Mr. Myron Stadnyk reports
ARC RESOURCES LTD. ANNOUNCES THE 8TH CONSECUTIVE YEAR OF ~200% RESERVES REPLACEMENT, 2015 FINDING AND DEVELOPMENT COSTS FOR 2P RESERVES OF $6.97 AND A SIGNIFICANT INCREASE IN MONTNEY RESOURCE ESTIMATES IN 2015
ARC Resources Ltd. has released its year-end 2015 reserves and resources information.
"ARC's team once again demonstrated the strength of its asset base and technical expertise, replacing 190 per cent of produced reserves through the drill bit at low finding and development costs of $6.97 per boe for proved plus probable reserves. These results showcase ARC's exceptional Montney assets, which were the main driver of both reserves replacement and positive technical revisions. An updated independent resources evaluation for our northeast British Columbia and Pouce Coupe assets realized a significant increase in the identified resource base on ARC's lands in the area. With exceptional capital and operating efficiencies and strong well performance, ARC's world-class Montney assets provide ARC with tremendous long-term development opportunities -- which our team will pursue in our tradition of prudent capital management and paced development," stated Myron Stadnyk, president and chief executive officer.
Highlights:
-
Replaced 190 per cent of 2015 total production, adding 78.7 million barrels of oil equivalent of proven plus probable (2P) reserves through development capital activities. Over the last eight years, ARC has delivered an average of 200 per cent produced reserves replacement through the drill bit.
- Positive technical revisions of 36 million boe (2P) were realized, predominantly in Tower, Sunrise and Dawson, reflecting the strong well performance of ARC's Montney assets. These more than offset the removal of 15 million boe due to the decrease in commodity prices since year-end 2014.
- Proven developed producing (PDP) reserves increased from 210 million boe to 222 million boe. The increase in PDP reserves was driven by northeast B.C. Montney properties, which increased to 115 million boe at year-end 2015 from 84 million boe at year-end 2014.
- Replaced 175 per cent of 2015 natural gas production, adding 300 million cubic feet of 2P natural gas reserves. Replaced approximately 210 per cent of 2015 oil and natural gas liquids (NGLs) production, adding 31 million bbl of 2P oil and NGLs reserves. Material reserves growth was realized in the northeast B.C. Montney region, particularly in Tower, Sunrise and Dawson.
- Finding and development (F&D) costs of $6.97 per boe for 2P reserves and $8.20 per boe for proven reserves, excluding future development capital (FDC) and F&D costs of $8.31 per boe for proven producing reserves. Significant northeast B.C. Montney reserve additions, combined with capital reductions, contributed to the 39-per-cent reduction in 2P F&D costs relative to 2014.
- Significant FDC reduction from $3.6-billion at year-end 2014 to $2.7-billion at year-end 2015. This was mainly attributed to a decrease in drilling, completions and facility capital costs, as well as the removal of capital associated with various dispositions.
-
ARC updated an independent resources evaluation for its lands in the northeast B.C. Montney region, including lands at Pouce Coupe in Alberta. The updated evaluation realized a significant increase in the identified resource base on ARC's northeast B.C. Montney lands. The shale gas total petroleum initially in place (TPIIP) increased 33 per cent from 67.4 trillion cubic feet in 2014 to 90 trillion cubic feet in 2015 and tight oil TPIIP increased 315 per cent from 2.3 billion barrels of oil in 2014 to 9.7 billion barrels in 2015.
Independent reserves evaluation
for 2015
GLJ Petroleum Consultants (GLJ) conducted an independent reserves evaluation, effective Dec. 31, 2015, which was prepared in accordance with definitions, standards and procedures contained in the Canadian oil and gas evaluation handbook and National Instrument 51-101 (standards of disclosure for oil and gas activities). The reserves evaluation was based on GLJ forecast pricing and foreign exchange rates at Jan. 1, 2016.
Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without the inclusion of any royalty interest) unless otherwise noted. All reserves information has been prepared in accordance with NI 51-101. In addition to the detailed information disclosed in this news release, more detailed information will be included in ARC's annual information form for the year ended Dec. 31, 2015, which will be filed on SEDAR on or before March 30, 2016.
Based on this independent reserves evaluation, ARC's reserves profile as at Dec. 31, 2015, is summarized below:
- Two-per-cent increase in 2015 2P reserves to 687 million barrels of oil equivalent compared with 673 million boe of 2P reserves at year-end 2014. 2P reserves are composed of 2.9 trillion cubic feet of natural gas and 200 million barrels of oil and NGLs at year-end 2015.
