Coast Copper Corp. — Audit Report / Information 2020

Apr 16, 2021

DISTINCTION ENERGY CORP.

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION (FORM 51-101F1)

National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) establishes a standard of disclosure for all Canadian reporting issuers in upstream oil and natural gas activities and reserves definitions for proved and probable reserves categories. The reserves disclosure presented below conforms to the requirements of NI 51-101. All of Distinction Energy Corp.’s (“ Distinction ” or the “ Corporation ”) reserves are in western Canada, specifically in the province of Alberta.

The Corporation engaged GLJ Ltd. (“ GLJ ”), independent qualified reserves evaluators, to evaluate and report on 100 percent of the Corporation’s proved and proved plus probable reserves. The crude oil, natural gas and natural gas liquids reserves of the Corporation were evaluated by GLJ, with an effective date of December 31, 2020 in a report dated March 5, 2021 (the “ GLJ Report ”).

Definitions, abbreviations, notes and conversions used throughout the following tables can be found in Appendix “A”.

The use of the boe unit of measurement may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf of natural gas to 1 barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. The estimated future net revenue contained in the following tables does not represent the fair market value of reserves associated with Distinction’s assets and properties. Tables may not add due to rounding.

The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

Reserves Data (Forecast Prices and Costs)

Reserves Summary (Forecast Prices and Costs)

Proved(3) (6) Developed producing(4) Developed non-producing(4) Undeveloped(5) Total proved Probable(3) (6) Total proved plus probable	Conventional Natural Gas (Mmcf)	Conventional Natural Gas (Mmcf)	Shale Gas (Mmcf)	Shale Gas (Mmcf)	Natural Gas Liquids (Mbbls)	Natural Gas Liquids (Mbbls)	Boe (6:1) (Mboe)	Boe (6:1) (Mboe)
	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)
	3,961 - -	3,530 - -	45,831 - 58,678	41,461 - 55,387	4,942 - 7,804	3,815 - 6,977	13,241 - 17,584	11,313 - 16,208
	3,961 4,631	3,530 4,161	104,509 95,954	96,848 89,537	12,746 13,946	10,792 11,242	30,825 30,710	27,522 26,858
	8,592	7,690	200,462	186,385	26,692	22,034	61,534	54,380

Net Present Value of Future Net Revenue Summary (Forecast Prices and Costs)

Proved(3) (6) Developed producing(4) Developed non-producing(4) Undeveloped(5) Total proved Probable(3) (6) Total proved plus probable		Before Income Taxes Discounted at	Before Income Taxes Discounted at	Before Income Taxes Discounted at		Unit Value Before Income Tax Discounted at 10%	Unit Value Before Income Tax Discounted at 10%
	0%	5%	10%	15%	20%
	($ 000’s)	($ 000’s)	($ 000’s)	($ 000’s)	($ 000’s)	$/boe	$/Mcfe
	140,701 - 157,752	121,706 - 91,793	106,304 - 52,313	94,206 - 27,940	84,655 - 12,372	17.34 - 6.24	2.89 - 1.04
	298,453 473,353	213,499 267,525	158,617 169,809	122,146 118,299	97,027 88,429	11.22 11.10	1.87 1.85
	771,807	481,024	328,426	240,445	185,456	11.16	1.86

Proved(3) (6) Developed producing(4) Developed non-producing(4) Undeveloped(5) Total proved Probable(3) (6) Total proved plus probable	After Income Taxes Discounted at 0% 5% 10% 15% 20%
	($ 000’s) ($ 000’s) ($ 000’s) ($ 000’s) ($ 000’s)
	140,701 121,706 106,304 94,206 84,655 - - - - - 157,752 91,793 52,313 27,940 12,372 298,453 213,499 158,617 122,146 97,027 366,464 211,927 138,079 98,898 75,934
	664,917 425,426 296,696 221,044 172,961

Total Future Net Revenue (Undiscounted)

Proved(3) (6) Developed producing(4) Developed non- producing(4) Undeveloped(5) Total proved Probable(3) (6) Total proved plus probable	Revenue	Royalties	Operating Costs	Capital Development Costs	Well Abandonment and Reclamation Costs	Future Net Revenue Before Income Taxes	Income Taxes(8)	Future Net Revenue After Income Taxes
	($ 000’s)	($ 000’s)	($ 000’s)	($ 000’s)	($ 000’s)	($ 000’s)	($ 000’s)	($ 000’s)
	397,853 - 636,133	63,809 - 58,167	179,282 - 210,311	1,240 - 203,970	12,821 - 5,932	140,701 - 157,752	- - -	140,701 - 157,752
	1,033,986 1,265,330	121,977 209,065	389,593 394,413	205,210 180,350	18,752 8,149	298,453 473,354	- 106,890	298,453 366,464
	2,299,316	331,041	784,006	385,561	26,901	771,807	106,890	664,917

