CALGARY, Feb. 25, 2021 - Advantage Oil & Gas Ltd. ("Advantage" or the "Corporation") is pleased to announce increased 2021 production guidance, reduced 2021 capital guidance, and 2020 year-end results and reserves highlights.
Results from Advantage's 2020 drilling program have exceeded expectations both in costs and well performance, positively impacting our 2020 reserves, financial outlook and 2021 guidance. Drilling in 2020 was entirely gas-focused at Glacier, with the first wells drilled in July and brought onstream in November.
Increasing 2021 production guidance range to 48,000 to 51,000 boe/d (from 47,000 to 49,000 boe/d)
Average initial well productivity at Glacier from 2020 wells increased 87% over prior programs
Only six of 13 wells drilled in 2020 were brought on-production prior to year-end, with the remainder brought on-production in early 2021 while gas prices were escalating
Improved cycle times to equip wells and deliver production to market within 3 days
Five wells drilled in Q1 2021 will be completed after spring breakup with production anticipated to begin in third quarter 2021
Frac intensity and well design will continue to be progressed through the 2021 program
Reducing 2021 capital guidance range to $115 million to $135 million (from $125 million to $150 million)
2021 capital efficiency(a) expected to be approximately $8,400/boe/d
Reduced drilling, completions and tie-in costs by 20%, allowing 2 wells to be added to the winter program without increasing total capital
Focus will remain on gas drilling, and additional oil infrastructure has been deferred into 2022
Significant flexibility remains in the capital spending plan, with optionality to throttle capital between oil-weighted and gas-weighted assets and strategic investments
Reinforcing corporate strategy:
Advantage believes that disciplined investment and balance sheet strength are crucial to maximize returns for our shareholders. Based on current futures pricing, our net debt to AFF(a) ratio is forecast to be 1x by exit 2021. Capital required to sustain production is less than $75 million per year, due to our quality assets and low annual decline rate of 23%. In 2021 Advantage anticipates delivering approximately $70 million of free cash flow(a) (after capital) and over a three-year period, can generate $225 million of free cash flow(a) while growing 7% per year. This financial strength will provide the basis to:
Continue to deliver moderate annual production growth (between 5% and 10%) utilizing existing capacity at our Glacier Gas Plant, given a constructive gas price outlook
Enhance corporate resilience and scale through:
growing our liquids production, balancing our high exposure to gas pricing
revenue-generating cleantech investments that leverage our carbon capture and sequestration expertise
acquisitions that create efficiencies and scale
Potentially return capital to shareholders
2020 Financial Highlights
Annual 2020 cash provided by operating activities of $101 million and adjusted funds flow(a) of $105 million or $0.56/share
Maintained low cash costs including operating costs of $2.43/boe, royalties of $0.64/boe, transportation expenses of $3.39/boe, general and administrative costs of $0.69/boe and finance costs of $1.11/boe
Sold 12.5% working interest in the Glacier Gas Plant for $100 million
Reduced net debt(a) to $251 million from $304 million
Year-end net debt to AFF(a) was 2.4 with bank debt of $247 million drawn on the Corporation's $350 million credit facility
Although commodity pricing was unusually volatile, Advantage successfully exited 2020 in a stronger position than it entered. By reducing capital spending, fortifying the balance sheet and focusing on highest return development projects, Advantage is accelerating into 2021 and capitalizing on the constructive natural gas pricing fundamentals.
a. Non-GAAP Measure which may not be comparable to similar non-GAAP measures used by other entities. Please see Advisory for reconciliations to the nearest measure calculated in accordance with GAAP.