- A total of 78.7 million boe of 2P reserve additions from exploration and development activities (including revisions), before net dispositions of 23 million boe and 2015 production of 42 million boe. Technical revisions of 36 million boe more than offset the removal of 15 million boe due to the decrease in commodity prices since year-end 2014.
- A 190-per-cent replacement of 2P reserves based on 78.7 million boe of 2P reserve additions and 2015 production of 42 million boe.
- Total proven reserves account for 57 per cent of 2P reserves.
- PDP reserves represent 56 per cent of total proven reserves and 32 per cent of 2P reserves.
- Oil and NGLs comprise 29 per cent of 2P reserves, and natural gas comprises 71 per cent of 2P reserves, using the commonly accepted boe conversion ratio of 6,000 cubic feet to one barrel.
- The downward change in FDC, which exceeded the 2015 capital spent, resulted in negative one-year 2P F&D costs, including FDC, of ($2.82) per boe for 2015, and $8.11 per boe for the three-year average. Proven F&D costs, including FDC, were 19 cents per boe for 2015 and $11.61 per boe for the three-year average. Given the large reduction in FDC, one-year F&D costs, including FDC, are not meaningful.
- Strong reserve life index (RLI) of 15.9 years, up from 15.0 years at year-end 2014. The increase in RLI is attributed to reserves growth in 2015, as well as modest expected production growth in 2016, as a result of reduced capital expenditures.
- Recycle ratio of 2.4 times and 2.5 times for the current year and the three-year average, respectively, for 2P reserves based on current and three-year average F&D costs, excluding FDC, based on current and three-year average operating netbacks of $16.69 per boe and $25.91 per boe, respectively.
- Abandonment and reclamation costs of $527-million (undiscounted) have been included in the 2P reserves, which account for the abandonment and reclamation of all wells to which reserves have been attributed.
GLJ PRICE FORECAST
WTI crude oil Edmonton light oil AECO natural gas Foreign exchange
at Jan. 1 (U.S.$/bbl) (Cdn$/bbl) (Cdn$/MMBtu) (U.S.$/Cdn$)
2016 2015 2016 2015 2016 2015 2016 2015
2016 $44.00 $75.00 $55.86 $80.00 $2.76 $3.77 $0.725 $0.875
2017 52.00 80.00 64.00 85.71 3.27 4.02 0.750 0.875
2018 58.00 85.00 68.39 91.43 3.45 4.27 0.775 0.875
2019 64.00 90.00 73.75 97.14 3.63 4.53 0.800 0.875
2020 70.00 95.00 78.79 102.86 3.81 4.78 0.825 0.875
2021 75.00 98.54 82.35 106.18 3.90 5.03 0.850 0.875
2022 80.00 100.51 88.24 108.31 4.10 5.28 0.850 0.875
2023 85.00 102.52 94.12 110.47 4.30 5.53 0.850 0.875
2024 87.88 104.57 96.48 112.67 4.50 5.71 0.850 0.875
2025 89.63 98.41 4.60 0.850 0.875
Escalate
thereafter at +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr 0.850 0.875
RESERVES SUMMARY
Crude and tight oil NGLs Natural gas 2015 oil equivalent 2014 oil equivalent
Company gross (Mbbl) (Mbbl) (MMcf) (Mboe) (Mboe)
Proven producing 82,163 12,712 759,803 221,509 209,509
Proven developed non-producing 2,913 870 49,679 12,062 20,164
Proven undeveloped 13,784 15,470 783,010 159,755 152,390
Total proven 98,860 29,052 1,592,492 393,327 382,063
Proven plus probable 146,483 53,343 2,922,145 686,851 672,748
RESERVES RECONCILIATION
Crude and tight oil NGLs Natural gas Oil equivalent
Company gross (Mbbl) (Mbbl) (MMcf) (Mboe)
Proven producing
Opening balance, Jan. 1, 2015 87,990 12,136 656,299 209,509
Exploration discoveries -- -- -- --
Extensions and improved recovery 6,168 1,756 239,384 47,821
Technical revisions 7,279 1,946 91,908 24,544
Acquisitions 63 -- -- 63
Dispositions (3,839) (83) (52,114) (12,708)
Economic factors (3,767) (301) (13,684) (6,349)
Production (11,731) (2,642) (161,990) (41,372)
Ending balance, Dec. 31, 2015 82,163 12,712 759,803 221,509
Total proven opening balance,
Jan. 1, 2015 104,931 21,668 1,532,788 382,063
Exploration discoveries -- -- -- --
Extensions and improved recovery 7,510 4,286 191,010 43,631
