CALGARY, Feb. 8, 2017 /CNW/ – (ARX – TSX) ARC Resources Ltd. (“ARC”) is pleased to report its 2016 year-end reserves and resources information.
“ARC delivered another year of outstanding reserves results, replacing 260 per cent of 2016 produced reserves through development activities at low finding and development costs of $4.02 per boe for proved plus probable reserves. Exceptional well performance from our Montney assets resulted in positive technical revisions and material reserves growth in 2016. These results highlight the increasing depth of ARC’s low-cost Montney asset base and the strong technical expertise of our team,” said Myron Stadnyk, President and CEO. “An updated Independent Resources Evaluation for our northeast British Columbia and Pouce Coupe assets also saw significant growth, with now greater than 100 Tcf of total shale gas initially-in-place and more than 10 billion barrels of total tight oil initially-in-place identified across ARC’s Montney lands. Coupled with our strong balance sheet and excellent operating and capital efficiencies, ARC is in an enviable position as we continue to develop these world-class assets and gain greater confidence in initiating larger-scale development projects across our Montney portfolio.”
HIGHLIGHTS
- Replaced 260 per cent of total 2016 production (1), adding 113.5 MMboe of proved plus probable (“2P”) reserves through development activities. Over the last nine years, ARC has replaced an average of 200 per cent or greater produced reserves through development activities.
- Positive technical revisions of 33 MMboe (2P) were realized, predominantly in Sunrise and Dawson, reflecting the strong well performance of ARC’s Montney assets.
- Proved developed producing (“PDP”) reserves decreased from 222 MMboe to 212 MMboe. The net decrease in PDP reserves was driven by dispositions, notably ARC’s non-core Saskatchewan asset sale which accounted for 21 MMboe of the total 24 MMboe divested at year-end 2016.
- Total proved reserves increased by eight per cent from 393 MMboe to 426 MMboe, and 2P reserves increased by seven per cent from 687 MMboe to 737 MMboe.
- Replaced 289 per cent of 2016 natural gas production, adding 0.5 Tcf of 2P natural gas reserves. Replaced 725 per cent of natural gas liquids (“NGLs”) production, adding 21.0 MMbbl of 2P NGLs reserves. Replaced 76 per cent of 2016 oil production, adding 8.7 MMbbl of 2P oil reserves. Replaced 97 per cent of 2016 oil produced, disregarding production from ARC’s Saskatchewan assets which were sold in the fourth quarter of 2016.
- Material reserves growth was realized in ARC’s Montney assets, particularly in Sunrise, Dawson, Parkland/Tower, Attachie, and Ante Creek.
- Finding and Development (“F&D”) costs (1) were $4.02 per boe for 2P reserves, $5.15 per boe for proved reserves and $10.46 per boe for proved producing reserves, excluding Future Development Capital (“FDC”). Significant NE BC Montney reserve additions combined with capital reductions contributed to the 42 per cent reduction in 2P F&D costs relative to 2015.
- FDC increased by $25 million compared to year-end 2015, to total $2.8 billion at year-end 2016. Adds due to additional development activities in the Montney were offset by the FDC reduction associated with dispositions that occurred in 2016.
- ARC updated an Independent Resources Evaluation (the “Resources Evaluation” or “Independent Resources Evaluation”) for its lands in the NE BC Montney region, including lands at Pouce Coupe in Alberta. The updated evaluation realized an increase in the identified resource base on ARC’s NE BC Montney lands. The shale gas Total Petroleum Initially-in-Place (“TPIIP”) increased 13 per cent from 90.0 Tcf in 2015 to 101.5 Tcf in 2016 and tight oil TPIIP increased nine per cent from 9.7 billion barrels of oil in 2015 to 10.5 billion barrels in 2016 (2).
- Best Estimate Risked Development Pending resources increased to 529 MMboe at year-end 2016 from 471 MMboe at year-end 2015, while before-tax present value, discounted at 10 per cent, increased to $1.8 billion from $1.2 billion year-over-year.
(1) |
“Reserve replacement” and “Finding and Development costs” or “F&D costs” do not have standardized meanings. See “Information Regarding Disclosure on Oil and Gas Reserves, Resources and Operational Information” contained in this news release. |
(2) |
The year-end 2016 Resources Evaluation complies with current Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) guidelines. The Resources Evaluation volumes provided are the “Best Estimate” case. Year-end 2016 and 2015 TPIIP estimates utilize a one per cent porosity cut-off for shale gas based upon “Best Estimate” case. Estimates for year-end 2016 were determined using a one per cent porosity cut-off, and for year-end 2015 using a three per cent porosity cut-off for tight oil based upon “Best Estimate” case. |
2016 INDEPENDENT RESERVES EVALUATION
GLJ Petroleum Consultants (“GLJ”) conducted an Independent Reserves Evaluation (the “Reserves Evaluation” or “Independent Reserves Evaluation”) effective December 31, 2016, which was prepared in accordance with definitions, standards and procedures contained in the COGE Handbook and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). The reserves evaluation was based on GLJ forecast pricing and foreign exchange rates at January 1, 2017, as outlined in Table 1 below.
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. In addition to the detailed information disclosed in this news release, more detailed information will be included in ARC’s Annual Information Form (“AIF”) for the year ended December 31, 2016, which will be available on ARC’s website at www.arcresources.com and filed on SEDAR at www.sedar.com on or before March 31, 2017.
Based on this Independent Reserves Evaluation, ARC’s reserves profile as at December 31, 2016 is summarized below:
- Seven per cent increase in 2016 2P reserves to 737 MMboe compared to 687 MMboe of 2P reserves at year-end 2015. 2P reserves are comprised of 3.2 Tcf of natural gas, 124 MMbbl of oil and 72 MMbbl of NGLs at year-end 2016. The NGLs are comprised of 54 per cent condensate (39 MMbbl), 40 per cent propane (29 MMbbl), and six per cent butane (4 MMbbl).
