CALGARY, Feb. 10, 2016 /CNW/ - (ARX - TSX) ARC
Resources Ltd. ("ARC") is pleased to report its 2015 year-end
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 CEO.
HIGHLIGHTS
- Replaced 190 per cent of 2015 total production, adding 78.7
MMboe of proved 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 MMboe (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 MMboe due to the
decrease in commodity prices since year-end 2014.
- Proved developed producing ("PDP") reserves increased from 210
MMboe to 222 MMboe. The increase in PDP reserves was driven by
northeast British Columbia ("NE
BC") Montney properties, which
increased to 115 MMboe at year-end 2015 from 84 MMboe at year-end
2014.
- Replaced 175 per cent of 2015 natural gas production, adding
0.3 Tcf of 2P natural gas reserves. Replaced approximately 210 per
cent of 2015 oil and natural gas liquids ("NGLs") production,
adding 31 MMbbl of 2P oil and NGLs reserves. Material reserves
growth was realized in the NE BC 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 proved reserves, excluding
Future Development Capital ("FDC") and F&D costs of
$8.31 per boe for proved producing
reserves. Significant NE BC 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 ("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 a significant increase in the identified resource base on
ARC's NE BC Montney lands. The
shale gas Total Petroleum Initially in Place ("TPIIP") increased 33
per cent from 67.4 Tcf in 2014 to 90 Tcf 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 (1).
(1)
|
Year-end 2015
complies with current Canadian Oil and Gas Evaluation Handbook
("COGE Handbook") guidelines. Resources Evaluation volumes provided
are the "Best Estimate" case. Year-end 2015 and 2014 TPIIP
estimates utilize a one per cent porosity cut-off for shale gas
based upon "Best Estimate" case. Estimates for both 2015 and 2014
were determined using a three per cent porosity cut-off for tight
oil based upon "Best Estimate" case.
|
2015 INDEPENDENT RESERVES EVALUATION
GLJ Petroleum Consultants ("GLJ") conducted an Independent
Reserves Evaluation effective December 31,
2015, 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, 2016 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. 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 ("AIF") for the year ended December 31, 2015, which will be filed on SEDAR
at www.sedar.com on or before March 30,
2016.
Based on this Independent Reserves Evaluation, ARC's reserves
profile as at December 31, 2015 is
summarized below:
- Two per cent increase in 2015 2P reserves to 687 MMboe compared
to 673 MMboe of 2P reserves at year-end 2014. 2P reserves are
comprised of 2.9 Tcf of natural gas and 200 MMbbl of oil and NGLs
at year-end 2015.
- 78.7 MMboe of 2P reserve additions from exploration and
development activities (including revisions), before net
dispositions of 23 MMboe and 2015 production of 42 MMboe. Technical
revisions of 36 MMboe more than offset the removal of 15 MMboe due
to the decrease in commodity prices since year-end 2014.
- 190 per cent replacement of 2P reserves based on 78.7 MMboe of
2P reserve additions and 2015 production of 42 MMboe.
- Total proved reserves account for 57 per cent of 2P
reserves.
- PDP reserves represent 56 per cent of total proved 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 six Mcf 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. Proved F&D costs, including FDC, were $0.19 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. For
details on ARC's 2016 production guidance, see the February 10, 2016 news release entitled, "ARC
Resources Ltd. Announces Strong Fourth Quarter, Record Annual
Production and a Siginificant Increase in Montney Resource Estimate
in 2015".
- 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 $527 million (undiscounted) have been included in
the 2P reserves, which account for the abandonment and reclamation
of all wells to which reserves have been attributed.