Financial Highlights
Three months ended
December 31
Year ended
December 31
($000, except as otherwise indicated)
2020
2019
2020
2019
Financial Statement Highlights
Sales including realized derivatives
$
69,930
$
76,921
$
240,058
$
275,237
Net income (loss) and comprehensive income (loss)
$
24,168
$
(1,844)
$
(284,045)
$
(24,654)
per basic share (2)
$
0.13
$
(0.01)
$
(1.51)
$
(0.13)
Basic weighted average shares (000)
188,113
186,911
187,761
186,659
Cash provided by operating activities
$
30,260
$
39,965
$
100,714
$
156,063
Cash provided by financing activities
$
5,071
$
20,037
$
48,087
$
24,317
Cash used in investing activities
$
37,325
$
50,365
$
158,621
$
173,640
Other Financial Highlights
Adjusted funds flow (1)
$
31,738
$
44,452
$
104,661
$
155,180
per boe (1)
$
7.92
$
10.20
$
6.37
$
9.59
per basic share (1)(2)
$
0.17
$
0.23
$
0.56
$
0.83
Net capital expenditures (1)
$
32,390
$
59,609
$
157,935
$
184,922
Working capital deficit (1)
$
4,292
$
7,996
$
4,292
$
7,996
Bank indebtedness
$
247,105
$
295,624
$
247,105
$
295,624
Net debt (1)
$
251,397
$
303,620
$
251,397
$
303,620
1.
Non-GAAP measure which may not be comparable to similar non-GAAP measures used by other entities. Please see "Non-GAAP Measures".
2.
Based on basic weighted average shares outstanding.
2020 Operational Highlights
Record annual production of 44,922 boe/d (243 mmcf/d natural gas, 2,379 bbls/d crude oil and condensate, and 2,029 bbls/d NGLs). Exit production was 45,850 boe/d (247 mmcf/d natural gas, 2,219 bbls/d crude oil and condensate, and 2,464 bbls/d NGLs).
Record annual liquids production of 4,408 bbls/d (up 63%).
Drilled 13 wells at Glacier. Initial well productivity increased by 87%, resulting from enhanced execution strategies. The first 10 wells drilled at Glacier were producing 95 mmcf/d after an average of 60 days on production and the remaining wells recently came onstream at similar per well levels.
Cycle times between completion and permanent production reduced to 3 days.
De-risked two new liquids-weighted core areas (Progress and Wembley), resulting in annual liquids production increase of 63%.
Constructed and commissioned Wembley oil battery and expanded Progress infrastructure
Capital efficiency(a) was $14,650/boe/d, including $70 million for major facilities projects, and $8,150/boe/d excluding major facilities expenditures.
Operating Highlights
Three months ended
December 31
Year ended
December 31
2020
2019
2020
2019
Operating
Production
Crude oil and condensate (bbls/d)
2,306
1,337
2,379
1,166
NGLs (bbls/d)
2,234
1,694
2,029
1,534
Total liquids production (bbls/d)
4,540
3,031
4,408
2,700
Natural gas (mcf/d)
233,949
266,035
243,081
249,802
Total production (boe/d)
43,532
47,370
44,922
44,334
Average realized prices (including realized derivatives)
Natural gas ($/mcf)
$
2.45
$
2.58
$
2.02
$
2.49
Crude oil and condensate ($/bbl)
$
55.08
$
68.53
$
48.58
$
67.34
NGLs ($/bbl)
$
27.04
$
33.75
$
24.35
$
35.31
Operating Netback ($/boe)
Petroleum and natural gas sales from production
$
18.28
$
17.69
$
14.91
$
15.53
Net sales of natural gas purchased from third parties (1)
-
-
-
(0.09)
Realized gains (losses) on derivatives
(0.74)
(0.04)
(0.28)
1.48
Royalty expense
(0.77)
(0.51)
(0.64)
(0.29)
Operating expense
(2.68)
(1.89)
(2.43)
(1.98)
Transportation expense
(3.62)
(3.46)
(3.39)
(3.50)
Operating netback (1)
$
10.47
$
11.79
$
8.17
$
11.15
1.
Non-GAAP measure which may not be comparable to similar non-GAAP measures used by other entities. Please see "Non-GAAP Measures".
2020 Reserve Evaluation by Sproule Associates Limited ("Sproule")
2020 Reserves Highlights
Proved Developed Producing ("PDP") additions were 120% of 2020 total production, at a finding and development ("F&D") cost of $8.41/boe.
Proved plus Probable ("2P") additions were 500% of 2020 total production, at an F&D cost of $2.80/boe.