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Future Net Revenue by Product Type (Forecast Prices and Costs)

Reserve Category	**Product Type **	Future Net Revenue Before Income Taxes (discounted at 10%)	Future Net Revenue Before Income Taxes (discounted at 10%)	Future Net Revenue Before Income Taxes (discounted at 10%)
Proved Producing Total Proved Total Proved Plus Probable	Conventional natural gas (including by-products) Shale gas (including by-products) TOTAL Conventional natural gas (including by-products) Shale gas (including by-products) TOTAL Conventional natural gas (including by-products) Shale gas (including by-products) TOTAL	($ 000’s) 1,873 104,431	$/boe 3.18 8.39	$/Mcfe 0.53 1.40
		106,304	8.03	1.34
		1,873 156,744	3.18 9.72	0.53 1.62
		158,617	5.76	0.96
		5,047 323,379	3.96 10.44	0.66 1.74
		328,426	6.04	1.01

Summary of Pricing Assumptions

This summary table identifies the benchmark reference pricing provided by GLJ, Distinction’s independent qualified reserves evaluators, and used in the evaluation of the Corporation’s reserves.

Pricing assumptions	Light and Medium Oil	Light and Medium Oil	Natural Gas Liquids	Natural Gas Liquids	Natural Gas Liquids	Conventional Natural Gas and Shale Gas	Conventional Natural Gas and Shale Gas	Inflation Rate	Exchange Rate
	West Texas Intermediate Cushing Oklahoma (US$/bbl)	Edmonton Par Price 40 API (Cdn$/bbl)	Edmonton Propane (Cdn$/bbl)	Edmonton Butane (Cdn$/bbl)	Edmonton Pentanes Plus (Cdn$/bbl)	U.S. Henry Hub Gas Price (US$/Mmbtu)	AECO/NIT spot price (Cdn$/Mmbtu)	%/year	US$/Cdn$
Forecast 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031+	48.00 51.50 54.50 57.79 58.95 60.13 61.33 62.56 63.81 65.09 +2.0%/yr	55.49 60.78 63.82 68.14 69.67 71.22 72.80 74.42 76.07 77.59 +2.0%/yr	19.43 24.31 25.53 27.26 27.87 28.49 29.12 29.77 30.43 31.03 +2.0%/yr	27.75 36.47 41.48 44.29 45.29 46.30 47.32 48.37 49.44 50.43 +2.0%/yr	60.65 65.36 70.07 74.72 76.25 77.80 79.38 81.00 82.64 84.30 +2.0%/yr	2.75 2.80 2.85 2.90 2.95 3.01 3.07 3.13 3.19 3.25 +2.0%/yr	2.72 2.67 2.60 2.60 2.65 2.71 2.76 2.81 2.87 2.92 +2.0%/yr	0.0 1.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0	0.775 0.765 0.760 0.760 0.760 0.760 0.760 0.760 0.760 0.760 0.760

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The Corporation received the following weighted average prices in 2020, excluding gains and losses on financial and physical commodity price contracts.

Conventional Natural gas ($/mcf) 2.45	Natural gas liquids ($/bbl) 33.58	Total ($/boe)
		23.14

Reconciliation of Corporation’s Gross[(1)] Reserves Using Forecast Prices and Costs

December 31, 2019 Extensions and Improved Recovery Technical revisions Discoveries Acquisitions Dispositions Economic factors Production	Conventional Natural Gas(Mmcf) Proved Probable Proved Plus Probable 5,016 5,499 10,515 - - - (85) (650) (735) - - - - - - - - - (246) (218) (463) (725) - (725)	Conventional Natural Gas(Mmcf) Proved Probable Proved Plus Probable 5,016 5,499 10,515 - - - (85) (650) (735) - - - - - - - - - (246) (218) (463) (725) - (725)	Conventional Natural Gas(Mmcf) Proved Probable Proved Plus Probable 5,016 5,499 10,515 - - - (85) (650) (735) - - - - - - - - - (246) (218) (463) (725) - (725)	Shale Gas(Mmcf) Proved Probable Proved Plus Probable 103,523 97,460 200,982 11,630 (4,806) 6,824 5,179 1,492 6,671 - - - 2,346 819 3,165 - - - (10,751) 988 (9,763) (7,418) - (7,418)	Shale Gas(Mmcf) Proved Probable Proved Plus Probable 103,523 97,460 200,982 11,630 (4,806) 6,824 5,179 1,492 6,671 - - - 2,346 819 3,165 - - - (10,751) 988 (9,763) (7,418) - (7,418)	Shale Gas(Mmcf) Proved Probable Proved Plus Probable 103,523 97,460 200,982 11,630 (4,806) 6,824 5,179 1,492 6,671 - - - 2,346 819 3,165 - - - (10,751) 988 (9,763) (7,418) - (7,418)
	Proved 5,016 - (85) - - - (246) (725)	Probable 5,499 - (650) - - - (218) -		Proved 103,523 11,630 5,179 - 2,346 - (10,751) (7,418)	Probable 97,460 (4,806) 1,492 - 819 - 988 -
December 31,2020	3,961	4,631	8,592	104,509	95,954	200,462