Table 1
|
|
|
|
|
|
|
|
|
GLJ Price
Forecast
|
|
WTI Crude
Oil
|
|
Edmonton Light
Oil
|
|
AECO Natural
Gas
|
|
Foreign
Exchange
|
at January
1
|
|
(US$/bbl)
|
|
(Cdn$/bbl)
|
|
(Cdn$/MMbtu)
|
|
(US$/Cdn$)
|
|
|
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
(1)
|
|
89.63
|
|
|
98.41
|
|
|
4.60
|
|
|
0.850
|
0.875
|
Escalate thereafter
at
|
|
+2% /
year
|
+2% / year
|
|
+2% /
year
|
+2% / year
|
|
+2% /
year
|
+2% / year
|
|
0.850
|
0.875
|
(1)
|
Escalated at two per
cent per year starting in 2025 in the January 1, 2016 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)
|
|
2015
Oil
Equivalent
|
|
2014 Oil
Equivalent
|
Company
Gross
|
|
(Mbbl)
|
|
(Mbbl)
|
|
(MMcf)
|
|
(Mboe)
|
|
(Mboe)
|
Proved
Producing
|
|
82,163
|
|
12,712
|
|
759,803
|
|
221,509
|
|
209,509
|
Proved Developed
Non-Producing
|
|
2,913
|
|
870
|
|
49,679
|
|
12,062
|
|
20,164
|
Proved
Undeveloped
|
|
13,784
|
|
15,470
|
|
783,010
|
|
159,755
|
|
152,390
|
Total
Proved
|
|
98,860
|
|
29,052
|
|
1,592,492
|
|
393,327
|
|
382,063
|
Proved plus
Probable
|
|
146,483(4)
|
|
53,343
|
|
2,922,145(5)
|
|
686,851
|
|
672,748
|
(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 71 per cent light and medium crude oil,
28 per cent tight oil and one per cent heavy crude oil.
|
(5)
|
Proved plus Probable
Natural Gas closing balance by percentage weighting of product
type: approximately 96 per cent shale gas and four per cent
conventional natural gas.
|
Table 3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserves
Reconciliation(1)
|
|
Crude and
Tight
Oil(2)
|
|
NGLs
|
|
Natural
Gas(3)
|
|
Oil
Equivalent
|
Company
Gross
|
|
(Mbbl)
|
|
(Mbbl)
|
|
(MMcf)
|
|
(Mboe)
|
Proved
Producing
|
|
|
|
|
|
|
|
|
|
Opening Balance,
January 1, 2015
|
|
87,990
|
|
12,136
|
|
656,299
|
|
209,509
|
|
|
Exploration
Discoveries
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Extensions and
Improved Recovery (4)
|
|
6,168
|
|
1,756
|
|
239,384
|
|
47,821
|
|
|
Technical
Revisions
|
|
7,279
|
|
1,946
|
|
91,908
|
|
24,544
|
|
|
Acquisitions
|
|
63
|
|
—
|
|
—
|
|
63
|
|
|
Dispositions
|
|
(3,839)
|
|
(183)
|
|
(52,114)
|
|
(12,708)
|
|
|
Economic
Factors
|
|
(3,767)
|
|
(301)
|
|
(13,684)
|
|
(6,349)
|
|
|
Production
|
|
(11,731)
|
|
(2,642)
|
|
(161,990)
|
|
(41,372)
|
|
Ending Balance,
December 31, 2015
|
|
82,163
|
|
12,712
|
|
759,803
|
|
221,509
|
Total
Proved
|
|
|
|
|
|
|
|
|
|
Opening Balance,
January 1, 2015
|
|
104,931
|
|
21,668
|
|
1,532,788
|
|
382,063
|
|
|
Exploration
Discoveries
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Extensions and
Improved Recovery (4)
|
|
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,
December 31, 2015
|
|
98,860
|
|
29,052
|
|
1,592,492
|
|
393,327
|
Proved plus
Probable
|
|
|
|
|
|
|
|
|
|
Opening Balance,
January 1, 2015
|
|
152,035
|
|
40,454
|
|
2,881,551
|
|
672,748
|
|
|
Exploration
Discoveries
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Extensions and
Improved Recovery (4)
|
|
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,
December 31, 2015
|
|
146,483(5)
|
|
53,343
|
|
2,922,145(6)
|
|
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)
|
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 71 per cent light and medium crude oil,
28 per cent tight oil and one per cent heavy crude oil.
|
(6)
|
Proved plus Probable
Natural Gas closing balance by percentage weighting of product
type: approximately 96 per cent shale gas and four per cent
conventional natural gas.
|
Reserve Life Index
ARC's 2P RLI was 15.9 years at year-end 2015, while the proved
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
$390 million capital program for
2016. The 2P RLI has been maintained at greater than 15 years since
year-end 2011, as a result of successful delineation and reserves
growth of the Montney in northeast
British Columbia. ARC's annual
average production has increased from 73,954 boe per day in 2010 to
114,167 boe per day in 2015. The following table summarizes ARC's
historical RLI.