Technical revisions 9,283 6,704 128,266 37,366
Acquisitions 63 -- -- 63
Dispositions (4,724) (260) (55,968) (14,312)
Economic factors (6,472) (705) (41,614) (14,113)
Production (11,731) (2,642) (161,990) (41,372)
Ending balance, Dec. 31, 2015 98,860 29,052 1,592,492 393,327
Proven plus probable
Opening balance, Jan. 1, 2015 152,035 40,454 2,881,551 672,748
Exploration discoveries -- -- -- --
Extensions and improved recovery 12,171 9,066 220,516 57,990
Technical revisions 8,616 7,903 116,551 35,944
Acquisitions 80 -- -- 80
Dispositions (8,805) (766) (82,391) (23,303)
Economic factors (5,882) (672) (52,092) (15,236)
Production (11,731) (2,642) (161,990) (41,372)
Ending balance, Dec. 31, 2015 146,483 53,343 2,922,145 686,851
Reserve life index
ARC's 2P RLI was 15.9 years at year-end 2015, while the proven RLI was 9.1 years based upon dividing the appropriate GLJ reserves category by ARC's 2016 production guidance midpoint of 118,000 boe per day, which is contingent upon the execution of a revised $390-million capital program for 2016. The 2P RLI has been maintained at greater than 15 years since year-end 2011, as a result of successful delineation and reserves growth of the Montney in northeast British Columbia. ARC's annual average production has increased from 73,954 boe per day in 2010 to 114,167 boe per day in 2015. The attached reserve life index table summarizes ARC's historical RLI.
RESERVE LIFE INDEX
2015 2014 2013 2012 2011
Total proven 9.1 8.5 9.1 10.5 10.7
Proven plus probable 15.9 15.0 15.5 17.5 17.0
Net present value summary
ARC's oil, natural gas and NGLs reserves were evaluated using GLJ's commodity price forecasts at Jan. 1, 2016. The net present value is prior to provision for interest, debt service charges, and general and administrative expenses. It should not be assumed that the NPV of cash flow estimated by GLJ represents the fair market value of the reserves. The NPV of ARC's reserves decreased relative to year-end 2014 due to a reduction in the Jan. 1, 2016, GLJ price forecast for both oil and natural gas as previously outlined. NPVs on both a before- and after-tax basis are presented in the attached net present value summary table.
NET PRESENT VALUE SUMMARY
NPV of cash flow Discounted Discounted Discounted Discounted
($ millions) Undiscounted at 5% at 10% at 15% at 20%
Before tax
Proven producing $4,670 $3,289 $2,533 $2,064 $1,748
Proven developed non-producing 206 158 128 107 92
Proven undeveloped 2,119 1,185 707 434 266
Total proven 6,995 4,632 3,367 2,605 2,106
Probable 6,199 3,046 1,772 1,142 785
Proven plus probable 13,194 7,678 5,139 3,748 2,891
After tax
Proven producing $4,030 $2,906 $2,279 $1,885 $1,615
Proven developed non-producing 151 116 94 79 68
Proven undeveloped 1,550 836 467 258 129
Total proven 5,732 3,858 2,841 2,222 1,812
Probable 4,538 2,206 1,258 789 524
Proven plus probable 10,269 6,063 4,098 3,011 2,336
At a 10-per-cent discount factor, and on a before-tax basis, proven producing reserves constitute 75 per cent of the total proven reserves cash flow (NPV10 before tax), while total proven reserves account for 66 per cent of the 2P reserves cash flow (NPV10 before tax).
Future development capital
FDC reflects the independent evaluator's best estimate of what it will cost to bring the proven undeveloped and probable reserves on production. Changes in forecast FDC occur annually as a result of development activities, acquisition and disposition activities, and changes in capital cost estimates based on improvements in well design and performance, as well as changes in service costs. FDC for total 2P reserves decreased to $2.7-billion at year-end 2015 from $3.6-billion at year-end 2014. The decrease in FDC in 2015 was predominantly attributed to the decrease in well and facility capital costs, the removal of capital associated with dispositions, and the removal of capital recognized at year-end 2014 that was executed in 2015.