- 113.5 MMboe of 2P reserve additions from development activities (including revisions), before net acquisitions and dispositions of negative 20.5 MMboe and 2016 production of 43.4 MMboe. Technical revisions of 32.5 MMboe more than offset the removal of 3.4 MMboe due to economic factor revisions resulting from the decrease in commodity price forecasts since year-end 2015.
- Replaced 260 per cent of total 2016 production, adding 113.5 MMboe of 2P reserves through development activities, with 2016 production of 43.4 MMboe.
- Total proved reserves account for 58 per cent of 2P reserves.
- PDP reserves represent 50 per cent of total proved reserves and 29 per cent of 2P reserves.
- Oil and NGLs comprise 27 per cent of 2P reserves and natural gas comprises 73 per cent of 2P reserves, using the commonly accepted boe conversion ratio of six Mcf to one barrel.
- Additions from development activities resulted in increased reserves, hand-in-hand with increased FDC for these development activities, resulting in one-year 2P F&D costs, including FDC, of $6.10 per boe for 2016, and $6.48 per boe for the three-year average. Proved F&D costs, including FDC, were $11.71 per boe for 2016 and $10.11 per boe for the three-year average.
- Strong 2P reserve life index (“RLI”) (1) of 16.4 years at year-end 2016, up from 15.9 years at year-end 2015. The increase in RLI is attributed to strong reserves growth in 2016. For details on ARC’s 2017 production guidance, see the February 8, 2017 news release entitled, “ARC Resources Ltd. Announces Fourth Quarter and Year-end 2016 Results as It Increases Capital Investment in Multi-year, Large-scale Development Projects at Dawson, Parkland/Tower, and Sunrise”.
- Recycle ratio (1) of 3.4 times and 2.9 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, which are based on current and three-year average operating netbacks (2) of $13.59 per boe and $20.93 per boe, respectively.
- Abandonment and reclamation costs decreased from $527 million (undiscounted) at year-end 2015 to $462 million (undiscounted) at year-end 2016. These costs have been included in the 2P reserves, which account for the abandonment and reclamation of all wells to which reserves have been attributed.
- Acquisition of working interests in Pembina Cardium in 2016 and disposition of ARC’s non-core Saskatchewan assets at the end of the fourth quarter of 2016 resulted in a net reduction in PDP reserves of approximately 7 MMboe.
(1) |
“Reserve life index” or “RLI” and “recycle ratio” do not have standardized meanings. See “Information Regarding Disclosure on Oil and Gas Reserves, Resources and Operational Information” contained in this news release. |
(2) |
“Operating netback” is a non-GAAP measure and does not have a standardized meaning under IFRS. See “Non-GAAP Measures” contained within ARC’s Management’s Discussion and Analysis (“MD&A”). |
Table 1
GLJ Price Forecast |
WTI Crude Oil |
Edmonton Light Oil |
AECO Natural Gas |
Foreign Exchange |
|||||||||||
at January 1 |
(US$/bbl) |
(Cdn$/bbl) |
(Cdn$/MMBtu) |
(US$/Cdn$) |
|||||||||||
2017 |
2016 |
2017 |
2016 |
2017 |
2016 |
2017 |
2016 |
||||||||
2017 |
55.00 |
52.00 |
69.33 |
64.00 |
3.46 |
3.27 |
0.750 |
0.750 |
|||||||
2018 |
59.00 |
58.00 |
72.26 |
68.39 |
3.10 |
3.45 |
0.775 |
0.775 |
|||||||
2019 |
64.00 |
64.00 |
75.00 |
73.75 |
3.27 |
3.63 |
0.800 |
0.800 |
|||||||
2020 |
67.00 |
70.00 |
76.36 |
78.79 |
3.49 |
3.81 |
0.825 |
0.825 |
|||||||
2021 |
71.00 |
75.00 |
78.82 |
82.35 |
3.67 |
3.90 |
0.850 |
0.850 |
|||||||
2022 |
74.00 |
80.00 |
82.35 |
88.24 |
3.86 |
4.10 |
0.850 |
0.850 |
|||||||
2023 |
77.00 |
85.00 |
85.88 |
94.12 |
4.05 |
4.30 |
0.850 |
0.850 |
|||||||
2024 |
80.00 |
87.88 |
89.41 |
96.48 |
4.16 |
4.50 |
0.850 |
0.850 |
|||||||
2025 |
83.00 |
89.63 |
92.94 |
98.41 |
4.24 |
4.60 |
0.850 |
0.850 |
|||||||
2026 (1) |
86.05 |
95.61 |
4.32 |
0.850 |
0.850 |
||||||||||
Escalate thereafter at |
‘+2% / year |
‘+2% / year |
‘+2% / year |
‘+2% / year |
‘+2% / year |
‘+2% / year |
0.850 |
0.850 |
(1)Â |
Escalated at two per cent per year starting in 2026 in the January 1, 2017 GLJ price forecast with the exception of foreign exchange, which remains flat. |
Table 2
Reserves Summary (1) |
Crude and Tight Oil (2) |
NGLs |
Natural Gas (3) |
2016 Oil |
2015 Oil |
||||
Company Gross |
(Mbbl) |
(Mbbl) |
(MMcf) |
(Mboe) |
(Mboe) |
||||
Proved Producing |
66,956 |
13,040 |
794,069 |
212,341 |
221,509 |
||||
Proved Developed Non-Producing |
1,581 |
916 |
50,599 |
10,930 |
12,062 |
||||
Proved Undeveloped |
20,247 |
24,108 |
949,808 |
202,656 |
159,755 |
||||
Total Proved |
88,783 |
38,064 |
1,794,476 |
425,927 |
393,327 |
||||
Proved plus Probable |
123,996 (4) |
71,504 |
3,247,395 (5) |
736,733 |
686,851 |
(1) |
Amounts may not add due to rounding. |
(2) |
Crude and Tight Oil includes product types of light and medium crude oil, tight oil and heavy crude oil. |