Table 4
|
|
|
|
|
|
Reserve Life
Index
|
2015
(1)
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
Total
Proved
|
9.1
|
|
8.5
|
|
9.1
|
|
10.5
|
|
10.7
|
Proved plus
Probable
|
15.9
|
|
15.0
|
|
15.5
|
|
17.5
|
|
17.0
|
(1)
|
Based on production
guidance midpoint of 118,000 boe per day for 2016.
|
Net Present Value Summary
ARC's oil, natural gas and NGLs reserves were evaluated using
GLJ's commodity price forecasts at January
1, 2016. The net present value ("NPV") is prior to provision
for interest, debt service charges, and general and administrative
expenses. It should not be assumed that the NPV of cash flow
estimated by GLJ represents the fair market value of the reserves.
The NPV of ARC's reserves decreased relative to year-end 2014 due
to a reduction in the January 1, 2016
GLJ price forecast for both oil and natural gas as previously
outlined in Table 1. NPVs on both a before- and after-tax basis are
presented in Table 5.
Table 5
|
|
|
|
|
|
|
|
|
|
|
NPV of Cash
Flow(1)(2)
|
|
|
|
Discounted
|
|
Discounted
|
|
Discounted
|
|
Discounted
|
($
millions)
|
|
Undiscounted
|
|
at
5%
|
|
at
10%
|
|
at
15%
|
|
at
20%
|
Before-tax
|
|
|
|
|
|
|
|
Proved
Producing
|
|
4,670
|
|
3,289
|
|
2,533
|
|
2,064
|
|
1,748
|
|
Proved Developed
Non-Producing
|
|
206
|
|
158
|
|
128
|
|
107
|
|
92
|
|
Proved
Undeveloped
|
|
2,119
|
|
1,185
|
|
707
|
|
434
|
|
266
|
|
Total
Proved
|
|
6,995
|
|
4,632
|
|
3,367
|
|
2,605
|
|
2,106
|
|
Probable
|
|
6,199
|
|
3,046
|
|
1,772
|
|
1,142
|
|
785
|
|
Proved plus
Probable
|
|
13,194
|
|
7,678
|
|
5,139
|
|
3,748
|
|
2,891
|
After-tax(3)(4)
|
|
|
|
|
|
|
|
Proved
Producing
|
|
4,030
|
|
2,906
|
|
2,279
|
|
1,885
|
|
1,615
|
|
Proved Developed
Non-Producing
|
|
151
|
|
116
|
|
94
|
|
79
|
|
68
|
|
Proved
Undeveloped
|
|
1,550
|
|
836
|
|
467
|
|
258
|
|
129
|
|
Total
Proved
|
|
5,732
|
|
3,858
|
|
2,841
|
|
2,222
|
|
1,812
|
|
Probable
|
|
4,538
|
|
2,206
|
|
1,258
|
|
789
|
|
524
|
|
Proved plus
Probable
|
|
10,269
|
|
6,063
|
|
4,098
|
|
3,011
|
|
2,336
|
(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, 2016.
|
(3)
|
Based on ARC's
estimated tax pools at year-end 2015.
|
(4)
|
The after-tax NPV of
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 Management's Discussion &
Analysis should be consulted for information at the business entity
level.
|
At a 10 per cent discount factor, and on a before-tax basis,
proved producing reserves constitute 75 per cent of the total
proved reserves cash flow (NPV10 before-tax), while total proved
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 proved 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 $3.6
billion at year-end 2014. The decrease in FDC in 2015 was
predominantly attributed to the decrease in well and facility
capital costs, the removal of capital associated with dispositions,
and the removal of capital recognized at year-end 2014 that was
executed in 2015.
Table 6 outlines GLJ estimated FDC required to bring total
proved and total proved plus probable reserves on production.
