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Copper Tip Energy Services
Hazloc Heaters
WEC - Western Engineered Containment
WEC - Western Engineered Containment
Hazloc Heaters
Copper Tip Energy

Altura Announces Fourth Quarter and Year End 2020 Results and Reserves

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These translations are done via Google Translate

CALGARY, AB, April 15, 2021 /CNW/ – Altura Energy Inc. (“Altura” or the “Company”) (TSXV: ATU) is pleased to announce its financial and operating results for the fourth quarter and year ended December 31, 2020 and the independent evaluation of the Company’s oil and natural gas reserves (the “McDaniel Report”), effective December 31, 2020, as prepared by McDaniel and Associates Consultants Ltd. (“McDaniel”). The audited consolidated financial statements and related management’s discussion and analysis (“MD&A”) for the year ended December 31, 2020 are available on SEDAR at and on Altura’s website at Selected financial and operating information for the fourth quarter and year ended December 31, 2020 appear below and should be read in conjunction with the related financial statements and MD&A.

Operational and Financial Summary

Three Months Ended Year Ended
December 31,
September 30,
December 31,
December 31,
December 31,
Average daily production
Heavy crude oil (bbls/d) 468 512 881 465 1,112
Light crude & medium crude oil (bbls/d) 16 6 17
Natural gas ­(Mcf/d) 2,402 2,118 3,406 2,151 3,145
NGLs (bbls/d) 48 38 113 51 89
Total (boe/d) 916 919 1,561 880 1,742
Total boe/d per million shares – diluted 8.4 8.4 14.3 8.1 15.9
Average realized prices
Heavy crude oil ($/bbl) 44.45 40.19 54.40 36.59 55.69
Natural gas ($/Mcf) 2.87 2.45 2.70 2.43 1.73
NGLs ($/bbl) 25.72 25.83 26.64 21.32 26.75
Average realized price ($/boe) 31.56 29.87 38.50 26.74 40.50
Petroleum and natural gas sales 31.56 29.87 38.50 26.74 40.50
Royalties (2.61) (2.63) (4.43) (2.03) (4.16)
Operating (12.75) (13.85) (8.63) (13.27) (8.25)
Transportation (1.93) (2.51) (2.45) (2.34) (3.48)
Operating netback(1) 14.27 10.88 22.99 9.10 24.61
Realized gain on financial instruments 1.48 0.51 0.53 4.51 0.34
Operating netback after realized gain on
financial instruments(1) 15.75 11.39 23.52 13.61 24.95
General and administrative (4.66) (5.71) (2.52) (4.93) (2.55)
Exploration expense (0.03)
Interest and financing expense (cash) (1.39) (1.21) (0.37) (0.91) (0.36)
Adjusted funds flow per boe(1) 9.70 4.47 20.63 7.77 22.01
Financial ($000, except per share amounts)
Petroleum and natural gas sales 2,659 2,526 5,531 8,615 25,757
Cash flow from operating activities 206 505 3,955 2,406 12,994
Adjusted funds flow(1) 818 378 2,963 2,502 13,994
Per share – basic and diluted(1) 0.01 0.03 0.02 0.13
Net income (loss) 10,823 (360) (56) (22,313) 2,215
Per share – basic and diluted(2) 0.10 (0.20) 0.02
Capital expenditures 105 469 1,528 7,874 12,884
Property acquisitions (dispositions), net (875) (3,508) (1,746) (3,508)
Total capital expenditures, net 105 (406) (1,980) 6,128 9,376
Net debt(1) 3,857 4,560 563 3,857 563
Common shares outstanding – basic (000) 108,921 108,921 108,921 108,921 108,921
(1) Adjusted funds flow, net debt, operating netback, and operating netback after realized gain on financial instruments are non-GAAP measures that do not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other companies.  Refer to the heading entitled “Non-GAAP Measures” included in the “Advisories” section at the end of the MD&A.
(2) Basic weighted average shares are used to calculate diluted per share amounts when the Corporation is in a loss position.


Production volumes averaged 916 boe per day in the fourth quarter, consistent with the third quarter of 2020. Production was impacted by one Leduc-Woodbend oil well that was curtailed for most of the quarter due to third-party gas processing restrictions.

Altura’s realized heavy oil price increased 11% to $44.45 per barrel in the fourth quarter compared to $40.19 per barrel in the third quarter of 2020 but decreased 18% compared to $54.40 per barrel in the fourth quarter of 2019.

Operating expenses in the fourth quarter were $12.75 per boe, compared to $13.85 per boe in the third quarter of 2020. The decrease was mainly due to lower repair and maintenance costs associated with fewer well workovers in the fourth quarter.  Transportation expenses were $1.93 per boe, 23% lower than $2.51 per boe in the third quarter of 2020 due to lower clean oil hauling rates in the quarter.