(3) |
Natural Gas includes product types of shale gas and conventional natural gas. |
(4) |
Proved plus Probable Crude and Tight Oil closing balance by percentage weighting of product type: approximately 62 per cent light and medium crude oil, 36 per cent tight oil and two per cent heavy crude oil. |
(5) |
Proved plus Probable Natural Gas closing balance by percentage weighting of product type: approximately 97 per cent shale gas and three per cent conventional natural gas. |
Table 3
Reserves Reconciliation (1) |
Crude and Tight |
NGLs |
Natural Gas (3) |
Oil Equivalent |
|||||
Company Gross |
(Mbbl) |
(Mbbl) |
(MMcf) |
(Mboe) |
|||||
Proved Producing |
|||||||||
Opening Balance, January 1, 2016 |
82,163 |
12,712 |
759,803 |
221,509 |
|||||
 Exploration Discoveries |
— |
— |
— |
— |
|||||
 Extensions and Improved Recovery (4) |
4,225 |
1,498 |
95,103 |
21,573 |
|||||
 Technical Revisions |
2,216 |
1,790 |
123,802 |
24,640 |
|||||
 Acquisitions |
11,561 |
526 |
12,683 |
14,200 |
|||||
 Dispositions |
(21,371) |
(412) |
(12,140) |
(23,807) |
|||||
 Economic Factors |
(446) |
(194) |
(11,923) |
(2,627) |
|||||
 Production |
(11,392) |
(2,879) |
(173,259) |
(43,148) |
|||||
Ending Balance, December 31, 2016 |
66,956 |
13,040 |
794,069 |
212,341 |
|||||
Total Proved |
|||||||||
Opening Balance, January 1, 2016 |
98,860 |
29,052 |
1,592,492 |
393,327 |
|||||
 Exploration Discoveries |
— |
— |
— |
— |
|||||
 Extensions and Improved Recovery (4) |
11,836 |
4,819 |
196,415 |
49,391 |
|||||
 Technical Revisions |
2,794 |
7,176 |
192,353 |
42,030 |
|||||
 Acquisitions |
12,468 |
573 |
13,863 |
15,352 |
|||||
 Dispositions |
(25,044) |
(469) |
(15,885) |
(28,161) |
|||||
 Economic Factors |
(740) |
(208) |
(11,503) |
(2,865) |
|||||
 Production |
(11,392) |
(2,879) |
(173,259) |
(43,148) |
|||||
Ending Balance, December 31, 2016 |
88,783 |
38,064 |
1,794,476 |
425,927 |
|||||
Proved plus Probable |
|||||||||
Opening Balance, January 1, 2016 |
146,483 |
53,343 |
2,922,145 |
686,851 |
|||||
 Exploration Discoveries |
— |
— |
— |
— |
|||||
 Extensions and Improved Recovery (4) |
10,195 |
11,462 |
376,732 |
84,445 |
|||||
 Technical Revisions |
(897) |
9,652 |
142,685 |
32,535 |
|||||
 Acquisitions |
16,004 |
740 |
17,901 |
19,727 |
|||||
 Dispositions |
(35,812) |
(652) |
(22,687) |
(40,246) |
|||||
 Economic Factors |
(584) |
(160) |
(16,123) |
(3,431) |
|||||
 Production |
(11,392) |
(2,879) |
(173,259) |
(43,148) |
|||||
Ending Balance, December 31, 2016 |
123,996 (5) |
71,504 |
3,247,395 (6) |
736,733 |
(1) |
Amounts may not add due to rounding. |
(2) |
Crude and Tight Oil includes product types of light and medium crude oil, tight oil and heavy crude oil. |
(3) |
Natural Gas includes product types of shale gas and conventional natural gas. |
(4) |
Reserves additions for infill drilling, improved recovery, and extensions are combined and reported as “Extensions and Improved Recovery”. |
(5) |
Proved plus Probable Crude and Tight Oil closing balance by percentage weighting of product type: approximately 62 per cent light and medium crude oil, 36 per cent tight oil and two per cent heavy crude oil. |
(6) |
Proved plus Probable Natural Gas closing balance by percentage weighting of product type: approximately 97 per cent shale gas and three per cent conventional natural gas. |
Reserve Life Index
ARC’s 2P RLI was 16.4 years at year-end 2016, while the proved RLI was 9.6 years based upon dividing the appropriate GLJ reserves category by ARC’s 2017 production guidance midpoint of 121,000 boe per day, which is contingent upon the execution of a $750 million capital program for 2017. The 2P RLI has been maintained at greater than 15 years since year-end 2010, as a result of successful delineation and reserves growth of the Montney in northeast British Columbia. ARC’s annual average production has increased from 83,416 boe per day in 2011 to 118,671 boe per day in 2016. Table 4 summarizes ARC’s historical RLI.
Table 4
Reserve Life Index |
2016 (1) |
2015 |
2014 |
2013 |
2012 |
|||||
Total Proved |
9.6 |
9.1 |
8.5 |
9.1 |
10.5 |
|||||
Proved plus Probable |
16.4 |
15.9 |
15.0 |
15.5 |
17.5 |
|||||
(1) Based on production guidance midpoint of 121,000 boe per day for 2017. |
Net Present Value Summary
ARC’s oil, natural gas and NGLs reserves were evaluated using GLJ’s commodity price forecasts at January 1, 2017. The net present value (“NPV”) is prior to provision for interest, debt service charges, and general and administrative expenses. It should not be assumed that the NPV of future net revenue estimated by GLJ represents the fair market value of the reserves. The NPV of ARC’s reserves increased relative to year-end 2015 due to material reserve adds in 2016. NPVs on both a before- and after-tax basis are presented in Table 5.