Average 2P reserves per booked location increased 18% as a result of enhanced geological targeting and frac designs, leading to increased confidence in higher reserve recoveries. These results were the basis for 367 bcfe of positive technical revision.
Reserves life index ("RLI") for PDP was 7 years, 1P was 24 years, 2P was 34 years based on the Corporation's average fourth quarter 2020 production rate of approximately 43,532 boe/d.
2020 Reserves Highlights
PDP
1P (1)
2P
2020 Reserves (million boe)
109.9
387.0
532.0
2020 F&D Cost ($/per boe, including FDC(2))
$8.41
$3.63
$2.80
2020 Recycle ratio
1.2
2.9
3.7
2020 Reserves Increase Over 2019
3.7%
9.7%
14.2%
(1) Proved reserves ("1P").
(2) Future development capital ("FDC").
RESERVES SUMMARY TABLES
Company Gross (before royalties) Working Interest Reserves Summary as at December 31, 2020
Light & Medium Crude Oil
(mbbl)
Conventional Natural Gas
(mmcf)
Natural
Gas Liquids
(mbbl)
Total Oil Equivalent
(mboe)
Proved
Developed Producing
1,382
616,445
5,731
109,854
Developed Non-producing
-
3,309
8
559
Undeveloped
6,863
1,522,632
15,975
276,610
Total Proved
8,245
2,142,386
21,714
387,023
Probable
5,838
786,756
8,046
145,011
Total Proved + Probable
14,083
2,929,142
29,760
532,034
(1)
Table may not add due to rounding.
Company Net Present Value of Future Net Revenue using the IQRE Average Forecasts (1)(2)(3)($000)
Before Income Taxes Discounted at
0%
10%
15%
Proved
Developed Producing
1,227,332
741,275
621,688
Developed Non-producing
2,764
539
69
Undeveloped
2,999,967
740,744
428,676
Total Proved
4,230,063
1,482,558
1,050,432
Probable
2,382,972
708,514
481,035
Total Proved + Probable
6,613,035
2,191,072
1,531,467
(1)
Advantage's light and medium oil, conventional natural gas and natural gas liquid reserves were evaluated using the IQRE Average Forecast effective December 31, 2020 prior to the provision for income taxes, interests, debt services charges and general and administrative expenses. It should not be assumed that the discounted future net revenue estimated by Sproule represents the fair market value of the reserves.
(2)
Assumes that development of reserves will occur, without regard to the likely availability to the Corporation of funding required for that development.
(3)
Future Net Revenue incorporates Managements' estimates of required abandonment and reclamation costs, including expected timing such costs will be incurred, associated with all wells, facilities and infrastructure.
(4)
Table may not add due to rounding.
IQRE Average Forecasts
The net present value of future net revenue at December 31, 2020 was based upon light and medium oil, conventional natural gas and natural gas liquid pricing assumptions, which was computed by using the average of the forecasts ("IQRE Average Forecast") prepared by McDaniel & Associates Consultants Ltd., GLJ Petroleum Consultants and Sproule effective December 31, 2020. These forecasts are adjusted for reserves quality, transportation charges and the provision of any applicable sales contracts. The price assumptions used over the next seven years are summarized in the table below:
Year
Canadian Light Sweet Crude 40o API ($Cdn/bbl)
Alberta AECO-C
Natural Gas
($Cdn/mmbtu)
Edmonton
Propane
($Cdn/bbl)
Edmonton
Butane
($Cdn/bbl)
Edmonton
Pentanes Plus
($Cdn/bbl)
Exchange
Rate
($US/$Cdn)
2021
55.76
2.78
18.18
26.36
59.24
0.77
2022
59.89
2.70
21.91
32.85
63.19
0.77
2023
63.48
2.61
24.57
39.20
67.34
0.76
2024
65.76
2.65
25.47
40.65
69.77
0.76
2025
67.13
2.70
26.00
41.50
71.18
0.76
2026
68.53
2.76
26.54
42.36
72.61
0.76
2027
69.95
2.81
27.09
43.24
74.07
0.76
Company Gross (before royalties) Working Interest Reserves Reconciliation (1):
Proved
Light & Medium Crude Oil
(mbbl)
Conventional Natural Gas
(mmcf)
Natural Gas
Liquids
(mbbl)
Total Oil