The future development capital table outlines GLJ-estimated FDC required to bring total proven and total proven plus probable reserves on production.
FUTURE DEVELOPMENT CAPITAL
($ millions) Total proved Total proven plus probable
2016 $215 $465
2017 358 515
2018 385 603
2019 236 377
2020 83 148
Remainder 210 623
Total FDC, undiscounted 1,488 2,730
Total FDC, discounted at 10% 1,127 1,982
Finding, development and acquisition costs
ARC's 2015 F&D costs were $6.97 per boe and $8.20 per boe for 2P and proven reserves, respectively, excluding FDC (($2.82) per boe and 19 cents per boe, respectively, for 2P and proven reserves, including FDC). The downward change in FDC, which was greater than the 2015 capital spent, resulted in negative one-year 2P F&D costs, including FDC. Given the large reduction in FDC, one-year F&D costs, including FDC, are not meaningful. ARC's three-year average F&D costs were $10.36 per boe for 2P reserves and $14.13 per boe for proven reserves, excluding FDC. The low F&D costs are attributed to the high quality of ARC's portfolio of properties, strong results from ARC's development program, and meaningful reserves growth, notably at Tower, Sunrise and Dawson. ARC's 2015 F&D costs include approximately $6.7-million of spending on Crown lands, with no significant associated reserves or production associated with these acquisitions in the current year.
Including net acquisitions, ARC's 2015 finding, development and acquisition (FD&A) costs were $8.54 per boe for 2P reserves and $9 per boe for proven reserves, excluding FDC (($7.80) per boe and ($2.20) per boe, respectively, for 2P and proven reserves, including FDC). The three-year average FD&A costs were $11.88 per boe for 2P reserves and $15.98 per boe for proven reserves, excluding FDC. ARC's low FD&A costs reflect ARC's focus on high-quality assets, cost management, and allocation of resources and capital to high rate-of-return projects. ARC's 2015 FD&A costs include approximately $6.7-million of spending on Crown lands, with no significant associated reserves or production. There was no capital spending on acquisition of facilities or infrastructure, or on lands with significant associated reserves or production during 2015. Additionally, ARC's FD&A costs incorporate the net disposition of properties with associated reserves and production for approximately $74-million in 2015.
The attached reserves, capital expenditures and operating netbacks table highlights ARC's reserves, F&D costs, FD&A costs and the associated recycle ratios for the past three years.
RESERVES (COMPANY GROSS), CAPITAL EXPENDITURES AND
OPERATING NETBACKS
2015 2014 2013
Reserves (Mboe)
Proven producing 221,509 209,509 208,454
Total proven 393,327 382,063 373,976
Proven plus probable 686,851 672,748 633,864
Capital expenditures ($ millions)
Exploration and development $548.3 $1,007.8 $874.2
Net acquisitions and (dispositions) (74.4) 34.2 (53.4)
Total capital expenditures 473.9 1,042.0 820.8
Operating netbacks ($/boe)
Operating netback 16.69 33.01 28.57
Operating netback -- three-year average 25.91 28.86 27.24
FINDING AND DEVELOPMENT COSTS, EXCLUDING FDC
Company gross 2015 2014 2013
Proven producing
Reserve additions (million boe) 66.0 48.0 47.4
F&D costs ($/boe) $8.31 $20.99 $18.43
F&D recycle ratio 2.0 1.6 1.6
F&D costs -- three-year average ($/boe) 15.05 20.49 20.24
F&D recycle ratio -- three-year average 1.7 1.4 1.3
Total proven reserve additions (million boe) 66.9 55.0 50.1
F&D costs ($/boe) 8.20 18.32 17.45
F&D recycle ratio 2.0 1.8 1.6
F&D costs -- three-year average ($/boe) 14.13 17.32 14.18
F&D recycle ratio -- three-year average 1.8 1.7 1.9
Proven plus probable
Reserve additions (million boe) 78.7 87.5 68.4
F&D costs ($/boe) 6.97 11.51 12.79
F&D recycle ratio 2.4 2.9 2.2
F&D costs -- three-year average ($/boe) 10.36 11.15 8.24
F&D recycle ratio -- three-year average 2.5 2.6 3.3
FINDING AND DEVELOPMENT COSTS, INCLUDING FDC
Company gross 2015 2014 2013
Proven producing
Change in FDC ($ millions) $(53.5) $32.9 $42.0