Table 5
NPV of Future Net Revenue (1)(2) |
Discounted |
Discounted |
Discounted |
Discounted |
|||||||
($ millions) |
Undiscounted |
at 5% |
at 10% |
at 15% |
at 20% |
||||||
Before-tax |
|||||||||||
Proved Producing |
4,626 |
3,296 |
2,585 |
2,148 |
1,852 |
||||||
Proved Developed Non-Producing |
154 |
116 |
91 |
75 |
63 |
||||||
Proved Undeveloped |
2,729 |
1,593 |
982 |
615 |
380 |
||||||
Total Proved |
7,509 |
5,005 |
3,659 |
2,839 |
2,295 |
||||||
Probable |
6,531 |
3,451 |
2,174 |
1,519 |
1,134 |
||||||
Proved plus Probable |
14,040 |
8,457 |
5,832 |
4,358 |
3,429 |
||||||
After-tax (3)(4) |
|||||||||||
Proved Producing |
3,827 |
2,786 |
2,218 |
1,863 |
1,619 |
||||||
Proved Developed Non-Producing |
112 |
84 |
66 |
54 |
45 |
||||||
Proved Undeveloped |
2,002 |
1,123 |
647 |
362 |
179 |
||||||
Total Proved |
5,941 |
3,993 |
2,931 |
2,278 |
1,843 |
||||||
Probable |
4,778 |
2,511 |
1,565 |
1,079 |
795 |
||||||
Proved plus Probable |
10,719 |
6,504 |
4,496 |
3,358 |
2,638 |
(1) |
Amounts may not add due to rounding. |
(2) |
Based on NI 51-101 net interest reserves and GLJ price forecasts and costs at January 1, 2017. |
(3) |
Based on ARC’s estimated tax pools at year-end 2016. |
(4) |
The after-tax NPV of the future net revenue attributed to ARC’s oil and natural gas properties reflects the tax burden on the properties on a standalone basis. It does not consider the business entity tax-level situation or tax planning, nor does it provide an estimate of the value at the level of the business entity, which may be significantly different. ARC’s audited consolidated financial statements and notes and MD&A should be consulted for information at the business entity level. |
At a 10 per cent discount factor, and on a before-tax basis, the future net revenue attributed to the proved producing reserves constitutes 71 per cent of the future net revenue attributed to the total proved reserves (NPV10 before-tax), while the future net revenue attributed to the total proved reserves accounts for 63 per cent of the future net revenue attributed to the 2P reserves (NPV10 before-tax).
Future Development Capital
FDC reflects the independent evaluator’s best estimate of what it will cost to bring the proved and probable developed and undeveloped 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 increased by $25 million compared to year-end 2015, to total $2.8 billion at year-end 2016. Adds due to additional development activities in the Montney were offset by the FDC reduction associated with dispositions that occurred in 2016.
Table 6 outlines GLJ estimated FDC required to bring total proved and total 2P reserves on production.
Table 6
Future Development Capital (1)(2) |
||||
($ millions) |
Total Proved |
Total Proved plus Probable |
||
2017 |
542 |
662 |
||
2018 |
530 |
639 |
||
2019 |
404 |
524 |
||
2020 |
151 |
279 |
||
2021 |
94 |
211 |
||
Remainder |
187 |
441 |
||
Total FDC, Undiscounted |
1,908 |
2,755 |
||
Total FDC, Discounted at 10% |
1,553 |
2,169 |
(1) |
Amounts may not add due to rounding. |
(2) |
FDC as per GLJ Independent Reserves Evaluation as of December 31, 2016 and based on GLJ forecast pricing at January 1, 2017. |
ARC’s 2017 capital budget is $750 million, 13 per cent higher than the proved plus probable FDC forecast for 2017. The total proved plus probable FDC, undiscounted, is less than four times ARC’s 2017 capital budget. For details on ARC’s 2017 capital budget, see the February 8, 2017 news release entitled, “ARC Resources Ltd. Announces Fourth Quarter and Year-end 2016 Results as It Increases Capital Investment in Multi-year, Large-scale Development Projects at Dawson, Parkland/Tower, and Sunrise”.
Finding, Development and Acquisition Costs
ARC’s 2016 F&D costs were $4.02 per boe and $5.15 per boe for 2P and proved reserves, respectively, excluding FDC ($6.10 per boe and $11.71 per boe, respectively, for 2P and proved reserves, including FDC). ARC’s three-year average F&D costs were $7.19 per boe for 2P reserves and $9.56 per boe for proved reserves, excluding FDC. The low F&D costs are attributed to the high quality of ARC’s portfolio of assets, strong results from ARC’s development program, and meaningful reserves growth, notably at Sunrise, Dawson and Tower. ARC’s 2016 F&D costs include approximately $3 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 2016 Finding, Development and Acquisition (“FD&A”) (1) costs were $(0.82) per boe for 2P reserves and $(1.01) per boe for proved reserves, excluding FDC ($(0.55) per boe and $4.53 per boe, respectively, for 2P and proved reserves, including FDC). Due to the disposition of ARC’s non-core Saskatchewan assets, the annual capital including net dispositions was negative in 2016, which resulted in negative one-year 2P F&D costs, including FDC. Given the negative annual capital, one-year F&D costs, including FDC, are not meaningful. The three-year average FD&A costs were $6.31 per boe for 2P reserves and $8.13 per boe for proved 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 investment to high rate of return projects. ARC’s 2016 FD&A costs include approximately $3 million of spending on Crown lands, with no significant associated reserves or production. Additionally, ARC’s FD&A costs incorporate the net disposition of properties with associated reserves and production for approximately $532 million in 2016.
(1) “Finding, development and acquisition costs” or “FD&A costs” does not have a standardized meaning. See “Information Regarding Disclosure on Oil and Gas Reserves, Resources and Operational Information” contained in this news release.
Table 7 highlights ARC’s reserves, F&D costs, FD&A costs and the associated recycle ratios for the past three years.