Equivalent
(mboe)
Opening balance Dec. 31, 2019
6,679
1,934,120
23,792
352,824
Extensions and improved recovery
2,654
81,848
1,632
17,927
Technical revisions(1)
(279)
230,115
(2,544)
35,530
Discoveries
-
-
-
-
Acquisitions
-
-
-
-
Dispositions
-
-
-
-
Economic factors
(200)
(14,730)
(162)
(2,818)
Production
(609)
(88,967)
(1,004)
(16,441)
Closing balance at Dec. 31, 2020
8,245
2,142,386
21,714
387,023
Proved Plus Probable
Light & Medium Crude Oil
(mbbl)
Conventional Natural Gas
(mmcf)
Natural Gas
Liquids
(mbbl)
Total Oil
Equivalent
(mboe)
Opening balance Dec. 31, 2019
12,652
2,526,042
32,046
465,705
Extensions and improved recovery
3,554
111,184
2,184
24,269
Technical revisions(1)
(1,315)
394,900
(3,314)
61,188
Discoveries
-
-
-
-
Acquisitions
-
-
-
-
Dispositions
-
-
-
-
Economic factors
(199)
(14,016)
(152)
(2,687)
Production
(609)
(88,967)
(1,004)
(16,441)
Closing balance at Dec. 31, 2020
14,083
2,929,142
29,760
532,034
(1)
Technical revisions accounted for 66% of the total proved additions and 72% of the total proved plus probable additions. Percentage of each category calculated by dividing the technical revisions in the category by the total reserve additions in the same category before production.
(2)
Tables may not add due to rounding.
Company 2020 F&D Costs - Gross (before royalties) Working Interest Reserves including FDC (1)(2)(3)
Proved
Proved + Probable
Net capital expenditures ($000)(a)
157,935
157,935
Net change in FDC ($000)
25,961
73,925
Total capital ($000)
183,897
231,860
Total mboe, end of year
387,023
532,034
Total mboe, beginning of year
352,824
465,705
Production, mboe
(16,441)
(16,441)
Reserve additions, mboe
50,640
82,770
2020 F&D costs ($/boe)
$3.63
$2.80
2019 F&D costs ($/boe)
$4.26
$5.94
Three-year average F&D costs ($/boe)
$5.10
$4.80
(1)
F&D costs are calculated by dividing total capital by reserve additions during the applicable period. Total capital includes both capital expenditures incurred and changes in FDC required to bring the proved undeveloped and probable undeveloped reserves to production during the applicable period. Reserves additions are calculated as the change in reserves from the beginning to the ending of the applicable period excluding production.
(2)
The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated FDC generally will not reflect total finding and development costs related to reserves additions for that year. Changes in forecast FDC occur annually as a result of development activities, acquisition and disposition activities and capital cost estimates that reflect Sproule's best estimate of what it will cost to bring the proved undeveloped and probable undeveloped reserves on production.
(3)
The change in FDC is primarily from incremental undeveloped locations.
The reserves by category and year-over-year changes compared to 2019 are indicated below:
Reserve Category
Light & Medium Crude Oil Million bbls
Conventional Natural Gas Tcf
Natural Gas Liquids Million bbls
Total Oil Equivalent Million boe
% Change from 2019
PDP
1.38
0.62
5.73
109.9
3.7%
1P
8.24
2.14
21.71
387.0
9.7%
2P
14.08
2.93
29.76
532.0
14.2%
The total number of 2P future well locations booked in the Sproule 2020 Reserves Report are illustrated in the following table:
Sproule Number of Gross Horizontal Wells Booked
Developed
Undeveloped
Total
Glacier
222
281
503
Valhalla
14
17
31
Wembley
8
29
37
Progress
6
10
16
Total
250
337
587
With modern, low emissions-intensity assets and the Glacier carbon capture and sequestration asset, the Corporation continues to proudly deliver clean, reliable and sustainable energy, contributing to a reduction in global emissions by displacing high-carbon fuels. Advantage wishes to thank our employees, Board of Directors and our shareholders for their ongoing support.