December 31, 2019 Extensions and Improved Recovery Technical revisions Discoveries Acquisitions Dispositions Economic factors Production	Natural Gas Liquids(Mbbls) Proved Probable Proved Plus Probable 12,005 11,102 23,107 1,797 2,315 4,112 909 77 986 - - - 379 152 531 - - - (1,264) 301 (963) (1,079) - (1,079)	Natural Gas Liquids(Mbbls) Proved Probable Proved Plus Probable 12,005 11,102 23,107 1,797 2,315 4,112 909 77 986 - - - 379 152 531 - - - (1,264) 301 (963) (1,079) - (1,079)	Natural Gas Liquids(Mbbls) Proved Probable Proved Plus Probable 12,005 11,102 23,107 1,797 2,315 4,112 909 77 986 - - - 379 152 531 - - - (1,264) 301 (963) (1,079) - (1,079)		Boe(Mboe)	Proved Plus Probable 58,356 5,249 1,975 - 1,058 - (2,668) (2,436)
	Proved 12,005 1,797 909 - 379 - (1,264) (1,079)	Probable 11,102 2,315 77 - 152 - 301 -		Proved 30,095 3,735 1,758 - 770 - (3,097) (2,436)	Probable 28,262 1,514 217 - 289 - 429 -
December 31,2020	12,746	13,946	26,692	30,825	30,710	61,534

The Corporation had a disciplined capital program in 2020 in which it drilled, completed and brought 3.0 (3.0 net) horizontal Montney wells on production in the Bigstone area. Proved developed producing extensions incorporated in the GLJ Report were the result of the 3.0 (3.0 net) above-mentioned Montney wells. Undeveloped Montney drilling locations in the GLJ Report decreased by 12 gross (6.8 net) in the total proved category and by 24 gross (17.5 net) in the total proved plus probable category compared to Distinction’s reserves report as at December 31, 2019. The reduction in well count is mainly due to changing the well density from 6 wells per section to 4 wells per section in liquid-rich west Bigstone. Overall, the Corporation’s reserves stayed flat or slightly increased across different categories while future development costs decreased resulting in a more capital efficient method of capturing the reserves. Changes in reserves due to extensions and improved recovery are due to the improvements in type curves for various areas as a result of improved completion techniques utilized by Distinction and results seen over 2020.

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Increase in reserves due to acquisitions represents the working interest of a partner who chose not to participate in 3 wells from the 2020 drilling program. Changes in reserves due to economic factors occur when there is a change in the economic limit of a well because of a change in factors including commodity prices, operating costs and transportations costs compared to the previous year. These changes are determined prior to any consideration of technical revisions. Decreases in reserves due to production represent reserves that were produced from the Corporation’s properties during 2020.

Additional Information Relating to Reserves Data

Undeveloped Reserves [(5)]

Proved and Probable Undeveloped Reserves

The following table sets forth the volumes of proved undeveloped and probable undeveloped reserves that were first attributed to each product type in each of the most recent three financial years:

Product Type Proved Undeveloped Shale gas Conventional natural gas Natural gas liquids Total	Units	2018	2019	2020
	Mmcf Mmcf Mbbl Mboe	26,309 - 3,722	9,671 - 1,325	9,485 - 1,365
		8,107	2,937	2,946

Probable Undeveloped Shale gas Mmcf Conventional natural gas Mmcf Natural gas liquids Mbbl Total Mboe	41,280 - 5,044	11,075 - 1,654	- - 2,358
	11,924	3,500	2,358

The future development costs are capital costs required in the future for Distinction to convert proved and probable undeveloped reserves into proved developed producing reserves. On an on-going basis Distinction typically uses its internally generated cash flow, proceeds from dispositions, available credit facilities and new equity financings, if available on favourable terms, to fund requirements for future development required to develop the proved or the proved plus probable reserves.

Development of undeveloped reserves within the GLJ Report are scheduled to deliver approximately 8,000 boe/d and 10,000 boe/d in total proved and total proved plus probable, respectively in 2022 and stay flat while the inventory lasts in each respective category. Sufficient processing capacity exists to support proved and proved plus probable undeveloped reserves coming on production. A number of other factors considered in determining the development schedule of undeveloped reserves include resource loading to address appropriate activity levels and the anticipated availability of free cash flow to fund development.