Table 7
Reserves (Company Gross), Capital Expenditures and |
|||||||
Operating Netbacks (1)(2) |
2016 |
2015 |
2014 |
||||
Reserves (Mboe) |
|||||||
Proved Producing |
212,341 |
221,509 |
209,509 |
||||
Total Proved |
425,927 |
393,327 |
382,063 |
||||
Proved plus Probable |
736,733 |
686,851 |
672,748 |
||||
Capital Expenditures ($ millions) |
|||||||
Exploration and Development |
456.1 |
548.3 |
1,007.8 |
||||
Net Property Acquisitions (Dispositions) |
(532.5) |
(74.4) |
34.2 |
||||
Total Capital Expenditures |
(76.4) |
473.9 |
1,042.0 |
||||
Operating Netbacks ($/boe) |
|||||||
Operating Netback |
13.59 |
16.69 |
33.01 |
||||
Operating Netback – Three-Year Average |
20.93 |
25.91 |
28.86 |
(1) |
Amounts may not add due to rounding. |
(2) |
“Operating netback” is a non-GAAP measure and does not have a standardized meaning under IFRS. See “Non-GAAP Measures” contained within ARC’s MD&A. |
Table 7a
Finding and Development Costs, excluding FDC (1)(2)(3) |
|||||||||
Company Gross |
2016 |
2015 |
2014 |
||||||
Proved Producing |
|||||||||
Reserve Additions (MMboe) |
43.6 |
66.0 |
48.0 |
||||||
F&D Costs ($/boe) |
10.46 |
8.31 |
20.99 |
||||||
F&D Recycle Ratio |
1.3 |
2.0 |
1.6 |
||||||
F&D Costs – Three-Year Average ($/boe) |
12.77 |
15.05 |
20.49 |
||||||
F&D Recycle Ratio – Three-Year Average |
1.6 |
1.7 |
1.4 |
||||||
Total Proved |
|||||||||
Reserve Additions (MMboe) |
88.6 |
66.9 |
55.0 |
||||||
F&D Costs ($/boe) |
5.15 |
8.20 |
18.32 |
||||||
F&D Recycle Ratio |
2.6 |
2.0 |
1.8 |
||||||
F&D Costs – Three-Year Average ($/boe) |
9.56 |
14.13 |
17.32 |
||||||
F&D Recycle Ratio – Three-Year Average |
2.2 |
1.8 |
1.7 |
||||||
Proved plus Probable |
|||||||||
Reserve Additions (MMboe) |
113.5 |
78.7 |
87.5 |
||||||
F&D Costs ($/boe) |
4.02 |
6.97 |
11.51 |
||||||
F&D Recycle Ratio |
3.4 |
2.4 |
2.9 |
||||||
F&D Costs – Three-Year Average ($/boe) |
7.19 |
10.36 |
11.15 |
||||||
F&D Recycle Ratio – Three-Year Average |
2.9 |
2.5 |
2.6 |
(1) |
F&D costs take into account reserves revisions during the year on a per boe basis. |
(2) |
The aggregate of the exploration and development costs incurred in the financial year and the changes during that year in estimated future development costs may not reflect the total F&D costs related to reserves additions for that year. |
(3) |
 “Finding and development recycle ratio” or “F&D recycle ratio” does not have a standardized meaning. See “Information Regarding Disclosure on Oil and Gas Reserves, Resources and Operational Information” contained in this news release. |
Table 7b
Finding and Development Costs, including FDC (1)(2) |
|||||||||
Company Gross |
2016 |
2015 |
2014 |
||||||
Proved Producing |
|||||||||
Change in FDC ($ millions) |
19.0 |
(53.5) |
32.9 |
||||||
Reserve Additions (MMboe) |
43.6 |
66.0 |
48.0 |
||||||
F&D Costs ($/boe) |
10.90 |
7.49 |
21.68 |
||||||
F&D Recycle Ratio |
1.2 |
2.2 |
1.5 |
||||||
F&D Costs – Three-Year Average ($/boe) |
12.76 |
15.19 |
21.09 |
||||||
F&D Recycle Ratio – Three-Year Average |
1.6 |
1.7 |
1.4 |
||||||
Total Proved |
|||||||||
Change in FDC ($ millions) |
581.3 |
(535.6) |
69.6 |
||||||
Reserve Additions (MMboe) |
88.6 |
66.9 |
55.0 |
||||||
F&D Costs ($/boe) |
11.71 |
0.19 |
19.58 |
||||||
F&D Recycle Ratio |
1.2 |
87.8 |
1.7 |
||||||
F&D Costs – Three-Year Average ($/boe) |
10.11 |
11.61 |
18.81 |
||||||
F&D Recycle Ratio – Three-Year Average |
2.1 |
2.2 |
1.5 |
||||||
Proved plus Probable |
|||||||||
Change in FDC ($ millions) |
236.5 |
(770.3) |
333.5 |
||||||
Reserve Additions (MMboe) |
113.5 |
78.7 |
87.5 |
||||||
F&D Costs ($/boe) |
6.10 |
(2.82) |
15.32 |
||||||
F&D Recycle Ratio |
2.2 |
(5.9) |
2.2 |
||||||
F&D Costs – Three-Year Average ($/boe) |
6.48 |
8.11 |
13.34 |
||||||
F&D Recycle Ratio – Three-Year Average |
3.2 |
3.2 |
2.2 |
(1) |
F&D costs take into account reserves revisions during the year on a per boe basis. |
(2) |
The aggregate of the exploration and development costs incurred in the financial year and the changes during that year in estimated future development costs may not reflect the total F&D costs related to reserves additions for that year. |
Table 7c
Finding, Development and Acquisition Costs, excluding FDC (1)(2)(3) |
|||||||||
Company Gross |
2016 |
2015 |
2014 |
||||||
Proved Producing |
|||||||||
Reserve Additions, including Net Acquisitions (Dispositions) (MMboe) |
34.0 |
53.4 |
41.7 |
||||||
FD&A Costs ($/boe) |
(2.25) |
8.88 |
24.97 |
||||||
FD&A Recycle Ratio |
(6.0) |
1.9 |
1.3 |
||||||
FD&A Costs – Three-Year Average ($/boe) |
11.15 |
17.02 |
22.77 |
||||||
FD&A Recycle Ratio – Three-Year Average |
1.9 |
1.5 |
1.3 |
||||||
Total Proved |
|||||||||
Reserve Additions, including Net Acquisitions (Dispositions) (MMboe) |
75.7 |
52.6 |
48.8 |
||||||
FD&A Costs ($/boe) |
(1.01) |
9.00 |
21.37 |
||||||
FD&A Recycle Ratio |
(13.5) |
1.9 |