The Company’s operating netbackaveraged $14.27 per boe, up 31% from the third quarter of 2020 due to higher crude oil and natural gas prices and lower operating and transportation expenses.

Adjusted funds flowwas $818,000 in the quarter, up 116% from the third quarter of 2020 due to increased crude oil and natural prices, lower operating and transportation expenses, lower G&A expenses and an increased realized gain on financial instruments.

Altura received $81,000 under the Canada Emergency Wage Subsidy and Canada Emergency Rent Subsidy in the fourth quarter, which was applied against G&A expenses.

Altura recorded net income of $10.8 million in the quarter compared to a net loss of $0.4 million in the third quarter of 2020, mainly due to a reversal of impairment of $11.2 million in the quarter.

Altura reduced its net debtby $703,000 during the fourth quarter. Considering Altura’s net debtof $3.9 million as at December 31, 2020, the Company has sufficient liquidity to execute its business plan in the current volatile commodity market.

The Company successfully abandoned five inactive wells and reclaimed three wells that were previously abandoned utilizing Alberta’s Site Rehabilitation Program (“SRP”), reducing its net asset retirement obligation by $192,000.


2020 will be remembered for the significant challenges to the global economy and energy sector. The COVID-19 induced global economic downturn combined with the actions of Saudi Arabia and Russia in the global oil market resulted in an unprecedented decline in crude oil prices. As a result, in March Altura quickly eliminated all discretionary capital spending for the remainder of 2020 and immediately reduced production volumes including shutting in all production volumes in May. The Company began restoring curtailed production in June as oil prices improved.

In August, the Company confirmed its revolving operating demand loan (the “Operating Loan”) borrowing base at $6.0 million. Additionally, Altura secured a $3.0 million term loan from its lender through the Business Credit Availability Program (“BCAP”) from the Export Development Bank of Canada (“EDC”) (the “Term Loan”) providing Altura with $9.0 million of total credit facilities and allowing the Company to exit 2020 in a strong financial position.

In 2020, Altura successfully closed two disposition transactions with a private company, divesting of a 2.75% working interest for cash of $1.75 million to further bolster the balance sheet.

These defensive actions were taken to preserve value and safeguard the balance sheet through this pandemic related low oil price period. With the recent strengthening of global economies and commodity price recovery the Company is now well positioned to resume and focus planned activities to capitalize on the depth of its opportunities on its large conventional oil resource with an estimated 400 MMbbls of OOIPon Altura’s lands.

Altura continued with its Environmental, Social and Governance (“ESG”) initiatives in 2020. Starting in July 2020, Altura submitted applications under the Government of Alberta’s SRP to accelerate the abandonment of wellbores and reclaim inactive well sites and the Company was approved for an abandonment and reclamation grant under the SRP. The Corporation utilized $213,000 ($192,000 net) of grant funding and abandoned five inactive wells (15% of the Corporation’s inactive gross well count) and finalized reclamation of three wells that were previously abandoned. Altura’s undiscounted and un-escalated asset retirement obligation was $5.4 million ($2.1 million, 2% inflation rate, discounted at 10%) at December 31, 2020 and the Company ended 2020 with a Liability Management Rating (“LMR”) of 5.68 with the Alberta Energy Regulator.


In February 2021, Altura completed its 102/16-14-049-26W4 Rex horizontal well (“16-14”) that was drilled in February 2020 and not completed due to low commodity prices. The 16-14 well was designed with increased frac density of 74 intervals at 27 meter spacing. This completion is consistent with two Rex horizontal wells that were completed in 2018 with increased frac density that continue to outperform previous type curve expectations. By comparison this is a 57% increase in intervals compared to earlier wells with 47 intervals at 40 meter spacing. Initial production rates for 16-14 are consistent with and meeting the Company’s higher expectations of increased frac density wells. This increased frac density is an exciting optimization that management will carry forward for future wells at Leduc-Woodbend.

Altura’s current production is estimated at 1,060 boe per daybased on field estimates from April 1, 2021 to April 14, 2021.  Approximately 110 boe per dayof net production from one (0.9 net) well is currently shut-in due to third-party gas processing restrictions. This well was shut-in in March 2020 and was brought back on production in mid-December 2020.  The well produced intermittently in January 2021 and was shut-in again in February 2021 due to further third-party gas processing restrictions.  Management is working with the gas plant operator with the goal to restart production in May 2021.


The 2021 $6.0 million capital budget builds on the recent sector commodity price recovery with WTI moving up from US$35.00 per barrel on October 30, 2020 to today’s price of approximately US$60 per barrel, a level not seen in well over a year. Western Canadian Select (“WCS”) differentials also continue to narrow with the forward curve approaching US$11 per barrel this summer.