The Corporation's audited consolidated financial statements for the fiscal year ended December 31, 2020 together with the notes thereto, and Management's Discussion and Analysis for the year ended December 31, 2020 have been filed on SEDAR and are available on the Corporation's website at https://www.advantageog.com/investors/financial-reports. The Corporation's audited consolidated financial statements for the fiscal year ended December 31, 2020 are also available on the Corporation's website via the same webpage. Upon request, Advantage will provide a hard copy of any financial reports free of charge.
Forward-Looking Information and Advisory The information in this press release contains certain forward-looking statements, including within the meaning of applicable securities laws. These statements relate to future events or our future intentions or performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "anticipate", "continue", "demonstrate", "expect", "may", "can", "will", "believe", "would" and similar expressions and include statements relating to, among other things, Advantage's position, strategy and development plans and the benefits to be derived therefrom, 2021 production guidance; timing to bring wells on production; enhanced geological targeting and frac intensity will continue in 2021 drilling program; 2021 capital expenditures; expected 2021 capital efficiency; expected date for deferral of additional oil infrastructure; expected annual production growth; ability to grow AFF and free cash flow per share; Advantage's focus with respect to capital spending; the expectation that free cash flow will be directed to debt reduction and the debt to AFF ratio at exit at the end of 2021; how excess cash will be used and the benefits to be derived therefrom; anticipated free cash flow in 2021; the expected amount of sustaining capital; anticipated free cash flow and annual growth over a three year period; the number of estimated future well locations, and Advantage's expectations generally and with respect to its liquids development. Advantage's actual decisions, activities, results, performance or achievement could differ materially from those expressed in, or implied by, such forward-looking statements and accordingly, no assurances can be given that any of the events anticipated by the forward-looking statements will transpire or occur or, if any of them do, what benefits that Advantage will derive from them.
These statements involve substantial known and unknown risks and uncertainties, certain of which are beyond Advantage's control, including, but not limited to: changes in general economic , market and business conditions; industry conditions, including as a result of demand and supply effects resulting from the COVID-19 pandemic; actions by governmental or regulatory authorities including increasing taxes and changes in investment or other regulations; changes in tax laws, royalty regimes and incentive programs relating to the oil and gas industry; Advantage's success at acquisition, exploitation and development of reserves; unexpected drilling results; changes in commodity prices, currency exchange rates, net capital expenditures, reserves or reserves estimates and debt service requirements; the occurrence of unexpected events involved in the exploration for, and the operation and development of, oil and gas properties, including hazards such as fire, explosion, blowouts, cratering, and spills, each of which could result in substantial damage to wells, production and processing facilities, other property and the environment or in personal injury; changes or fluctuations in production levels; delays in anticipated timing of drilling and completion of wells; individual well productivity; competition from other producers; the lack of availability of qualified personnel or management; credit risk; changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; our ability to comply with current and future environmental or other laws; stock market volatility and market valuations; liabilities inherent in oil and natural gas operations; competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions; geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves; ability to obtain required approvals of regulatory authorities; and ability to access sufficient capital from internal and external sources. Many of these risks and uncertainties and additional risk factors are described in the Corporation's Annual Information Form which is available at www.sedar.com ("SEDAR") and www.advantageog.com. Readers are also referred to risk factors described in other documents Advantage files with Canadian securities authorities.