In the GLJ Report, Distinction has anticipated that approximately 40 percent of future development costs relating to the development of Distinction’s proved undeveloped reserves will occur within two years, and all future development costs in respect of these reserves are anticipated to occur within six years. In the GLJ Report, Distinction has anticipated that approximately 22 percent of future development costs relating to the development of Distinction’s undeveloped proved plus probable reserves will occur within two years

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and all future development costs in respect of these undeveloped reserves are anticipated to occur within 11 years to appropriately align with the Company’s cash flow from development.

Significant Factors or Uncertainties

The process of evaluating reserves is inherently complex and requires significant judgments and decisions based upon a number of variable factors and assumptions, such as commodity prices, projected production from the properties, the assumed effects of regulation by government agencies and future operating costs. All of these estimates may vary from actual results. The reserve estimates contained in this NI 51-101F1 disclosure are based on current production forecasts, prices and economic conditions. Estimates of the recoverable oil and natural gas reserves attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, may vary. The Corporation's actual production, revenues, taxes, development and operating expenditures with respect to its reserves may vary from such estimates and such variances could be material.

The Corporation estimates the total cost of future abandonment and reclamation for its existing wells, including their associated production facilities and infrastructure, and the expected timing of the costs to be incurred in future periods. The Corporation has a process for estimating these costs, which considers past experience, applicable current regulations, technology and industry standards, actual and anticipated costs, the type and depth of the well (or the nature and size of the facility), and the geographic location. The Corporation expects to incur abandonment and reclamation costs on 341 (205.6 net) wells, comprising currently producing and non-producing wells. As at December 31, 2020 the Corporation has estimated its share of the future abandonment and reclamation costs for its existing wells and facilities to be $42.8 million undiscounted (approximately $12.5 million discounted at 10%), of which the Corporation expects to spend approximately $3.3 million undiscounted over the next three financial years. Of the undiscounted future abandonment and reclamation costs to be incurred over the life of the Corporation’s proved developed producing reserves, approximately $12.8 million has been deducted in estimating the future net revenue in the GLJ Report. For total proved plus probable reserves, approximately $26.9 million of undiscounted future abandonment and reclamation costs has been deducted in estimating the future net revenue in the GLJ Report, which represents the Corporation’s total existing estimated abandonment and reclamation costs associated with the developed reserves, plus all forecast estimates of abandonment and reclamation costs attributable to future development activity associated with the undeveloped reserves. In the GLJ Report, abandonment and reclamation costs have been included only for wells with reserves assigned. Abandonment and reclamation costs for suspended wells with no reserves assigned, service wells, gathering systems, facilities and surface land have not been included in the GLJ Report but are included in the Corporation’s estimate of future abandonment and reclamation costs. The Corporation does not anticipate any unusually high expected development costs or operating costs in respect of its reserves.

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Future Development Costs (Forecast Prices and Costs)

Period 2021 2022 2023 2024 2025 Remainder Total for all years undiscounted Total for all years discounted at 10% per year	($ 000’s)	($ 000’s)
	Proved Reserves 31,015 50,084 30,623 50,339 33,528 9,621 205,210 160,171	Proved Plus Probable Reserves
		31,015 55,074 45,020 36,337 36,767 181,347
		385,867
		251,511

On an on-going basis, Distinction typically uses its internally generated cash flow, proceeds from dispositions, available credit facilities and new equity and debt financings, if available on favourable terms, to fund requirements for future development required to develop the proved or the proved plus probable reserves. Distinction evaluates the available financing alternatives closely and has made use of all of the foregoing options depending on the given investment situation and the capital markets. Distinction expects to continue to use all financing alternatives available to continue pursuing its development strategy. The various financing alternatives have certain inherent costs which are considered in the economic evaluation of pursuing any development opportunity.

There can be no guarantee that funds will be available or that Distinction will allocate funding to develop all of the reserves attributed in the GLJ Report. Failure to develop those reserves would have a negative impact on future production and cash flow and could result in negative revisions to reserves.

The interest or other costs of external funding are not included in the reserves and future net revenue estimates set forth above and would reduce the reserves and future net revenue to some degree depending upon the available funding sources. The Corporation does not anticipate that interest or other external funding costs would make further development of a property uneconomic for the Corporation.

Other Oil and Gas Information

Areas of Operations

Distinction’s core operating area, Bigstone, is in the Deep Basin of Northwest Alberta. The stacked, multizone opportunities containing liquid rich natural gas and oil make it an attractive area in the industry. The area is also extensively covered by the infrastructure required to bring hydrocarbon products to market.