Table 6
|
|
|
|
Future Development
Capital (1)(2)
|
|
|
|
($
millions)
|
Total
Proved
|
|
Total Proved 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
|
(1)
|
Amounts may not add
due to rounding.
|
(2)
|
FDC as per GLJ
Independent Reserves Evaluation as of December 31, 2015 and based
on GLJ forecast pricing at January 1, 2016.
|
Finding, Development and Acquisition Costs
ARC's 2015 F&D costs were $6.97 per boe and $8.20 per boe for 2P and proved reserves,
respectively, excluding FDC (($2.82)
per boe and $0.19 per boe,
respectively, for 2P and proved 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
proved 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 $9.00 per boe for proved reserves, excluding FDC
(($7.80) per boe and ($2.20) per boe, respectively, for 2P and proved
reserves, including FDC). The three-year average FD&A costs
were $11.88 per boe for 2P reserves
and $15.98 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 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 $74 million in
2015.
Table 7 highlights ARC's reserves, F&D costs, FD&A costs
and the associated recycle ratios for the past three years.
Table 7
|
|
|
|
|
|
Reserves (Company
Gross), Capital Expenditures and Operating
|
|
|
|
|
|
|
Netbacks(1)(2)
|
|
2015
|
|
2014
|
|
2013
|
Reserves(Mboe)
|
|
|
|
|
|
Proved
Producing
|
|
221,509
|
|
209,509
|
|
208,454
|
|
Total
Proved
|
|
393,327
|
|
382,063
|
|
373,976
|
|
Proved plus
Probable
|
|
686,851
|
|
672,748
|
|
633,864
|
Capital
Expenditures($ 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($/boe)
|
|
|
|
|
|
Operating
Netback
|
|
16.69
|
|
33.01
|
|
28.57
|
|
Operating Netback –
Three-Year Average
|
|
25.91
|
|
28.86
|
|
27.24
|
(1)
|
Amounts may not add
due to rounding.
|
(2)
|
Operating netback is
calculated using production revenues, excluding realized gains and
losses on commodity hedging, less
royalties, transportation and operating
expenses, calculated on a per boe equivalent basis.
|
Table 7a
|
|
|
|
Finding and
Development Costs, excluding
FDC(1)(2)(3)(4)
|
|
|
|
Company
Gross
|
2015
|
|
2014
|
|
2013
|
Proved
Producing
|
|
|
|
|
Reserve Additions
(MMboe)
|
66.0
|
|
48.0
|
|
47.4
|
|
|
F&D Costs
($/boe)
|
8.31
|
|
20.99
|
|
18.43
|
|
|
F&D Recycle
Ratio
|
2.0
|
|
1.6
|
|
1.6
|
|
|
F&D Costs –
Three-Year Average ($/boe)
|
15.05
|
|
20.49
|
|
20.24
|
|
|
F&D Recycle Ratio
– Three-Year Average
|
1.7
|
|
1.4
|
|
1.3
|
Total
Proved
|
|
|
|
|
Reserve Additions
(MMboe)
|
66.9
|
|
55.0
|
|
50.1
|
|
|
F&D Costs
($/boe)
|
8.20
|
|
18.32
|
|
17.45
|
|
|
F&D Recycle
Ratio
|
2.0
|
|
1.8
|
|
1.6
|
|
|
F&D Costs –
Three-Year Average ($/boe)
|
14.13
|
|
17.32
|
|
14.18
|
|
|
F&D Recycle Ratio
– Three-Year Average
|
1.8
|
|
1.7
|
|
1.9
|
Proved plus
Probable
|
|
|
|
|
Reserve Additions
(MMboe)
|
78.7
|
|
87.5
|
|
68.4
|
|
|
F&D Costs
($/boe)
|
6.97
|
|
11.51
|
|
12.79
|
|
|
F&D Recycle
Ratio
|
2.4
|
|
2.9
|
|
2.2
|
|
|
F&D Costs –
Three-Year Average ($/boe)
|
10.36
|
|
11.15
|
|
8.24
|
|
|
F&D Recycle Ratio
– Three-Year Average
|
2.5
|
|
2.6
|
|
3.3
|
(1)
|
In all cases, the
F&D or FD&A number is calculated by dividing the identified
capital expenditures by the
applicable reserves additions both before
and after changes in FDC costs.
|
(2)
|
Both F&D and
FD&A costs take into account reserves revisions during the year
on a per boe basis.
|
(3)
|
Recycle ratio is
defined as operating netback per barrel of oil equivalent divided
by the appropriate F&D or FD&A costs on a per
barrel
of oil equivalent.