With respect to forward-looking statements contained in this press release, Advantage has made assumptions regarding, but not limited to: conditions in general economic and financial markets; the impact and duration thereof that the COVID-19 pandemic will have on (i) the demand for crude oil, NGLs and natural gas, (ii) the supply chain including the Corporation's ability to obtain the equipment and services it requires, and (iii) the Corporation's ability to produce, transport and/or sell its crude oil, NGLs and natural gas; effects of regulation by governmental agencies; current and future commodity prices and royalty regimes; the Corporation's current and future hedging program; future exchange rates; royalty rates; future operating costs; future transportation costs and availability of product transportation capacity; availability of skilled labor; availability of drilling and related equipment; timing and amount of net capital expenditures; the impact of increasing competition; the price of crude oil and natural gas; the number of new wells required to achieve the budget objectives; that the Corporation will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and requirements as needed; that the Corporation's conduct and results of operations will be consistent with its expectations; that the Corporation will have the ability to develop the Corporation's properties in the manner currently contemplated; current or, where applicable, proposed assumed industry conditions, laws and regulations will continue in effect or as anticipated; and the estimates of the Corporation's production and reserves volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects. Three year free cash flow estimates are based on gas-focused development at Glacier and commodity price assumptions including average AECO $2.65/mcf, Henry Hub US$2.75/mmbtu, WTI US$55/bbl, and $US/$CDN 0.79. All forward looking estimates include current hedging and market diversification transactions. Readers are cautioned that the foregoing lists of factors are not exhaustive.
Management has included the above summary of assumptions and risks related to forward-looking information above and in its continuous disclosure filings on SEDAR in order to provide shareholders with a more complete perspective on Advantage's future operations and such information may not be appropriate for other purposes. Advantage's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that Advantage will derive there from. Readers are cautioned that the foregoing lists of factors are not exhaustive. These forward-looking statements are made as of the date of this news release and Advantage disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.
Barrels of oil equivalent (boe) and thousand cubic feet of natural gas equivalent (mcfe) may be misleading, particularly if used in isolation. Boe and mcfe conversion ratios have been calculated using a conversion rate of six thousand cubic feet of natural gas equivalent to one barrel of oil. A boe and mcfe conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. References to natural gas or liquids production in this press release refer to conventional natural gas and natural gas liquids, respectively, product types as defined in National Instrument 51-101.
This press release contains a number of oil and gas metrics, including F&D cost, recycle ratio, reserve replacement, reserve life index, sustaining capital and operating netback, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included herein to provide readers with additional measures to evaluate the Corporation's performance; however, such measures are not reliable indicators of the future performance of the Corporation and future performance may not compare to the performance in previous periods and therefore such metrics should not be unduly relied upon. Management uses these oil and gas metrics for its own performance measurements and to provide securityholders with measures to compare Advantage's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied upon for investment or other purposes. F&D cost is calculated based on adding net capital expenditures and the net change in future development capital ("FDC"), divided by reserve additions for the year from the Sproule 2020 Reserves Report. Recycle ratio is calculated by dividing Advantage's fourth quarter operating netback by the calculated F&D cost of the applicable year and expressed as a ratio. Reserve replacement is calculated by dividing reserves net volume additions by the current annual production and expressed as a percentage. Reserve life index is calculated by dividing the total volume of reserves by the fourth quarter production rate and expressed in years. Reserves per share is calculated as the total volume of reserves divided by the number of common shares issued and outstanding at year end. Sustaining capital is Management's estimate of the capital required to drill, complete, equip and tie-in new wells to existing infrastructure thereby offsetting the corporate decline rate and maintain production at existing levels. Operating netback is calculated by adding natural gas and liquids sales with realized gains/losses on derivatives and subtracting royalty expense, operating expense, and transportation expense.
Sproule was engaged as an independent qualified reserve evaluator to evaluate Advantage's year-end reserves as of December 31, 2020 ("Sproule 2020 Reserves Report") in accordance with National Instrument 51-101 ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook"). Reserves are stated on a gross (before royalties) working interest basis unless otherwise indicated. Additional details are provided in the accompanying tables to this release and additional reserve information as required under NI 51-101 will be included in our Annual Information Form which will be filed on SEDAR on or about February 25, 2021. The recovery and reserve estimates of reserves provided in this news release are estimates only, and there is no guarantee that the estimated reserves will be recovered. Actual reserves may eventually prove to be greater than, or less than, the estimates provided herein.