Bigstone Montney

The liquids-rich Montney development project is located in the Bigstone area of Alberta, 150 kilometres southeast of Grande Prairie. The Montney formation is recognized as one of the world’s greatest deposits of hydrocarbons. It covers vast distances and many areas are now exploited with horizontal drilling combined with hydraulic fracturing. As the dataset of Montney production expands, a divergence between higher and lower economic value areas becomes apparent. Distinction’s Bigstone Montney has the combination of high deliverability, high liquid-gas ratios and access to markets that make it a higher value area. As of December 31, 2020, Distinction had a working interest in a total of 117 (76 net) sections of

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undeveloped and partially undeveloped land as part of 147 (97 net) sections of total land prospective for liquids-rich gas in the Montney formation.

The majority of production from the Montney is produced through the Corporation’s 65 percent owned 0711-060-23 W5M (“ 7-11 facility ”) compression and dehydration facility. The 7-11 facility includes an amine facility that is designed to sweeten up to 17 Mmcf/d gross (11.1 Mmcf/d net) of raw natural gas that can then be further processed at the Bigstone sweet natural gas plant in which the Corporation owns 25 percent. In 2020, Distinction spent $0.5 million on building a pump station and other required infrastructure at its 7-11 facility to tie into a third party field condensate pipeline. The third party pipeline transports the majority of the Corporation’s field condensate to a sales point in Fox Creek, Alberta, eliminating the majority of field condensate trucking costs.

Approximately 50% of Distinction’s Montney gas was processed at the Energy Transfer Kaybob South 3 processing plant (“ K3 plant ”) in 2020 and the remaining Montney gas, that is sweetened through the amine facility, was processed at Bigstone gas plant, with a gross capacity of 85 Mmcf/d, which the Corporattion has 25 percent working interest in. Natural gas processed at K3 plant is sold into the Chicago market via Distinction’s full-path firm service with Alliance Pipeline Ltd. (“ Alliance ”). Natural gas processed at Bigstone gas plant is currently shipped on the Nova Gas Transmission system (“ NGTL ”) and sold into the AECO market prior to an Alliance Pipeline lateral that is expected to be reactivated in 2022.

Bigstone Cretaceous (Sweet)

The sweet natural gas production from the shallower Cretaceous zones at Bigstone is the Corporation’s second largest producing asset, contributing an average of 674 boe/d of production in 2020, with 14 percent as oil and natural gas liquids. Of this, fuel gas of 745mcf/d (124 boe/d) is allocated for the facility operations, resulting in net average daily production of 550 boe/d. In addition to the ownership in the Bigstone gas plant, the Corporation has over 40 kilometres of field gathering infrastructure as well as a 100 percent working interest in a 15 Mmcf/d sweet shallow cut natural gas processing plant at West Bigstone.

Oil and Gas Properties and Wells (All Onshore)

The following table sets forth the number and status of wells in which Distinction had a working interest as at December 31, 2020. Distinction has title to its net working interest in all wells and is not subject to any change in ownership as a consequence of any current contract or agreement.

Alberta British Columbia	Producing Wells	Producing Wells	Producing Wells	Producing Wells	Non-Producing Wells	Non-Producing Wells	Non-Producing Wells	Non-Producing Wells
	Oil		Gas		Oil		Gas
	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)
	3 -	2.3 -	121 -	94.8 -	15 -	13.6 -	164 38	76.0 18.9
	3	2.3	121	94.8	15	13.6	202	94.9

Of the 217 (108.5 net) non-producing wells, 100 (47.4 net) have been abandoned and 42 (22.1 net) have had zonal abandonments.

Distinction does not have any properties to which reserves have been attributed and which are capable of producing, but which are not producing.

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Properties with No Attributed Reserves

The following table sets forth the Corporation’s unproved land holdings as at December 31, 2020.

(Acres) Alberta British Columbia Total	Unproved	Unproved
	Gross(1) 89,062 30,108 119,170	Net(2)
		46,759 12,237
		58,996

During 2021, approximately 28,450 net acres of the Corporation’s land is set to expire, however Distinction expects that, subject to Crown approval, approximately 65% of these lands will be continued.

None of the above properties are subject to any work commitments.

Significant Factors or Uncertainties Relevant to Properties with No Attributed Reserves

There are several economic factors and significant uncertainties that affect Distinction’s anticipated development of its properties to which no reserves are attributed. Distinction will be required to make substantial capital expenditures in order to prove, exploit, develop and produce from these properties in the future. If cash flow from operations is not sufficient to satisfy its capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or, if available, on terms acceptable to the Corporation. Failure to obtain such financing on a timely basis could cause the Corporation to forfeit its interest in certain properties, miss certain opportunities and reduce or terminate its operations on such properties. The inability of Distinction to access sufficient capital for its exploration and development purposes could have a material adverse effect on the Corporation’s ability to execute its business strategy to develop these prospects.