|
(4)
|
The aggregate of the
exploration and development costs incurred in the financial year
and the changes during that year in estimated
future development costs may not reflect
the total F&D costs related to reserves additions for that
year.
|
Table 7b
|
|
|
|
|
Finding and
Development Costs, including
FDC(1)(2)(3)(4)
|
|
|
|
|
Company
Gross
|
2015
|
|
2014
|
|
2013
|
Proved
Producing
|
|
|
|
|
|
Change in FDC ($
millions)
|
(53.5)
|
|
32.9
|
|
42.0
|
|
Reserve Additions
(MMboe)
|
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
Proved
|
|
|
|
|
|
Change in FDC ($
millions)
|
(535.6)
|
|
69.6
|
|
33.0
|
|
Reserve Additions
(MMboe)
|
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
|
Proved plus
Probable
|
|
|
|
|
|
Change in FDC ($
millions)
|
(770.3)
|
|
333.5
|
|
(90.2)
|
|
Reserve Additions
(MMboe)
|
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
|
(1)
|
The calculation of
F&D and FD&A costs incorporates the change in FDC required
to bring proved undeveloped and developed
reserves into production. In all cases,
the F&D or FD&A number is calculated by dividing the
identified capital expenditures by the
applicable reserves additions both before
and after changes in FDC costs.
|
(2)
|
Both F&D and
FD&A costs take into account reserves revisions during the year
on a per boe basis.
|
(3)
|
Recycle ratio is
defined as operating netback per barrel of oil equivalent divided
by the appropriate F&D or FD&A costs on a per
barrel of oil equivalent.
|
(4)
|
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)(4)
|
|
|
|
Company
Gross
|
2015
|
|
2014
|
|
2013
|
Proved
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
Proved
|
|
|
|
|
Reserve Additions,
including Net Acquisitions (Dispositions) (MMboe)
|
52.6
|
|
48.8
|
|
44.8
|
|
|
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
|
Proved 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
|
(1)
|
In all cases, the
F&D or FD&A number is calculated by dividing the identified
capital expenditures by the
applicable reserves additions both before
and after changes in FDC costs.
|
(2)
|
Both F&D and
FD&A costs take into account reserves revisions during the year
on a per boe basis.
|
(3)
|
Recycle ratio is
defined as operating netback per barrel of oil equivalent divided
by the appropriate F&D or FD&A costs on a per
barrel of oil equivalent.
|
(4)
|
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 7d
|
|
|
|
Finding,
Development and Acquisition Costs, including
FDC(1)(2)(3)(4)
|
|
|
|
Company
Gross
|
2015
|
|
2014
|
|
2013
|
Proved
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
Proved
|
|
|
|
|
Change in FDC ($
millions)
|
(589.5)
|
|
69.2
|
|
38.9
|
|
Reserve Additions,
including Net Acquisitions (Dispositions) (MMboe)
|
52.6
|
|
48.8
|
|
44.8
|
|
|
FDA& 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
|
Proved 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
|
|
14.44
|
|
12.47
|
|
|
FD&A Recycle
Ratio – Three-Year Average
|
3.0
|
|
2.0
|
|
2.2
|
(1)
|
The calculation of
F&D and FD&A costs incorporates the change in FDC required
to bring proved undeveloped and developed
reserves into production. In all cases,
the F&D or FD&A number is calculated by dividing the
identified capital expenditures by the
applicable reserves additions both before
and after changes in FDC costs.
|
(2)
|
Both F&D and
FD&A costs take into account reserves revisions during the year
on a per boe basis.
|
(3)
|
Recycle ratio is
defined as operating netback per barrel of oil equivalent divided
by the appropriate F&D or FD&A costs on a per
barrel of oil equivalent.
|
(4)
|
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 release for additional
cautionary language, explanations and discussion, and see
"Forward-looking 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, DPIIP and Economic
Contingent Resource ("ECR") as per the GLJ Resources Evaluation as
at December 31, 2015, 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.
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 zero per cent, five per
cent, 10 per cent, 15 per cent and 20 per cent;
- The disclosure of the chance of development risk for each
project maturity sub-class the issuer discloses; and
- 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 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 Resources Evaluation was effective December 31, 2015 based on GLJ forecast pricing
at January 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 results of
the 2015 and 2014 resources evaluations are summarized in the
discussion and tables below.