Reserve additions (million boe) 66.0 48.0 47.4
F&D costs ($/boe) 7.49 21.68 19.32
F&D recycle ratio 2.2 1.5 1.5
F&D costs -- three-year average ($/boe) 15.19 21.09 20.60
F&D recycle ratio -- three-year average 1.7 1.4 1.3
Total proven change in FDC ($ millions) (535.6) 69.6 33.0
Reserve additions (million boe) 66.9 55.0 50.1
F&D costs ($/boe) 0.19 19.58 18.11
F&D recycle ratio 87.8 1.7 1.6
F&D costs -- three-year average ($/boe) 11.61 18.81 17.42
F&D recycle ratio -- three-year average 2.2 1.5 1.6
Proven plus probable
Change in FDC ($ millions) (770.3) 333.5 (90.2)
Reserve additions (million boe) 78.7 87.5 68.4
F&D costs ($/boe) (2.82) 15.32 11.47
F&D recycle ratio (5.9) 2.2 2.5
F&D costs -- three-year average ($/boe) 8.11 13.34 12.01
F&D recycle ratio -- three-year average 3.2 2.2 2.3
FINDING, DEVELOPMENT AND ACQUISITION COSTS, EXCLUDING FDC
Company gross 2015 2014 2013
Proven producing
Reserve additions, including
net acquisitions (dispositions) (MMboe) 53.4 41.7 42.2
FD&A costs ($/boe) $8.88 $24.97 $19.46
FD&A recycle ratio 1.9 1.3 1.5
FD&A costs -- three-year average ($/boe) 17.02 22.77 21.53
FD&A recycle ratio -- three-year average 1.5 1.3 1.3
Total proven reserve additions,
including net acquisitions (dispositions) (MMboe) 52.6 48.8 4.8
FD&A costs ($/boe) 9.00 21.37 18.31
FD&A recycle ratio 1.9 1.5 1.6
FD&A costs -- three-year average ($/boe) 15.98 18.99 15.00
FD&A recycle ratio -- three-year average 1.6 1.5 1.8
Proven plus probable
Reserve additions, including
net acquisitions (dispositions) (MMboe) 55.5 79.6 61.6
FD&A costs ($/boe) 8.54 13.10 13.32
FD&A recycle ratio 2.0 2.5 2.1
FD&A costs -- three-year average ($/boe) 11.88 11.94 8.39
FD&A recycle ratio -- three-year average 2.2 2.4 3.2
FINDING, DEVELOPMENT AND ACQUISITION COSTS, INCLUDING FDC
Company gross 2015 2014 2013
Proven producing
Change in FDC ($ millions) $(63.4) $31.0 $41.6
Reserve additions, including
net acquisitions (dispositions) (MMboe) 53.4 41.7 42.2
FD&A costs ($/boe) 7.69 25.71 20.44
FD&A recycle ratio 2.2 1.3 1.4
FD&A costs -- three-year average ($/boe) 17.09 23.41 21.93
FD&A recycle ratio -- three-year average 1.5 1.2 1.2
Total proven change in FDC ($ millions) (589.5) 69.2 38.9
Reserve additions, including
net acquisitions (dispositions) (MMboe) 52.6 48.8 44.8
FD&A costs ($/boe) (2.20) 22.79 19.18
FD&A recycle ratio (7.6) 1.4 1.5
FD&A costs -- three-year average ($/boe) 12.69 20.74 18.57
FD&A recycle ratio -- three-year average 2.0 1.4 1.5
Proven plus probable
Change in FDC ($ millions) (906.2) 333.2 (76.7)
Reserve additions, including
net acquisitions (dispositions) (MMboe) 55.5 79.6 61.6
FD&A costs ($/boe) (7.80) 17.29 12.07
FD&A recycle ratio (2.1) 1.9 2.4
FD&A costs -- three-year average ($/boe) 8.58 14.4 412.47
FD&A recycle ratio -- three-year average 3.0 2.0 2.2
Northeast B.C. Montney resources evaluation
Amendments to NI 51-101 that came into effect on July 1, 2015, require significant changes to the way resources are disclosed relative to prior years. The most significant changes require:
The classification of contingent resources into the following specified project maturity subclasses. Those that apply to ARC's resources include:
- Development pending;
- Development unclarified;
- Development not viable;
-
Changes to the product types, including the addition of new product types and providing new definitions for some existing product types;
- The disclosure of the risked, best estimate of the contingent resources volumes for each product type;
- The disclosure of the risked NPV of future net revenues for any disclosed development pending contingent resources, calculated using forecast prices and costs for each product type, on a before- and after-tax basis using discount rates of 0 per cent, 5 per cent, 10 per cent, 15 per cent and 20 per cent;
-
The disclosure of the chance of development risk for each project maturity subclass the issuer discloses;
-
The disclosure of the estimated total cost to achieve commercial production, the estimated date of first commercial production and the recovery technology to be used.