The primary economic factors that affect the development of the properties to which no reserves have been attributed are future commodity prices for oil, natural gas and NGLs (and the Corporation’s outlook relating to such prices) and the future costs of drilling, completing, tying-in and operating wells at the time that such activities are considered. The Corporation would also need to secure adequate transportation capacity on acceptable terms for its incremental future production. The primary uncertainties that affect the development of such lands are the future drilling and completion results achieved in the development activities, drilling and completion results achieved by others on lands in close proximity to these lands, and future changes to applicable regulatory or royalty regimes that affect timing or economics of proposed development activities. All of these uncertainties have the potential to delay the development of such lands. Conversely, uncertainty as to the timing and nature of the evolution or development of better exploration, drilling, completion and production technologies have the potential to accelerate development activities and enhance the economics relating to such properties.

Forward Contracts

Distinction uses risk management contracts in order to reduce its exposure to fluctuations in commodity prices. These instruments are not used for trading or speculative purposes.

All of the contracts through which the Corporation has fixed the price applicable to certain of its future production outstanding as at December 31, 2020 have been disclosed in Note 6 to the audited financial

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statements of the Corporation for the years ended December 31, 2020 and 2019, which are available on the SEDAR website at www.sedar.com.

Distinction has an agreement with Alliance for full path service to deliver up to 29.7 Mmcf/d of natural gas volumes until October 2025 into the Chicago gas market. In addition, the Corporation has service on NGTL until March 2026. The Corporation’s transportation commitments with Alliance and NGTL exceed Distinction’s current expected future production from its total proved reserves. Although the Corporation’s Montney production is currently being shipped on both Alliance (K3 plant) and NGTL (Bigstone gas plant), the Corporation expects to ship the majority of its Bigstone Montney production on Alliance after an Alliance lateral from Bigstone gas plant is reactivated in 2022. Based on this and the gas production from total proved reserves in the GLJ Report, the total cost of the excess transportation capacity on Alliance and NGTL is estimated to be approximately $20.6 million for the term of these services. In order to mitigate the cost of transportation service in excess of its needs, the Corporation temporarily assigns the excess service to other shippers or purchases natural gas in Alberta or British Columbia for sale in Chicago. The company has already mitigated approximately $3.1 million in excess Alliance transportation for 2021 by temporaily assigning approximately 17 Mmcf/d until November 1, 2021.

Tax Horizon

The income taxes deducted in the calculation of future net revenue assume a scenario whereby the Corporation produces all of its existing proved plus probable reserves. Under this scenario, Distinction would pay taxes in 2027.

The Corporation forecasts its tax horizon assuming reinvestment of cash flow to achieve production and reserve growth. The Corporation does not expect to be required to pay income taxes for the 2020 financial year. The Corporation does not anticipate becoming cash taxable before 2027. This estimate will be impacted by, among other factors, production volumes, commodity prices, foreign exchange rates, operating costs, interest rates, changes in tax laws and Distinction’s other business activities. Changes in these factors from estimates used by the Corporation could result in Distinction paying income taxes earlier than expected.

Costs Incurred

During 2020, the Corporation incurred the following costs in Canada:

Property and acquisition costs – Unproved properties Property and acquisition costs – Proved properties Exploration costs(12) Development costs(10)	2020 ($ 000’s)
	- - - 23,047

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Exploration and Development Activities

The following table sets forth the number of completed exploratory and development wells in which Distinction participated which were drilled during the year ended December 31, 2020:

	**Exploratory **	Wells(11)	Development	Wells(9)
	Gross(1)	Net(2)	Gross(1)	Net(2)
Natural gas wells	-	-	3.0	3.0
Total wells	-	-	3.0	3.0

1) Distinction did not drill any dry holes or stratigraphic test wells for the year ended December 31, 2020.

Distinction’s capital program for 2020 was focused on the delineation and development of its inventory of opportunities at Bigstone in the Montney formation. The Corporation expects to continue to develop and delineate the Bigstone Montney asset as part of its capital program in 2021.

Production Estimates

The following table sets forth the volume of daily gross[(1)] production estimated for the year 2021 in the reserves forecast for proved, probable and proved plus probable reserves.