The evaluation reaffirmed that ARC's NE BC 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 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 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), comprised 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 Tcf. The 2015 drilling
program resulted in a 17 per cent increase of DPIIP for the
Evaluated Areas to 41.4 Tcf. 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 totaled 2.4 Tcf and risked development unclarified
shale gas ECR totaled 3.3 Tcf. The risked prospective shale gas ECR
totaled 5.3 Tcf.
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 totaled 36.9 MMbbl and risked development unclarified NGLs
ECR totaled 201 MMbbl. The risked prospective NGLs ECR totaled 319
MMbbl.
On the tight oil-bearing lands at Tower, Red Creek and Attachie, TPIIP increased 315 per cent to
9,688 MMbbl and DPIIP increased 217 per cent to 5,736 MMbbl. 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 totaled 33 MMbbl and risked development unclarified
tight oil ECR totaled 129 MMbbl. The risked prospective tight oil
ECR totaled 81 MMbbl.
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.
Table 8
|
|
|
|
|
Shale Gas
Resources (1)(2)(3)(4)
|
|
|
|
|
(Tcf)
|
|
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
|
(1)
|
TPIIP, DPIIP and
UPIIP have been estimated using a one per cent porosity cut-off in
both 2015 and 2014, 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."
|
Table 9
|
|
|
|
|
Tight Oil
Resources (1)(2)(3)(4)
|
|
|
|
|
(MMbbl)
|
|
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
|
(1)
|
TPIIP, DPIIP and
UPIIP have been estimated using a three per cent porosity cut-off
for tight oil due to lower mobility for oil relative to
gas.
|
(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."
|
Table 10
|
|
|
|
|
|
|
2015 Reserves and
Risked and Unrisked ECR (1)(2)(3)(4)(5)
|
|
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
(MMbbl)
|
|
|
|
|
|
|
|
Reserves
|
|
100 %
|
|
42.3
|
|
42.3
|
|
Development Pending
ECR
|
|
94 %
|
|
39.1
|
|
36.9
|
|
Development
Unclarified ECR
|
|
76 %
|
|
265.1
|
|
200.9
|
Tight Oil
(MMbbl)
|
|
|
|
|
|
|
|
Reserves
|
|
100 %
|
|
22.7
|
|
22.7
|
|
Development Pending
ECR
|
|
95 %
|
|
34.8
|
|
33.1
|
|
Development
Unclarified ECR
|
|
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 2015 was 0.6
Tcf of shale gas and 2.5 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.
|
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
|
|
|
|
|
|
|
2015 Risked and
Unrisked ECR
Development
Pending (1)(2)(3)
|
|
Chance
of
Development
|
|
Best
Estimate
Unrisked
|
|
Best
Estimate
Risked
|
Shale Gas
(Tcf)
|
|
92 %
|
|
2.6
|
|
2.4
|
NGLs
(MMbbl)
|
|
94 %
|
|
39.1
|
|
36.9
|
Tight Oil
(MMbbl)
|
|
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)
|
(1)
|
All volumes listed in
the table are company gross and sales volumes.
|
(2)
|
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.
|
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 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
|
|
|
|
|
|
|
2015 Prospective
Resources (1)(2)(3)(4)
|
|
Chance
of
Commerciality
|
|
Best
Estimate
Unrisked
|
|
Best
Estimate
Risked
|
Shale Gas
(Tcf)
|
|
49 %
|
|
10.7
|
|
5.3
|
NGLs
(MMbbl)
|
|
46 %
|
|
690.8
|
|
319.3
|
Tight Oil
(MMbbl)
|
|
68 %
|
|
119.0
|
|
81.3
|
(1)
|
All UPIIP, other than
prospective resources, has been categorized as unrecoverable. GLJ
estimated DPIIP values using a porosity cut-off of one per cent for
shale gas and three per cent for tight oil.
|
(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 prospective maturity
subclass.
|
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 fracing
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
re-classified to reserves.