The Montney formation in northeast British Columbia and Alberta has been identified as a world-class unconventional natural gas resource play with the potential for significant volumes of recoverable resources. The area includes dry gas, liquids-rich gas and tight oil development opportunities. It is one of the largest and lowest-cost natural gas resource plays in North America. ARC has a significant presence in northeast British Columbia and across the provincial border at Pouce Coupe, with a land position of 728 net sections, located primarily in the most prospective areas of the play.
GLJ was commissioned to conduct an independent resources evaluation for ARC's lands in the northeast B.C. Montney region, including Dawson, Parkland/Tower, Sunrise/Sunset, Sundown, Septimus, Attachie, Red Creek and Blueberry in northeast British Columbia, and Pouce Coupe just across the provincial border in Alberta. The resources evaluation was effective Dec. 31, 2015, based on GLJ forecast pricing at Jan. 1, 2016. All references in the following discussion to TPIIP, discovered petroleum initially in place (DPIIP) and ECR are in reference to the evaluated areas included in the independent resources evaluation.
The evaluation reaffirmed that ARC's northeast B.C. Montney assets provide a significant long-term growth opportunity with considerable potential reserves, extending well beyond existing booked reserves and even the current estimates of the ECR. ARC's northeast B.C. Montney assets provide optionality for future growth through commodity price cycles given the diversity of ARC's Montney landholdings with exposure to liquids-rich natural gas, crude oil and dry natural gas. ARC believes that the concentrated nature of the assets will result in additional upside based on expected capital efficiencies.
ARC's 2015 capital development program was primarily focused on Montney development, which was inclusive of crude oil, liquids-rich gas and dry gas opportunities. In northeast British Columbia, ARC's capital development program consisted of drilling 48 gross operated wells (48 net wells), composed of 22 tight oil wells at Tower, five liquids-rich wells (three wells at Attachie and two wells at Parkland) and 21 shale gas wells (14 wells at Sunrise and seven wells at Dawson).
TPIIP for the shale-gas-bearing lands in the evaluated areas increased 34 per cent relative to 2014 to 90 trillion cubic feet. The 2015 drilling program resulted in a 17-per-cent increase of DPIIP for the evaluated areas to 41.4 trillion cubic feet. Growth in shale gas TPIIP and DPIIP is primarily attributed to 2015 land acquisition activity in Sunrise and Attachie.
Shale gas ECR was evaluated on an unrisked and risked basis in 2015 and was subdivided into the maturity subclasses of development pending and development unclarified. The risked development pending shale gas ECR totalled 2.4 trillion cubic feet, and risked development unclarified shale gas ECR totalled 3.3 trillion cubic feet. The risked prospective shale gas ECR totalled 5.3 trillion cubic feet.
NGLs ECR was also evaluated on an unrisked and risked basis in 2015 and was subdivided into the maturity subclasses of development pending and development unclarified. The risked development pending NGLs ECR totalled 36.9 million barrels, and risked development unclarified NGLs ECR totalled 201 million bbl. The risked prospective NGLs ECR totalled 319 million bbl.
On the tight-oil-bearing lands at Tower, Red Creek and Attachie, TPIIP increased 315 per cent to 9,688 million bbl, and DPIIP increased 217 per cent to 5,736 million bbl. The increase in tight oil TPIIP and DPIIP is attributed to land acquisition activity at Attachie, as well as the conversion of the 2014 classification of Attachie East lands, from a gas resource to an oil resource in the Upper Montney formation.
Tight oil ECR was evaluated on an unrisked and risked basis in 2015 and was subdivided into the maturity subclasses of development pending and development unclarified. The risked development pending tight oil ECR totalled 33 million bbl, and risked development unclarified tight oil ECR totalled 129 million bbl. The risked prospective tight oil ECR totalled 81 million bbl.