Two (1.8 net) new wells at Leduc-Woodbend are planned to be drilled and completed in the summer of 2021 and are scheduled to commence production in July and October 2021, respectively. The 2021 capital expenditure budget targets an annual average production rate of 1,100 to 1,150 boe per day compared to 880 boe per dayin 2020, representing more than 25% growth on an absolute and per share basis.

Altura’s Leduc-Woodbend asset has a well inventory of 47 (36.6 net) booked locations and 104 (67 net) drilling opportunitieswith drilling flexibility at current commodity prices to self-fund growth within cash flow and maintain a strong balance sheet.

Altura expects to close two additional dispositions of a 0.6875% working interest for $437,500 on April 30, 2021 and a 1.375% working interest for $875,000 on June 30, 2021 (total remaining disposition of 2.0625% working interest for $1,312,500), as disclosed in the January 29, 2021 news release.

While 2020 was primarily a defensive year of survival for many junior oil weighted producers, 2021 is looking to be a year of opportunity. The Altura team is very excited and poised to refocus efforts towards creating value for its shareholders in 2021 and beyond.


During 2020, Altura responded to the unprecedented commodity price weakness and volatility by cutting its planned capital budget in early March and reducing production volumes in April, May and June. The reduction in capital investment, shut-in of production volumes and natural well declines combined to reduce reserves year-over-year.

In addition, a significant reduction in the reserves evaluator’s 2020 price forecast compared to 2019 negatively impacted net present values and reserves volumes by reducing well economic limit cut-offs. The evaluator WTI oil price forecast may have been considered reasonable at year-end 2020; however, this forecast has decoupled from current pricing and is now over US$10 per barrel lower than the current forward strip for 2021 and does not reach the current WTI spot price of approximately US$60 per barrel until the year 2029.


Altura’s year end 2020 reserves were evaluated by independent reserves evaluator McDaniel & Associates Consultants Ltd. in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) as of December 31, 2020. The reserves evaluation was based on the average of the published price forecasts for McDaniel, GLJ Petroleum Consultants Ltd., and Sproule Associates Ltd. (the “Consultant Average Price Forecast”) at January 1, 2021.

Consistent with 2019, and as per guidance in the Canadian Oil and Gas Evaluation Handbook COGE Handbook (“COGE Handbook”), the McDaniel Report includes all abandonment, decommissioning and reclamation obligations (“ADR”), including all the ADR associated with both active and inactive wells regardless of whether such wells had any attributed reserves.

Unless noted otherwise, reserves included herein are stated on a company gross basis, which is the Company’s working interest before deduction of government royalties and excluding any other additional royalty interests. This news release contains several cautionary statements under the heading “Reader Advisory” and throughout the release. In addition to the information contained in this news release, more detailed reserves information will be included in Altura’s Annual Information Form for the year ended December 31, 2020, which will be filed on SEDAR by April 30, 2021.

Company Gross Reserves as at December 31, 2020

The following table summarizes the Company’s gross reserve volumes at December 31, 2020 utilizing the Consultant Average Price Forecast and cost estimates outlined further below in this press release.

Company Gross Reserves(1)(2)
Category Light
Crude &
Crude Oil
Natural Gas
2020 Oil
2019 Oil


Developed Producing 164.5 562.8 3,439.0 100.3 1,400.8 1,754.5 (20)
Developed Non-Producing 11.4 83.5 252.7 7.3 144.4 161.0 (10)
Undeveloped 2,559.0 8,034.1 233.0 4,131.1 4,431.1 (7)
Total Proved(3) 176.0 3,205.4 11,725.8 340.6 5,676.3 6,346.5 (11)
Total Probable 67.3 2,439.2 12,491.8 362.8 4,951.3 4,803.9 3
Total Proved + Probable(3) 243.3 5,644.7 24,217.6 703.4 10,627.6 11,150.4 (5)
(1) Gross reserves are Company working interest reserves before royalty deductions
(2) Based on the January 1, 2021 Consultant Average Price Forecast
(3) Numbers may not add due to rounding

Reconciliation of Company Gross Reserves for 2020(1)(2)

Light Crude
& Medium Crude
Oil (Mbbl)

