reserves are proved plus probable.
See "Information Regarding Disclosure on Oil and Gas Resources and Operational Information" for additional cautionary language, explanations and discussion and "Forward Looking Statements" for a statement of principal assumptions and risks that may apply.
ACQUISITIONS AND DISPOSITIONS
In 2009, ARC spent
FINDING DEVELOPMENT AND ACQUISITION COSTS ("FD&A")
Incorporating the net acquisitions during the year, ARC's proved plus probable FD&A costs excluding FDC were
FUTURE DEVELOPMENT CAPITAL ("FDC")
NI 51-101 requires that FD&A costs be calculated including changes in FDC. Changes in forecast FDC occur annually as a result of development activities, acquisition and disposition activities and capital cost estimates that reflect the independent evaluator's best estimate of what it will cost to bring the proved undeveloped and probable reserves on production. The increased level of undeveloped reserves now booked in the Montney acreage has yielded an increased capital cost expectation in the 2009 evaluation.
<<
FD&A Costs - Company Interest Reserves
Proved plus
Proved Probable
-------------------------------------------------------------------------
FD&A Costs Excluding Future Development Capital
-----------------------------------------------
Exploration and Development Capital
Expenditures - $thousands $359,561 $359,561
Exploration and Development Reserve Additions
including Revisions - mboe 41,460 65,984
Finding and Development Cost - $/boe $8.67 $5.45
Three Year Average F&D Cost - $/boe $12.58 $8.91
Net Acquisition Capital - $thousands $158,440 $158,440
Net Acquisition Reserve Additions - mboe 7,975 14,438
Net Acquisition Cost - $/boe $19.87 $10.97
Three Year Average Net Acquisition Cost - $/boe $26.77 $15.47
Total Capital Expenditures including Net
Acquisitions - $thousands $518,001 $518,001
Reserve Additions including Net
Acquisitions - mboe 49,435 80,422
Finding Development and Acquisition Cost - $/boe $10.48 $6.44
Three Year Average FD&A Cost - $/boe $13.76 $9.57
FD&A Costs Including Future Development Capital
------------------------------------------------
Exploration and Development Capital
Expenditures - $thousands $359,561 $359,561
Exploration and Development Change in FDC
- $thousands $150,181 $335,803
Exploration and Development Capital including
Change in FDC- $thousands $509,741 $695,364
Exploration and Development Reserve Additions
including Revisions - mboe 41,460 65,984
Finding and Development Cost - $/boe $12.29 $10.54
Three Year Average F&D Cost - $/boe $17.10 $14.12
Net Acquisition Capital - $thousands $158,440 $158,440
Net Acquisition FDC - $thousands $38,321 $76,236
Net Acquisition Capital including FDC
- $thousands $196,761 $234,677
Net Acquisition Reserve Additions - mboe 7,975 14,438
Net Acquisition Cost - $/boe $24.67 $16.25
Three Year Average Net Acquisition Cost - $/boe $31.16 $20.34
Total Capital Expenditures including Net
Acquisitions - $thousands $518,001 $518,001
Total Change in FDC - $thousands $188,501 $412,040
Total Capital Including Change in FDC
- $thousands $706,502 $930,041
Reserve Additions including Net Acquisitions
- mboe 49,435 80,422
Finding Development and Acquisition Cost
including FDC - $/boe $14.29 $11.56
Three Year Average FD&A Cost Including FDC
- $/boe $18.27 $14.75
-------------------------------------------------------------------------
-------------------------------------------------------------------------
In all cases, the F&D, or FD&A number is calculated by dividing the
identified capital expenditures by the applicable reserves additions.