This press release discloses undeveloped drilling locations in two categories: (i) proved locations; and (ii) probable locations. Proved locations and probable locations are derived from the Sproule 2020 Reserves Report and account for drilling locations that have associated proved and/or probable reserves, as applicable. Of the 337 total undeveloped drilling locations identified herein, 299 are proved locations with 255 in Glacier, 16 in Valhalla, 22 in Wembley and 6 in Progress. Of the 38 probable locations, 26 are in Glacier, 1 in Valhalla, 7 in Wembley and 4 in Progress.
References in this press release to short-term production rates are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. Additionally, such rates may also include recovered "load oil" fluids used in well completion stimulation. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production of Advantage.
Non-GAAP Measures The Corporation discloses several financial and performance measures in this press release that do not have any standardized meaning prescribed under GAAP. These financial and performance measures include "net capital expenditures", "adjusted funds flow", "adjusted funds flow per share", "adjusted funds flow per boe", "free cash flow", "operating netback", "net debt", "net debt to adjusted funds flow", "working capital", "capital efficiency" and "net sales of natural gas purchased from third parties", which should not be considered as alternatives to, or more meaningful than "net income", "comprehensive income", "cash provided by operating activities", "cash used in investing activities", or "bank indebtedness" presented within the consolidated financial statements as determined in accordance with GAAP. Management believes that these measures provide an indication of the results generated by the Corporation's principal business activities and provide useful supplemental information for analysis of the Corporation's operating performance and liquidity. Advantage's method of calculating these measures may differ from other companies, and accordingly, they may not be comparable to similar measures used by other companies.
Net Capital Expenditures
Net capital expenditures include total capital expenditures related to property, plant and equipment and exploration and evaluation assets incurred during the period. Management considers this measure reflective of actual capital activity for the period as it excludes changes in working capital related to other periods. A reconciliation between net capital expenditures and the nearest measure calculated in accordance with GAAP, cash used in investing activities, is provided below:
Three months ended
December 31
Year ended
December 31
($000)
2020
2019
2020
2019
Cash used in investing activities
$
37,325
$
50,365
$
158,621
$
173,640
Changes in non-cash working capital
(4,935)
9,244
(686)
11,282
Net capital expenditures
$
32,390
$
59,609
$
157,935
$
184,922
Working Capital
Working capital includes cash and cash equivalents, trade and other receivables, prepaid expenses and deposits and trade and other accrued payables at the reporting date. Working capital provides Management and users with a measure of the Corporation's operating liquidity.
Net Debt
Net debt is comprised of bank indebtedness and working capital. Net debt provides Management and users with a measure of the Corporation's indebtedness and expected settlement of net liabilities in the next year. A detailed calculation of net debt is provided below:
($000)
December 31
2020
December 31
2019
Bank indebtedness (non-current)
$
247,105
$
295,624
Working capital deficit
4,292
7,996
Net debt
$
251,397
$
303,620
Adjusted Funds Flow
The Corporation considers adjusted funds flow to be a useful measure of Advantage's ability to generate cash from the production of natural gas and liquids, which may be used to settle outstanding debt and obligations, and to support future capital expenditures plans. Changes in non-cash working capital and other long-term liabilities are excluded from adjusted funds flow as they may vary significantly between periods and are not considered to be indicative of the Corporation's operating performance as they are a function of the timeliness of collecting receivables or paying payables. Expenditures on decommissioning liabilities are excluded from the calculation as the amount and timing of these expenditures are unrelated to current production, highly variable and discretionary. Adjusted funds flow has also been presented per boe, by dividing adjusted funds flow by total production in boe for the reporting period, and per basic share, by dividing by the basic weighted average shares outstanding of the Corporation. A reconciliation between adjusted funds flow and the nearest measure calculated in accordance with GAAP, cash provided by operating activities, is provided below:
Three months ended
December 31
Year ended
December 31
($000, except as otherwise indicated)
2020
2019
2020
2019
Cash provided by operating activities
$
30,260
$
39,965
$
100,714
$
156,063
Expenditures on decommissioning liability
610
85
1,080
1,911
Changes in non-cash working capital
868
4,402
2,867
(2,794)
Adjusted funds flow
$
31,738
$
44,452
$
104,661
$
155,180
Net Debt to Adjusted Funds Flow
Net debt to adjusted funds flow is calculated by dividing net debt by adjusted fund flow for the previous four quarters. Net debt to adjusted funds flow is a coverage ratio that provides Management and users the ability to determine how long it would take the Corporation to repay its debt if it devoted all its adjusted funds flow to debt repayment.