1.5 |
||||||
FD&A Costs – Three-Year Average ($/boe) |
8.13 |
15.98 |
18.99 |
||||||
FD&A Recycle Ratio – Three-Year Average |
2.6 |
1.6 |
1.5 |
||||||
Proved plus Probable |
|||||||||
Reserve Additions, including Net Acquisitions (Dispositions) (MMboe) |
93.0 |
55.5 |
79.6 |
||||||
FD&A Costs ($/boe) |
(0.82) |
8.54 |
13.10 |
||||||
FD&A Recycle Ratio |
(16.6) |
2.0 |
2.5 |
||||||
FD&A Costs – Three-Year Average ($/boe) |
6.31 |
11.88 |
11.94 |
||||||
FD&A Recycle Ratio – Three-Year Average |
3.3 |
2.2 |
2.4 |
(1) |
FD&A costs take into account reserves revisions during the year on a per boe basis. |
(2) |
The aggregate of the exploration and development costs incurred in the financial year and the changes during that year in estimated future development costs may not reflect the total F&D costs related to reserves additions for that year. |
(3) |
“Finding, development and acquisition recycle ratio” or “FD&A recycle ratio” does not have a standardized meaning. See “Information Regarding Disclosure on Oil and Gas Reserves, Resources and Operational Information” contained in this news release. |
Table 7d
Finding, Development and Acquisition Costs, including FDC (1)(2) |
||||||||
Company Gross |
2016 |
2015 |
2014 |
|||||
Proved Producing |
||||||||
Change in FDC ($ millions) |
(95.9) |
(63.4) |
31.0 |
|||||
Reserve Additions, including Net Acquisitions (Dispositions) (MMboe) |
34.0 |
53.4 |
41.7 |
|||||
FD&A Costs ($/boe) |
(5.07) |
7.69 |
25.71 |
|||||
FD&A Recycle Ratio |
(2.7) |
2.2 |
1.3 |
|||||
FD&A Costs – Three-Year Average ($/boe) |
10.16 |
17.09 |
23.41 |
|||||
FD&A Recycle Ratio – Three-Year Average |
2.1 |
1.5 |
1.2 |
|||||
Total Proved |
||||||||
Change in FDC ($ millions) |
419.7 |
(589.5) |
69.2 |
|||||
Reserve Additions, including Net Acquisitions (Dispositions) (MMboe) |
75.7 |
52.6 |
48.8 |
|||||
FDA& Costs ($/boe) |
4.53 |
(2.20) |
22.79 |
|||||
FD&A Recycle Ratio |
3.0 |
(7.6) |
1.4 |
|||||
FD&A Costs – Three-Year Average ($/boe) |
7.56 |
12.69 |
20.74 |
|||||
FD&A Recycle Ratio – Three-Year Average |
2.8 |
2.0 |
1.4 |
|||||
Proved plus Probable |
||||||||
Change in FDC ($ millions) |
25.0 |
(906.2) |
333.2 |
|||||
Reserve Additions, including Net Acquisitions (Dispositions) (MMboe) |
93.0 |
55.5 |
79.6 |
|||||
FD&A Costs ($/boe) |
(0.55) |
(7.80) |
17.29 |
|||||
FD&A Recycle Ratio |
(24.7) |
(2.1) |
1.9 |
|||||
FD&A Costs – Three-Year Average ($/boe) |
3.91 |
8.58 |
14.44 |
|||||
FD&A Recycle Ratio – Three-Year Average |
5.4 |
3.0 |
2.0 |
(1) |
 FD&A costs take into account reserves revisions during the year on a per boe basis. |
(2) |
The aggregate of the exploration and development costs incurred in the financial year and the changes during that year in estimated future development costs may not reflect the total F&D costs related to reserves additions for that year. |
NE BC MONTNEY RESOURCES EVALUATION
The following discussion in “NE BC Montney Resources Evaluation” is subject to a number of cautionary statements, assumptions and risks as set forth therein. See “Information Regarding Disclosure on Oil and Gas Reserves, Resources and Operational Information” at the end of this news release for additional cautionary language, explanations and discussion, and see “Forward-looking Information and Statements” for a statement of principal assumptions and risks that may apply. See also “Definitions of Oil and Gas Resources and Reserves” in this news release. The discussion includes reference to TPIIP, Discovered Petroleum Initially-in-Place (“DPIIP”), Undiscovered Petroleum Initially-in-Place (“UPIIP”) and Economic Contingent Resource (“ECR”) as per the GLJ Resources Evaluation as at December 31, 2016, prepared in accordance with the COGE Handbook. Unless otherwise indicated in this news release, all references to ECR and Prospective volumes are Best Estimate ECR and Best Estimate Prospective volumes, respectively.
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 744 net sections, located primarily in the most prospective areas of the play.
GLJ was commissioned in 2016 and in 2015 to conduct independent resource evaluations for ARC’s lands in the NE BC 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 “Evaluated Areas”). The Independent Resources Evaluation was effective December 31, 2016 based on GLJ forecast pricing at January 1, 2017. The GLJ Independent Resources Evaluation conducted in respect of 2015 was effective December 31, 2015 based on GLJ forecast pricing at January 1, 2016 (the “2015 Resources Evaluation”). All references in the following discussion to TPIIP, DPIIP, UPIIP and ECR are in reference to the Evaluated Areas included in the 2016 Independent Resources Evaluation and 2015 Independent Resources Evaluation. The results of the 2016 and 2015 resources evaluations are summarized in the discussion and tables that follow.