Risking of the contingent resources included a quantitative assessment of the economic status, the recovery technology status, the project evaluation scenario status and the development time frame. Risking of the prospective resources included a quantitative assessment of these same factors, as wells as a quantitative assessment of the chance of discovery.
SHALE GAS RESOURCES
(trillion cubic feet)
2015 2014
Total petroleum initially in place 90.0 67.4
Discovered petroleum initially in place 41.4 35.4
Undiscovered petroleum initially in place (UPIIP) 48.6 32.0
TIGHT OIL RESOURCES
(million bbl)
2015 2014
Total petroleum initially in place 9,688 2,334
Discovered petroleum initially in place 5,736 1,807
Undiscovered petroleum initially in place 3,952 527
RESERVES AND RISKED AND UNRISKED ECR IN 2015
Chance of development Best estimate unrisked Best estimate risked
Shale gas (tcf)
Reserves 100% 2.6 2.6
Development pending ECR 92% 2.6 2.4
Development unclarified ECR 76% 4.4 3.3
NGLs (million bbl)
Reserves 100% 42.3 42.3
Development pending ECR 94% 39.1 36.9
Development unclarified ECR 76% 265.1 200.9
Tight oil (million bbl)
Reserves 100% 22.7 22.7
Development pending ECR 95% 34.8 33.1
Development unclarified ECR 79% 163.2 129.0
An estimate of risked NPV of future net revenues of the development pending contingent resources subclass only is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of ARC proceeding with the required investment. It includes contingent resources that are considered too uncertain with respect to the chance of development to be classified as reserves. There is uncertainty that the risked NPV of future net revenue will be realized. The other subclasses of resources are not included in this NPV, and therefore this is not reflective of the value of the resource base.
RISKED AND UNRISKED ECR DEVELOPMENT PENDING IN 2015
Chance of development Best estimate unrisked Best estimate risked
Shale gas (tcf) 92% 2.6 2.4
NGLs (million bbl) 94% 39.1 36.9
Tight oil (million bbl) 95% 34.8 33.1
Before-tax NPV ($ millions)
Undiscounted $10,624 $9,890
Discounted at 5% 3,447 3,203
Discounted at 10% 1,247 1,154
Discounted at 15% 443 406
Discounted at 20% 114 100
After-tax NPV ($ millions)
Undiscounted $7,728 $7,194
Discounted at 5% 2,431 2,258
Discounted at 10% 812 750
Discounted at 15% 229 208
Discounted at 20% (3) (8)
The estimated cost to bring on commercial production the development pending contingent resources for all three product types is approximately $3.8-billion (discounted at 10 per cent is approximately $1.5-billion). The expected timeline to bring these resources onto production is between two and 10 years. The ECR is expected to be recovered using the same technology in horizontal drilling and multistage fracturing that ARC has already proved to be effective in the Montney in northeast British Columbia.
PROSPECTIVE RESOURCES IN 2015
Chance of commerciality Best estimate unrisked Best estimate risked
Shale gas (tcf) 49% 10.7 5.3
NGLs (million bbl) 46% 690.8 319.3
Tight oil (million bbl) 68% 119.0 81.3
Based upon the foregoing analysis, as well as ARC's expertise in the Montney formation in northeast British Columbia, it is expected that significant additional reserves will be developed in the future with continued drilling success on currently undeveloped Montney acreage, together with further development, completions refinements and improved economic conditions. Historical drilling success and recoveries on the more fully developed Montney acreage, abundant well log and production test data, and the application of increased drilling densities support ARC's belief that significant additional resources will be recovered. Continuous development through multiyear exploration and development programs and significant levels of future capital expenditures are required for additional resources to be recovered in the future. The principal risks that would inhibit the recovery of additional reserves relate to the potential for variations in the quality of the Montney formation, where minimal well data currently exist, access to the capital which would be required to develop the resources, low commodity prices that would curtail the economics of development and the future performance of wells, regulatory approvals, access to the required services at the appropriate cost, and the effectiveness of fracking technology and applications. For ECR to be converted to reserves, management and the board need to ascertain commercial production rates, then develop firm plans, including timing, infrastructure and the commitment of capital. Confirmation of commercial productivity is generally required before the company can prepare firm development plans and commit required capital for the development of the ECR. Additional contingencies are related to the current lack of infrastructure required to develop the resources in a relatively quick time frame. As continued delineation occurs, some resources currently classified as ECR are expected to be reclassified to reserves.
We seek Safe Harbor.
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