Historic Company Interest Proved FD&A Costs
-------------------------------------------------------------------------
2009 2008 2007 2006 2005 2004
-------------------------------------------------------------------------
Annual FD&A
excluding FDC $10.48 $14.22 $20.37 $24.51 $15.60 $16.53
Three year
average FD&A
excluding FDC $13.76 $18.28 $18.51 $17.77 $13.30 $11.05
-------------------------------------------------------------------------
Annual FD&A
including FDC $14.29 $21.87 $20.37 $27.53 $17.64 $20.46
Three year
average FD&A
including FDC $18.27 $22.85 $20.30 $20.31 $15.45 $13.02
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Historic Company Interest Proved Plus Probable FD&A Costs
-------------------------------------------------------------------------
2009 2008 2007 2006 2005 2004
-------------------------------------------------------------------------
Annual FD&A
excluding FDC $6.44 $10.13 $19.00 $22.41 $13.64 $13.76
Three Year
Average FD&A
excluding FDC $9.57 $14.70 $16.57 $15.59 $11.00 $9.30
-------------------------------------------------------------------------
Annual FD&A
including FDC $11.56 $17.00 $20.03 $27.20 $16.09 $19.14
Three Year
Average FD&A
including FDC $14.75 $19.84 $19.19 $18.99 $13.50 $11.65
-------------------------------------------------------------------------
-------------------------------------------------------------------------
RESERVES RECONCILIATION
Company Gross (Company Interest - Royalties Payable)
Light and Heavy Total Total Oil
Medium Crude Crude Natural Equiv-
Crude Oil Oil Oil NGLs Gas alent
(mbbl) (mbbl) (mbbl) (mbbl) (mmcf) (mboe)
-------------------------------------------------------------------------
PROVED
PRODUCING
Opening
Balance 94,805 2,357 97,162 8,535 437,774 178,659
Exploration
Discoveries 0 0 0 0 0 0
Drilling
Extensions 500 0 500 128 32,101 5,978
Improved
Recovery 3,845 7 3,852 192 8,666 5,489
Infill
Drilling 1,432 12 1,444 301 52,041 10,418
Technical
Revisions 1,714 121 1,835 202 8,466 3,448
Acquisitions 612 0 612 294 14,504 3,324
Dispositions -241 0 -241 -1 -90 -257
Economic
Factors -70 36 -34 -19 -3,152 -579
Production -9,607 -335 -9,942 -1,333 -69,252 -22,817
Closing
Balance 92,988 2,199 95,187 8,299 481,057 183,663
-------------------------------------------------------------------------
TOTAL PROVED
Opening
Balance 104,912 2,366 107,278 11,057 736,916 241,154
Exploration
Discoveries 11 0 11 3 1,267 225
Drilling
Extensions 449 0 449 371 110,941 19,310
Improved
Recovery 1,862 16 1,878 14 794 2,024
Infill
Drilling 1,961 12 1,973 456 61,394 12,661
Technical
Revisions 2,112 117 2,229 202 31,016 7,600
Acquisitions 1,366 0 1,366 606 37,517 8,225
Dispositions -241 0 -241 -1 -90 -257
Economic
Factors -69 36 -33 -19 -3,187 -583
Production -9,607 -335 -9,942 -1,333 -69,252 -22,817
Closing
Balance 102,756 2,212 104,968 11,355 907,316 267,543
-------------------------------------------------------------------------
PROBABLE
Opening
Balance 30,137 640 30,777 3,329 263,119 77,959
Exploration
Discoveries 4 0 4 1 435 77
Drilling
Extensions 572 0 572 218 109,531 19,045
Improved
Recovery 360 2 362 5 86 382
Infill
Drilling 432 2 434 295 33,251 6,271
Technical
Revisions -1,510 -31 -1,541 5 3,541 -945
Acquisitions 1,841 0 1,841 440 26,194 6,646
Dispositions -183 0 -183 0 -24 -186
Economic
Factors -46 8 -38 -11 -1,192 -248
Production 0 0 0 0 0 0
Closing
Balance 31,607 622 32,229 4,281 434,941 109,000
-------------------------------------------------------------------------
PROVED PLUS
PROBABLE
Opening
Balance 135,049 3,006 138,055 14,386 1,000,035 319,113
Exploration
Discoveries 15 0 15 4 1,702 302
Drilling
Extensions 1,021 0 1,021 588 220,472 38,355
Improved
Recovery 2,222 18 2,240 19 880 2,406
Infill
Drilling 2,393 14 2,407 750 94,645 18,932
Technical
Revisions 602 86 688 207 34,557 6,655
Acquisitions 3,207 0 3,207 1,046 63,711 14,871
Dispositions -424 0 -424 -1 -114 -443
Economic
Factors -115 44 -71 -30 -4,379 -831
Production -9,607 -335 -9,942 -1,333 -69,252 -22,817
Closing
Balance 134,363 2,834 137,197 15,637 1,342,257 376,543
-------------------------------------------------------------------------
-------------------------------------------------------------------------
FD&A Costs - Company Gross Reserves
Proved plus
Proved Probable
-------------------------------------------------------------------------
NI 51-101 Calculation Including Future Development
Capital
--------------------------------------------------
Capital Expenditures excluding
Net Acquisitions - $thousands $359,561 $359,561
Net Change in FDC excluding
Net Acquisitions - $thousands $150,181 $335,803
Total Capital including FDC - $thousands $509,741 $695,364
Reserve additions excluding
Net Acquisitions - mboe 41,238 65,818
Finding and Development Cost - $/boe $12.36 $10.57
Three Year Average F&D Cost - $/boe $17.18 $14.11
Capital Expenditures including
net acquisitions - $thousands $518,001 $518,001
Net Change in FDC including
net acquisitions - $thousands $188,501 $412,040
Total Capital - $thousands $706,502 $930,041
Reserve additions including
net acquisitions - mboe 49,206 80,246
Finding Development and Acquisition Cost - $/boe $14.36 $11.59
Three Year Average FD&A Cost - $/boe $18.41 $14.81
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Historic Company Gross Proved FD&A Costs
-------------------------------------------------------------------------
2009 2008 2007 2006 2005 2004 2003
-------------------------------------------------------------------------
Annual FD&A
including
FDC $14.36 $22.01 $20.71 $28.05 $17.81 $21.27 $12.95
Three year
average
FD&A
including
FDC $18.41 $23.12 $20.57 $20.63 $15.74 $13.54 n/a
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Historic Company Gross Proved Plus Probable FD&A Costs
-------------------------------------------------------------------------
2009 2008 2007 2006 2005 2004 2003
-------------------------------------------------------------------------
Annual FD&A
including
FDC $11.59 $17.08 $20.29 $27.79 $16.24 $19.74 $10.74
Three Year
Average
FD&A
including
FDC $14.81 $20.04 $19.43 $19.28 $13.73 $12.09 n/a
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
INFORMATION REGARDING DISCLOSURE ON OIL AND GAS RESERVES, RESOURCES AND OPERATIONAL INFORMATION
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 company 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 "company gross reserves" (as defined in National Instrument 51-101 adopted by the Canadian securities regulators ("NI 51-101") plus ARC's royalty interests in reserves. "Company interest reserves" are not a measure defined in NI 51-101 and does 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
This news release contains references to estimates of gas classified as discovered petroleum initially in place in the area west of Dawson in British Columbia which are not, and should not be confused with, oil and gas reserves. "Discovered petroleum initially in place" ("DPIIP") is defined in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") as the quantity of hydrocarbons that are estimated to be in place within a known accumulation. DPIIP is divided into recoverable and unrecoverable portions, with the estimated future recoverable portion classified as reserves and contingent resources and the remainder as at evaluation date is by definition unrecoverable. There is no certainty that it will be economically viable or technically feasible to produce any portion of this DPIIP.