The evaluation reaffirmed that ARC’s NE BC Montney assets provide a significant long-term growth opportunity with considerable resources, extending well beyond existing booked reserves and even the current estimates of the ECR. ARC’s NE BC 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 2016 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 51 gross operated wells (50.5 net wells), comprised of 22 tight oil wells and one liquids-rich well at Tower, 16 wells at Dawson that were a combination of dry gas and liquids-rich wells, three dry gas wells at Sunrise, and nine liquids-rich wells elsewhere in NE BC (three in Attachie, three in Parkland, one in Blueberry, and two in Pouce Coupe).
TPIIP for the shale gas-bearing lands in the Evaluated Areas increased 13 per cent to 101.5 Tcf relative to 2015. DPIIP for the shale gas-bearing lands increased slightly by one per cent for the Evaluated Areas to 41.8 Tcf. Growth in shale gas TPIIP is driven by a revised geological interpretation due to improved understanding of the Montney.
Shale gas ECR was evaluated on an unrisked and risked basis in 2016 and was subdivided into the Maturity Subclasses of Development Pending and Development Unclarified. The risked development pending shale gas ECR totaled 2.6 Tcf and risked development unclarified shale gas ECR totaled 3.6 Tcf. The risked prospective shale gas ECR totaled 7.0 Tcf.
NGLs ECR was evaluated on an unrisked and risked basis in 2016 and was subdivided into the Maturity Subclasses of Development Pending and Development Unclarified. The risked development pending NGLs ECR totaled 54 MMbbl and risked development unclarified NGLs ECR totaled 212 MMbbl. The risked prospective NGLs ECR totaled 472 MMbbl.
On the tight oil-bearing lands at Tower, Red Creek and Attachie, TPIIP increased nine per cent to 10.5 MMbbl and DPIIP increased eight per cent to 6.2 MMbbl.
Tight Oil ECR was evaluated on an unrisked and risked basis in 2016 and was subdivided into the Maturity Subclasses of Development Pending and Development Unclarified. The risked development pending tight oil ECR totaled 40 MMbbl and risked development unclarified tight oil ECR totaled 107 MMbbl. The risked prospective tight oil ECR totaled 50 MMbbl.
Risking of the economic 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.
Table 8
Shale Gas Resources (1)(2)(3)(4) |
|||||
(Tcf) |
2016 |
2015 |
|||
Total Petroleum Initially-in-Place |
101.5 |
90.0 |
|||
Discovered Petroleum Initially-in-Place (5) |
41.8 |
41.4 |
|||
Undiscovered Petroleum Initially-in-Place (6) |
59.7 |
48.6 |
(1) |
TPIIP, DPIIP and UPIIP have been estimated using a one per cent porosity cut-off in both 2016 and 2015, which means that essentially all gas-bearing rock has been incorporated into the calculations. |
(2) |
The resource categories in this table do not include free crude oil or liquids. |
(3) |
All volumes listed in the table are company gross and raw gas volumes. |
(4) |
All numbers are “Best Estimates”. |
(5) |
There is uncertainty that it will be commercially viable to produce any portion of the resources. |
(6) |
There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. |
Table 9
Tight Oil Resources (1)(2)(3)(4) |
|||||
(MMbbl) |
2016 |
2015 |
|||
Total Petroleum Initially-in-Place |
10,529 |
9,688 |
|||
Discovered Petroleum Initially-in-Place (5) |
6,180 |
5,736 |
|||
Undiscovered Petroleum Initially-in-Place (6) |
4,349 |
3,952 |
(1) |
TPIIP, DPIIP and UPIIP have been estimated in 2016 using a one per cent porosity cut-off for tight oil and using a three per cent cut-off in 2015. |
(2) |
All volumes listed in the table are company gross. |
(3) |
The tight oil DPIIP is a Stock Tank Barrel. |
(4) |
All numbers are “Best Estimates”. |
(5) |
There is uncertainty that it will be commercially viable to produce any portion of the resources. |
(6) |
There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. |
Table 10
2016 |
2015 |
|||||||||||
Best |
Best |
Best |
Best |
|||||||||
Reserves and Risked and |
Chance of |
Estimate |
Estimate |
Chance of |
Estimate |
Estimate |
||||||
Unrisked ECR (1)(2)(3)(4)(5)(6) |
Development |
Unrisked |
Risked |
Development |
Unrisked |
Risked |
||||||
Shale Gas (Tcf) |
||||||||||||
 Reserves |
100 % |
3.0 |
3.0 |
100 % |
2.6 |
2.6 |
||||||
 Development Pending ECR |
91 % |
2.9 |
2.6 |
92 % |
2.6 |
2.4 |
||||||
 Development Unclarified ECR |
74 % |
4.8 |
3.6 |
76 % |
4.4 |
3.3 |
||||||
NGLs (MMbbl) |
||||||||||||
 Reserves |
100 % |
61.9 |
61.9 |
100 % |
42.3 |
42.3 |
||||||
 Development Pending ECR |
91 % |
58.6 |
53.5 |
94 % |
39.1 |
36.9 |
||||||
 Development Unclarified ECR |
74 % |
286.7 |
212.5 |
76 % |
265.1 |
200.9 |
||||||
Tight Oil (MMbbl) |
||||||||||||
 Reserves |
100 % |
25.2 |
25.2 |
100 % |
22.7 |
22.7 |
||||||
 Development Pending ECR |
95 % |
42.0 |
39.9 |
95 % |
34.8 |
33.1 |
||||||
 Development Unclarified ECR |
69 % |
154.3 |
106.9 |
79 % |
163.2 |
129.0 |
(1) |
All DPIIP, other than cumulative production, reserves, and ECR, has been categorized as unrecoverable. Cumulative raw production to year-end 2016 was 0.7 Tcf of shale gas and 5.6 MMbbl of tight oil, all of which are immaterial in relation to the reserves and ECR magnitude. NGLs cumulative production is calculated based on current NGLs recoveries. |
(2) |
All volumes listed in the table are company gross and sales volumes. |
(3) |
All numbers are “Best Estimates”. |
(4) |
All ECR have been risked for chance of development. For ECR, the chance of development is defined as the probability of a project being commercially viable. In quantifying the chance of development, factors that were assessed quantitatively to be less than one in the risking calculation included the economic status, the project evaluation scenario status, and the development time frame. The chance of development is multiplied by the unrisked resource volume estimate, which yields the risked volume estimate. As many of these factors have a wide range of uncertainty and are difficult to quantify, the chance of development is an uncertain value that should be used with caution. |
(5) |
For reserves, the volumes under the heading “Best Estimate” are 2P reserves. |
(6) |
There is uncertainty that it will be commercially viable to produce any portion of the resources. |
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.