Proved

Bigstone Montney Bigstone Sweet Other Total Proved Probable	Conventional natural gas (mcf/d) - 2,990 10 3,000	Shale gas (mcf/d) 20,624 - - 20,624	Natural gas liquids (bbls/d) 2,554 94 - 2,648	Total (boe/d)
				5,992 592 2
				6,585
Bigstone Montney Bigstone Sweet Other Total Probable	Conventional natural gas (mcf/d) - 71 - 71	Shale gas (mcf/d) 704 - - 704	Natural gas liquids (bbls/d) 355 2 - 358	Total (boe/d)
				473 14 -
				487

Proved plus Probable

Provedplus Probable
Bigstone Montney Bigstone Sweet Other Total Proved plus Probable	Conventional natural gas (mcf/d) - 3,061 10 3,071	Shale gas (mcf/d) 21,329 - - 21,329	Natural gas liquids (bbls/d) 2,909 96 - 3,006	Total (boe/d)
				6,464 606 2
				7,072

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Production History

Distinction's 2020 average daily production, before deduction of royalties, is summarized below:

Average Daily Production									Year Ended December 31, 2020
				Quarter Ended
		March 31, 2020		June 30, 2020		September 30, 2020		December 31, 2020
Conventional natural gas (mcf/d) Shale gas (mcf/d) Natural gas liquids (bbls/d) Total (boe/d)		2,519 21,082 2,641		2,545 18,352 3,140		2,724 19,076 3,002		3,189 19,502 3,009 6,791	2,722 19,525 2,949 6,657
		6,575		6,623		6,635

Distinction's 2020 share of average daily production, before deduction of royalties, from Bigstone Montney is summarized below:

is summarized below:
Average Daily Production									Year Ended December 31, 2020
				Quarter Ended
		March 31, 2020		June 30, 2020		September 30, 2020		December 31, 2020
Shale gas (mcf/d) Natural gas liquids (bbls/d) Total (boe/d)		21,082 2,523		18,352 3,050		19,076 2,914		19,502 2,914 6,164	19,525 2,851 6,105
		6,037		6,109		6,093

Distinction's 2020 share of average daily production, before deduction of royalties, from Bigstone Sweet is summarized below:

Average Daily Production									Year Ended December 31, 2020
				Quarter Ended
		March 31, 2020		June 30, 2020		September 30, 2020		December 31, 2020
Conventional natural gas (mcf/d) Natural gas liquids (bbls/d) Total (boe/d)		2,508 117		2,534 89		2,723 88		3,185 95 626	2,715 97 550
		535		511		542

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Netback By Product

The following table sets forth information in respect of quarterly average net product prices received before risk management contracts, royalties paid, operating expenses and operating netbacks by product for the year ended December 31, 2020.

			Conventional Natural Gas($/mcf)	Conventional Natural Gas($/mcf)	Conventional Natural Gas($/mcf)
			Quarter		Ended
	March 31, 2020		June 30, 2020		September 30, 2020		December 31, 2020
Average prices received Royalties Operating expenses Transportation Netback	2.06 0.81 (2.39) (0.22) 0.26		2.43 0.08 (3.37) (0.19)		2.87 0.05 (1.38) (0.27)		2.81 0.04 (2.79) (0.26) (0.20)
			(1.05)		1.27
			Quarter		Ended
	March 31, 2020		June 30, 2020		September 30, 2020		December 31, 2020
Average prices received Royalties Operating expenses Transportation Netback	2.40 (0.01) (2.87) (0.83) (1.31)		2.08 2.40 (0.16) (0.25) (2.27) (2.08) (0.80) (0.79) (1.15) (0.72) Natural Gas Liquids($/bbl)		2.40 (0.25) (2.08) (0.79)		2.90 (0.27) (2.48) (0.90) (0.75)
					(0.72)
			Quarter		Ended
	March 31, 2020		June 30, 2020		September 30, 2020		December 31, 2020
Average prices received Royalties Operating expenses1 Transportation Netback	38.15 (5.33) - (2.90) 29.92		18.44 (2.19) - (3.33)		39.11 (3.62) - (2.44)		39.74 (4.30) - (2.78) 32.66
			12.92		33.05

1 The Corporation does not allocate operating expenses to natural gas liquids as they are a by-product of conventional natural gas and shale gas.

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Product Sales Revenues

The only significant products produced and sold by the Corporation are conventional natural gas, shale gas and natural gas liquids. Virtually all of these products are sold on a short term basis that is a function of current market prices. None of the Corporation’s products are sold to non-arm’s length parties.

The following table summarizes the Corporation’s revenues in 2020 and 2019 by product type.

Product($ 000’s) Conventional natural gas Shale gas Natural gas liquids	2020 2,458 17,670 36,246	2019
		1,633 27,209 64,040

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APPENDIX A

ABBREVIATIONS, EQUIVALENCIES AND DEFINITIONS

The following are abbreviations of terms used in this form. All calculations converting natural gas to crude oil equivalent have been made using a ratio of 6 mcf of natural gas to one barrel of crude equivalent.