ARC has not categorized the resources disclosed as DPIIP into all of the subcategories of discovered resources as projects have not been defined to develop them as at the evaluation date. Such projects, in the case of the Montney resource development, have historically been developed sequentially over a number of drilling seasons and are subject to annual budget constraints, ARC's policy of orderly development on a staged basis, the timing of the growth of third party infrastructure, the short and long-term view of ARC on gas prices, the results of exploration and development activities of ARC and others in the area and possible infrastructure capacity constraints.
ARC's belief that it will establish significant additional reserves over time in the discussion of the Montney Resource Development is a forward looking statement and is based on certain assumptions and is subject to certain risks, as discussed below under the heading "Forward Looking Statements".
Additionally, the SEC prohibits disclosure of oil and gas resources, whereas Canadian issuers may disclose resource volumes. Resources are different than, and should not be construed as, reserves. For a description of the definition of, and the risks and uncertainties surrounding the disclosure of, resources, see above.
NOTICE TO U.S. READERS
The oil and natural gas reserves contained in this press release have generally been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects of
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", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", "strategy" and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the recognition of significant additional reserves under the heading "Montney Resource Discussion", the volumes and estimated value of ARC's oil and gas reserves; the life of ARC's reserves; the volume and product mix of ARC's oil and gas production; future oil and natural gas prices and ARC's commodity risk management programs; the amount of future asset retirement obligations; future results from operations and operating metrics; and future development, exploration, acquisition and development activities (including drilling plans) and related production expectations.
The forward-looking information and statements contained in this news release reflect several material factors and expectations and assumptions of ARC including, without limitation: that ARC will continue to conduct its operations in a manner consistent with past operations; results from drilling and development activities consistent with past results; the continued and timely development of infrastructure in areas of new production; the general continuance of current 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 ARC's reserve and resource volumes; certain commodity price and other cost assumptions; and the continued availability of adequate debt and equity financing and cash flow to fund its plans expenditures. There are a number of assumptions associated with the development of the lands at Dawson and the lands west of Dawson including the quality of the Montney reservoir, continued performance from existing wells, future drilling programs and performance from new wells, the growth of infrastructure, well density per section, recovery factors and development necessarily involves known and unknown risks and uncertainties, including those risks identified in this press release. ARC believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.
The forward-looking information and statements included in this news release are not guarantees of future performance and should not be unduly relied upon. Such information and statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; the potential for variation in the quality of the Montney formation, changes in the demand for or supply of ARC's products; unanticipated operating results or production declines; unanticipated results from ARC's exploration and development activities; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of ARC or by third party operators of ARC's properties, increased debt levels or debt service requirements; inaccurate estimation of ARC'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; and certain other risks detailed from time to time in ARC's public disclosure documents (including, without limitation, those risks identified in this news release and in ARC's Annual Information Form).
The forward-looking information and statements contained in this news release speak only as of the date of this news release, and none of ARC 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.
ARC Energy Trust is one of Canada's largest conventional oil and gas royalty trusts with a current enterprise value of approximately
<<
ARC RESOURCES LTD.
John P. Dielwart,
Chief Executive Officer
>>
%SEDAR: 00015954E %CIK: 0001029509
For further information: about ARC Energy Trust, please visit our website www.arcresources.com or contact: Investor Relations, E-mail: ir@arcresources.com, Telephone: (403) 503-8600, Fax: (403) 509-6417, Toll Free 1-888-272-4900, Suite 2100, 440 - 2nd Avenue S.W., Calgary, AB, T2P 5E