Table 11
2016 |
2015 |
|||||||||||
Best |
Best |
Best |
Best |
|||||||||
Risked and Unrisked ECR |
Chance of |
Estimate |
Estimate |
Chance of |
Estimate |
Estimate |
||||||
Development Pending (1)(2)(3)(4) |
Development |
Unrisked |
Risked |
Development |
Unrisked |
Risked |
||||||
Shale Gas (Tcf) |
91 % |
2.9 |
2.6 |
92 % |
2.6 |
2.4 |
||||||
NGLs (MMbbl) |
91 % |
58.6 |
53.5 |
94 % |
39.1 |
36.9 |
||||||
Tight Oil (MMbbl) |
95 % |
42.0 |
39.9 |
95 % |
34.8 |
33.1 |
||||||
Oil Equivalent (MMboe) |
92 % |
577.3 |
528.9 |
92 % |
509.4 |
470.7 |
||||||
Before-tax NPV ($ millions) |
||||||||||||
Undiscounted |
11,683 |
10,693 |
10,624 |
9,890 |
||||||||
Discounted at 5% |
4,431 |
4,068 |
3,447 |
3,203 |
||||||||
Discounted at 10% |
1,992 |
1,831 |
1,247 |
1,154 |
||||||||
Discounted at 15% |
1,006 |
925 |
443 |
406 |
||||||||
Discounted at 20% |
552 |
508 |
114 |
100 |
||||||||
After-tax NPV ($ millions) |
||||||||||||
Undiscounted |
8,566 |
7,841 |
7,728 |
7,194 |
||||||||
Discounted at 5% |
3,185 |
2,924 |
2,431 |
2,258 |
||||||||
Discounted at 10% |
1,390 |
1,277 |
812 |
750 |
||||||||
Discounted at 15% |
675 |
620 |
229 |
208 |
||||||||
Discounted at 20% |
352 |
323 |
(3) |
(8) |
(1) |
All volumes listed in the table are company gross and sales volumes. |
(2) |
2016 NPV as per GLJ Independent Resources Evaluation as of December 31, 2016 and based on GLJ forecast pricing at January 1, 2017. 2015 NPV as per GLJ Independent Resources Evaluation as of December 31, 2015 and based on GLJ forecast pricing at January 1, 2016. |
(3) |
Risk in the above table is the chance of development. Contingent resources are discovered resources by definition. |
(4) |
There is uncertainty that it will be commercially viable to produce any portion of the resources. |
The estimated cost to bring on commercial production the Development Pending Contingent Resources for all three product types is approximately $4.0 billion (when discounted at 10 per cent, the estimated cost is approximately $1.4 billion). The expected timeline to bring these resources on production is between two and 10 years. The ECR are expected to be recovered using the same technology in horizontal drilling and multi-stage fracturing that ARC has already proven to be effective in the Montney in northeast British Columbia.
Table 12
2016 |
2015 |
|||||||||||
Best |
Best |
Best |
Best |
|||||||||
Prospective |
Chance of |
Estimate |
Estimate |
Chance of |
Estimate |
Estimate |
||||||
Resources (1)(2)(3)(4)(5) |
Commerciality |
Unrisked |
Risked |
Commerciality |
Unrisked |
Risked |
||||||
Shale Gas (Tcf) |
48 % |
14.7 |
7.0 |
49 % |
10.7 |
5.3 |
||||||
NGLs (MMbbl) |
45 % |
1,042.1 |
471.5 |
46 % |
690.8 |
319.3 |
||||||
Tight Oil (MMbbl) |
41 % |
122.5 |
49.9 |
68 % |
119.0 |
81.3 |
||||||
Oil Equivalent (MMboe) |
47 % |
3,612.1 |
1,686.6 |
49 % |
2,587.1 |
1,279.2 |
(1) |
All UPIIP, other than prospective resources, has been categorized as unrecoverable. |
(2) |
All volumes listed in the table are company gross and sales volumes. |
(3) |
Prospective resources have been risked for chance of development and chance of discovery. For prospective resources, the chance of development multiplied by the chance of discovery is defined as the probability of a project being commercially viable. In quantifying the chance of commerciality, factors that were assessed quantitatively to be less than one in the risking calculation included the economic status, the project evaluation scenario status and the development time frame, along with the overall chance of discovery. The chance of commerciality is multiplied by the unrisked prospective resource volume estimate, which yields the risked volume estimate. As many of these factors have a wide range of uncertainty and are difficult to quantify, the chance of commerciality is an uncertain value that should be used with caution. |
(4) |
All prospective resources are subclassified as the prospect maturity subclass. |
(5) |
There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. |
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. Historic 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 multi-year exploration and development programs and significant levels of future capital expenditures are required in order 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 exists, 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 well fracturing technology and applications. For ECR to be converted to reserves, Management and the Board of Directors 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 re-classified to reserves.