Crude Oil and Natural Gas Liquids bbl One barrel equaling 34.972 Imperial gallons or 42 U.S. gallons bbls/d Barrels per day bbls/mmcf Barrels per million cubic feet boe Barrels of oil equivalent boe/d Barrels of oil equivalent per day Mboe Thousand barrels of oil equivalent Mmboe Million barrels of oil equivalent Mbbls Thousand barrels Mmbbls Million barrels Mmlts Million long tonnes NGL or NGLs Natural gas liquids, consisting of any one or more of propane, butane and condensate WI Working interest

Natural Gas

bcf Billion cubic feet bcfe Billion cubic feet equivalent bcf/d Billion cubic feet per day mcf Thousand cubic feet Mcfe Thousand cubic feet equivalent mcf/d Thousand cubic feet per day Mmcfe Million cubic feet equivalent Mmcf Million cubic feet Mmcf/d Million cubic feet per day Mmbtu Million British Thermal Units GJ/d Gigajoules per day US$ United Stated dollar Cdn$ Canadian dollar

The following table sets forth certain standard conversions from Standard Imperial units to the International System of Units (or metric units).

To Convert From Mcf Cubic metres Bbls Cubic metres Feet Metres Miles Kilometres Acres Hectares GJ	To Cubic metres Cubic feet Cubic metres Bbls Metres Feet Kilometres Miles Hectares Acres Mcf	Multiply By
		28.174 35.494 0.159 6.290 0.305 3.281 1.609 0.621 0.405 2.471 1.055

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The following are the note references to the tables disclosed under “Oil and Gas Activities” in this NI51 101F1 disclosure.

(1) Gross

• (a) In relation to the Corporation's interest in production or reserves, its “company gross reserves”, which are the Corporation’s working interest (operating or non-operating) share before deduction of royalties and excluding any royalty interest of the Corporation;

• (b) In relation to wells, the total number of wells in which the Corporation has an interest;

• (c) In relation to properties, the total area of properties in which the Corporation has an interest.

(2) Net

• (a) In relation to the Corporation's interest in production or reserves, the Corporation's working interest (operating and non-operating) share after deduction of royalty obligations, plus the Corporation's royalty interests in production or reserves;

• (b) In relation to the Corporation’s interest in wells, the number of wells obtained by aggregating the Corporation’s working interest in each of its gross wells.

• (c) In relation to the Corporation's interest in a property, the total area in which the Corporation has an interest multiplied by the working interest owned by the Corporation.

• (3) Definitions used for reserve categories in the GLJ Report are as set forth, which definitions apply to both estimates of individual reserves entities and the aggregate of reserves for multiple entities: Reserve Categories

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on

• analysis of drilling, geological, geophysical and engineering data;

• the use of established technology; and

• specified economic conditions,

Reserves are classified according to the degree of certainty associated with the estimates.

• (a) 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.

• (b) 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.

• (4) Each of the reserve categories (proved and probable) may be divided into developed and undeveloped categories:

• (a) Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.

  • i. Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These

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reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

• ii. Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

• (5) Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned. In multi-well pools it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed nonproducing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

• (6) Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

• (a) At least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and

• (b) At least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

• (7) Forecast prices and costs

Future prices and costs that are:

• (a) Generally accepted as being a reasonable outlook of the future;

• (b) If, and only to the extent that, there are fixed or presently determinable future prices or costs to which the Corporation is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a).

The forecast summary table identifies benchmark reference pricing that apply to the Corporation.

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• (8) Future income tax expenses

Future income tax expenses are estimated:

• (a) Making appropriate allocations of estimated unclaimed costs and losses carried forward for tax purposes, between oil and gas activities and other business activities;

• (b) Without deducting estimated future costs (for example, Crown royalties) that are not deductible in computing taxable income;

• (c) Taking into account estimated tax credits and allowances (for example, royalty tax credits); and

• (d) Applying to the future pre-tax net cash flows relating to the Corporation’s oil and gas activities the appropriate year-end statutory rates, taking into account future tax rates already legislated.

• (9) Development well – A well drilled inside the established limits of an oil or gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive.

• (10) Development costs – Costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from the reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

• (a) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines and power lines, to the extent necessary in developing the reserves;

• (b) Drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and wellhead assembly;

• (c) Acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and

• (d) Provide improved recovery systems.

• (11) Exploration well – A well that is not a development well, a service well or a stratigraphic test well.

• (12) Exploration costs – Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as “prospecting costs”) and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities are:

• (a) Costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews and others conducting those studies (collectively sometimes referred to as “geological and geophysical costs”);

• (b) Costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defense, and the maintenance of land and lease records;

• (c) Dry hole contributions and bottom hole contributions;

• (d) Costs of drilling and equipping exploratory wells; and

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• (e) Costs of drilling exploratory type stratigraphic test wells.

• (13) Numbers may not add due to rounding.

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