DEFINITIONS OF OIL AND GAS RESOURCES AND RESERVES
Reserves are
estimated remaining quantities of oil and natural gas and related
substances anticipated to be recoverable from known accumulations,
as of a given date, based on the analysis of drilling, geological,
geophysical and engineering data; the use of established
technology; and specified economic conditions, which are generally
accepted as being reasonable. Reserves are classified according to
the degree of certainty associated with the estimates as
follows:
|
|
|
|
Proved
Reserves are those reserves that can be estimated with a high
degree of certainty to be recoverable. It is likely that the actual
remaining quantities recovered will exceed the estimated proved
reserves.
|
|
|
|
Probable
Reserves are those additional reserves that are less certain to
be recovered than proved reserves. It is equally likely that the
actual remaining quantities recovered will be greater or less than
the sum of the estimated proved plus probable reserves.
|
|
|
|
Possible
Reserves are those additional reserves that are less certain to
be recovered than probable reserves. It is unlikely that the actual
remaining quantities recovered will exceed the sum of the estimated
proved plus probable plus possible reserves.
|
|
|
Resources
encompasses all petroleum quantities that originally existed on or
within the earth's crust in naturally occurring accumulations,
including Discovered and Undiscovered (recoverable and
unrecoverable) plus quantities already produced. "Total Resources"
is equivalent to "Total Petroleum Initially-In-Place." Resources
are classified in the following categories:
|
|
|
|
Total Petroleum
Initially-In-Place ("TPIIP") is that quantity of petroleum that
is estimated to exist originally in naturally occurring
accumulations. It includes that quantity of petroleum that is
estimated, as of a given date, to be contained in known
accumulations, prior to production, plus those estimated quantities
in accumulations yet to be discovered.
|
|
|
|
Discovered
Petroleum Initially-In-Place ("DPIIP") is that quantity
of petroleum that is estimated, as of a given date, to be contained
in known accumulations prior to production. The recoverable portion
of DPIIP includes production, reserves, and contingent resources;
the remainder is unrecoverable.
|
|
|
|
Contingent
Resources are those quantities of petroleum estimated, as of a
given date, to be potentially recoverable from known accumulations
using established technology or technology under development but
which are not currently considered to be commercially recoverable
due to one or more contingencies.
|
|
|
|
Economic
Contingent Resources ("ECR") are those contingent resources
which are currently economically recoverable.
|
|
|
|
Project Maturity
Subclass Development Pending is defined as a contingent
resource that has been assigned a high chance of development and
the resolution of final conditions for development are being
actively pursued.
|
|
|
|
Project Maturity
Subclass Development Unclarified is defined as a contingent
resource that requires further appraisal to clarify the potential
for development and has been assigned a lower chance of development
until contingencies can be clearly defined.
|
|
|
|
Undiscovered
Petroleum Initially-In-Place ("UPIIP") is that quantity of
petroleum that is estimated, on a given date, to be contained in
accumulations yet to be discovered. The recoverable portion of
UPIIP is referred to as "prospective resources" and the remainder
as "unrecoverable."
|
|
|
|
Prospective
Resources are those quantities of petroleum estimated, as of a
given date, to be potentially recoverable from undiscovered
accumulations by application of future development
projects.
|
|
|
|
Unrecoverable
is that portion of DPIIP and UPIIP quantities which is estimated,
as of a given date, not to be recoverable by future development
projects. A portion of these quantities may become recoverable in
the future as commercial circumstances change or technological
developments occur; the remaining portion may never be recovered
due to the physical/chemical constraints represented by subsurface
interaction of fluids and reservoir rocks.
|
|
|
|
Uncertainty
Ranges are described by the COGE Handbook as low, best, and
high estimates for reserves and resources. The Best Estimate
is considered to be the best estimate of the quantity that will
actually be recovered. It is equally likely that the actual
remaining quantities recovered will be greater or less than the
best estimate. If probabilistic methods are used, there should be
at least a 50 per cent probability that the quantities actually
recovered will equal or exceed the best estimate.
|
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 a six Mcf
to one barrel ratio. The boe rate is based on an energy equivalent
conversion method primarily applicable at the burner tip, and given
that the value ratio based on the current price of crude oil as
compared to natural gas is significantly different than the energy
equivalency of the 6:1 conversion ratio, utilizing the 6:1
conversion ratio may be misleading as an indication of value. 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, and without including any
royalty interest, unless otherwise stated. Unless otherwise
specified, all reserves volumes in this news release (and all
information derived therefrom) are based on company gross reserves
using forecast prices and costs.