Free Cash Flow
Free cash flow is calculated as adjusted funds flow less net capital expenditures. Free cash flow is a useful measure of Advantage's ability to settle outstanding debt and obligations.
Operating Netback
Advantage calculates operating netback on a per boe basis. Operating netback is comprised of sales revenue, realized gains (losses) on derivatives and net sales of natural gas purchased from third parties, net of expenses resulting from field operations, including royalty expense, operating expense and transportation expense. Operating netback provides Management and users with a measure to compare the profitability of field operations between companies, development areas and specific wells.
Three months ended
December 31
2020
2019
$000
per boe
$000
per boe
Petroleum and natural gas sales from production
$
73,203
$
18.28
$
77,102
$
17.69
Realized losses on derivatives
(2,949)
(0.74)
(181)
(0.04)
Royalty expense
(3,067)
(0.77)
(2,231)
(0.51)
Operating expense
(10,750)
(2.68)
(8,225)
(1.89)
Transportation expense
(14,488)
(3.62)
(15,072)
(3.46)
Operating netback
$
41,949
$
10.47
$
51,393
$
11.79
Year ended
December 31
2020
2019
$000
per boe
$000
per boe
Petroleum and natural gas sales from production
$
245,085
$
14.91
$
251,279
$
15.53
Net sales of natural gas purchased from third parties (1)
-
-
(1,505)
(0.09)
Realized gains (losses) on derivatives
(4,640)
(0.28)
23,958
1.48
Royalty expense
(10,474)
(0.64)
(4,690)
(0.29)
Operating expense
(40,005)
(2.43)
(31,967)
(1.98)
Transportation expense
(55,817)
(3.39)
(56,607)
(3.50)
Operating netback
$
134,149
$
8.17
$
180,468
$
11.15
Net Sales of Natural Gas Purchased from Third Parties
Net sales of natural gas purchased from third parties represents the revenue or loss generated from the sale of natural gas volumes purchased from third parties, after deducting the cost to purchase the volumes. The purchase and sale transactions are non-routine and are considered by Management to be related for performance purposes.
The following terms and abbreviations used in this press release have the meanings set forth below:
Capital Efficiency
Three-year and single year capital efficiency is calculated by dividing net capital development costs for oil and gas activities including drilling, completion, facilities, infrastructure, office and capitalized general and administrative costs (excluding abandonment and reclamation costs, exploration and evaluation costs, and acquisition and disposition related costs and proceeds) by the average production additions of the applicable year to replace base production declines and deliver production growth targets, expressed in $/boe/d. Capital efficiency is considered by management to be a useful performance measure as a common metric used to evaluate the efficiency with which capital activity is allocated to achieve production additions.
The following abbreviations used in this press release have the meanings set forth below:
bbl
one barrel
bbls
barrels
bbls/d
barrels per day
boe
barrels of oil equivalent of natural gas, on the basis of one barrel of oil or NGLs for six thousand cubic feet of natural gas
boe/d
barrels of oil equivalent of natural gas per day
mbbl
thousand barrels
mboe
thousand barrels of oil equivalent of natural gas
mcf
thousand cubic feet
mcf/d
thousand cubic feet per day
mcfe
thousand cubic feet equivalent on the basis of six thousand cubic feet of natural gas for one barrel of oil or NGLs
mmcf
million cubic feet
mmcf/d
million cubic feet per day
mmbtu
million British thermal units
mmcfe/d
million cubic feet equivalent per day
tcf
trillion cubic feet
tcfe
trillion cubic feet equivalent
Liquids or NGLs
Natural Gas Liquids as defined in National Instrument 51-101
Natural Gas
Conventional Natural Gas as defined in National Instrument 51-101
Crude Oil
Light Crude Oil and Medium Crude Oil as defined in National Instrument 51-101