This press release contains metrics commonly used in the oil and
natural gas industry, such as "recycle ratio," "finding and
development costs," "finding and development recycle ratio,"
"finding, development and acquisition costs," "operating netbacks,"
and "reserve life index." These terms do not have a standardized
meaning and may not be comparable to similar measures presented by
other companies, and therefore should not be used to make such
comparisons.
Both F&D and FD&A costs take into account reserves
revisions during the year on a per boe basis. The aggregate of the
costs incurred in the financial year and changes during that year
in estimated FDC may not reflect total F&D costs related to
reserves additions for that year. F&D costs both including and
excluding acquisitions and dispositions have been presented in this
news release because acquisitions and dispositions can have a
significant impact on ARC's ongoing reserves replacement costs and
excluding these amounts could result in an inaccurate portrayal of
its cost structure. Recycle ratio is measured by dividing the
operating netback by appropriate F&D or FD&A costs per boe
for the year. Operating netback is calculated using production
revenues, excluding realized gains and losses on commodity hedging,
less royalties, transportation and operating expenditures,
calculated on a per boe equivalent basis. Management uses these oil
and gas metrics for its own performance measurements and to provide
shareholders with measures to compare ARC's performance over
time.
ARC's oil and gas reserves statement for the year ended
December 31, 2015, which will include
complete disclosure of its oil and gas reserves and other oil and
gas information in accordance with NI 51-101, will be contained
within ARC's AIF which will be available on or before March 30, 2016 on ARC's website at
www.arcresources.com and on SEDAR at www.sedar.com.
This news release contains references to estimates of oil and
gas classified as TPIIP, DPIIP, UPIIP and ECR in the Montney region in northeast British Columbia, including lands in
Pouce Coupe in Alberta, which are not, and should not be
confused with, oil and gas reserves. See "Definitions of Oil and
Gas Resources and Reserves."
Projects have not been defined to develop the resources in the
Evaluated Areas 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 with conversion of DPIIP into ECR, ECR into 2P
reserves, and probable reserves into proved reserves, 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 Information and Statements."
Notice to US 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 United States or other foreign disclosure
standards. For example, the United States Securities and Exchange
Commission ("the SEC") generally permits oil and gas issuers, in
their filings with the SEC, to disclose only proved reserves (as
defined in SEC rules). Canadian securities laws require oil and gas
issuers, in their filings with Canadian securities regulators, to
disclose not only proved reserves (which are defined differently
from the SEC rules) but also probable reserves, each as defined in
NI 51-101. Accordingly, proved reserves disclosed in this news
release may not be comparable to US standards, and in this news
release, ARC has disclosed reserves designated as "probable
reserves" and "proved plus probable reserves." Probable reserves
are higher-risk and are generally believed to be less likely to be
accurately estimated or recovered than proved reserves. The SEC's
guidelines strictly prohibit reserves in these categories from
being included in filings with the SEC that are required to be
prepared in accordance with US disclosure requirements. In
addition, under Canadian disclosure requirements and industry
practice, reserves and production are reported using gross volumes,
which are volumes prior to deduction of royalties and similar
payments. The practice in the United
States is to report reserves and production using net
volumes, after deduction of applicable royalties and similar
payments. Moreover, ARC has determined and disclosed estimated
future net revenue from its reserves using forecast prices and
costs, whereas the SEC generally requires that prices and costs be
held constant at levels in effect at the date of the reserve
report. As a consequence of the foregoing, ARC's reserve estimates
and production volumes in this news release may not be comparable
to those made by companies utilizing United States reporting and disclosure
standards. 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.
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 "2015 Independent Reserves
Evaluation" and the recognition of significant resources under the
heading "NE BC Montney Resources Evaluation," 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; 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 are
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
planned expenditures. There are a number of assumptions associated
with the development of the Evaluated Areas, 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, and recovery factors and development necessary
involves known and unknown risks and uncertainties, including those
risks identified in this news 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
early stage of development of some areas in the Evaluated Areas;
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, unfavorable 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 AIF).
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 Resources Ltd. ("ARC") is one of Canada's largest conventional oil and gas
companies with an enterprise value of approximately $6.8 billion. ARC's common shares trade on the
TSX under the symbol ARX.
ARC RESOURCES LTD.
Myron M. Stadnyk
President and Chief Executive Officer
SOURCE ARC Resources Ltd.