Crude Oil

Natural Gas
Natural Gas
Oil Equivalent
Total Proved
December 31, 2019 161.2 3,695.0 13,052.0 315.1 6,346.5
Extensions 11.4 11.4
Technical Revisions 49.5 (13.6) 889.3 85.7 269.7
Dispositions (7.4) (125.6) (518.3) (15.1) (234.5)
Economic Factors (8.9) (207.8) (910.1) (26.4) (394.8)
Production (29.8) (142.6) (787.1) (18.6) (322.1)
December 31, 2020 176.0 3,205.4 11,725.8 340.7 5,676.2
Total Proved + Probable
December 31, 2019 325.4 6,031.6 25,161.9 599.7 11,150.4
Extensions 14.6 509.1 1,967.9 57.1 908.8
Technical Revisions (38.9) (250.2) 297.5 135.6 (104.1)
Dispositions (38.9) (250.2) 297.5 135.6 (104.1)
Economic Factors (18.4) (311.4) (1,559.8) (45.3) (635.1)
Production (29.8) (142.6) (787.1) (18.6) (322.1)
December 31, 2020 243.2 5,644.6 24,217.6 703.5 10,627.6
(1) Gross reserves are Company working interest reserves before royalty deductions
(2) Numbers may not add due to rounding

Technical revisions for heavy crude oil, natural gas and NGLs, in both the Total Proved (“1P”) and Total Proved + Probable (“2P”) reserves categories, are due to performance deviations and changes in the Leduc-Woodbend production forecast based on higher natural gas production in 2020 than previous year’s forecast.

Future Development Costs (“FDC”) and Well Schedule

The following is a summary of the estimated FDC and number of wells required to bring 1P and 2P undeveloped reserves on production.  Changes in forecast FDC occur annually as a result of drilling 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 1P undeveloped reserves decreased by $4.1 million compared to year-end 2019 due to a decreased working interest and lower expected drilling and completion cost estimates at Leduc-Woodbend.  FDC for 2P undeveloped reserves increased by $0.2 million compared to year-end 2019 due to 2.3 additional net wells in 2020 with decreased expected drilling and completion cost estimates at Leduc-Woodbend.

Total Proved
Total Proved


Gross (Net)

Total Proved +
Probable FDC(1)(2)($000)
Total Proved +
Probable Wells(2)Gross (Net)
2021 4,947 2   (1.7) 4,947 2 (1.7)
2022 15,111 8   (6.6) 15,261 8 (6.6)
2023 21,843 11   (9.1) 26,060 13 (10.9)
2024 17,710 11   (7.2) 32,255 18 (13.2)
2025 10,526 6 (4.2)
Total Undiscounted 59,611 32 (24.5) 89,049 47 (36.6)
(1) Numbers may not add due to rounding
(2) FDC and well counts as per the McDaniel Report and based on the January 1, 2021 Consultant Average Price Forecast

The forecasted future net operating income for the next four years from the McDaniel Report based on the January 1, 2021 Consultant Average Price Forecast is estimated to be $66.3 million for 1P reserves and $90.8 million for 2P reserves, which is sufficient to fund Altura’s FDC.

Summary of Before Tax Net Present Value (“NPV”) of Future Net Revenue as at December 31, 2020

Benchmark oil and NGL prices used are adjusted for quality of oil or NGL produced and for transportation costs. The calculated NPVs are based on the Consultant Average Pricing Forecast at January 1, 2021 as outlined in the price forecast table further below in this press release.  The NPVs include ADR but do not include a provision for interest, debt service charges and general and administrative expenses. It should not be assumed that the NPV estimate represents the fair market value of the reserves.

Before Tax Net Present Value ($000) (1)(2)(3)
Discount Rate
Category Undiscounted 5% 10% 15% 20%
Developed Producing 8,968.9 10,540.0 10,604.1 10,181.4 9,630.7
Developed Non-Producing 1,756.0 1,562.7 1,391.5 1,243.6 1,116.3
Undeveloped 27,544.7 19,555.7 13,565.6 9,122.3 5,822.6
Total Proved 38,269.6 31,658.4 25,561.2 20,547.3 16,569.6
Total Probable 60,816.8 43,540.0 31,887.2 23,914.6 18,339.6
Total Proved + Probable 99,086.5 75,198.4 57,448.5 44,461.9 34,909.1
(1) Based on the January 1, 2021 Consultant Average Price Forecast
(2) Numbers may not add due to rounding

Price Forecast

The McDaniel Report was based on the Consultant Average Price Forecast at January 1, 2021 as outlined below.


Crude Oil


Western Canadian Select

Crude Oil


Alberta AECO



2021 47.17 44.63 2.78 0.768
2022 50.17 48.18 2.70 0.765
2023 53.17 52.10 2.61 0.763
2024 54.97 54.10 2.65 0.763
2025 56.07 55.19 2.70 0.763
2026 57.19 56.29 2.76 0.763
2027 58.34 57.42 2.81 0.763
2028 59.50 58.57 2.87 0.763
2029 60.69 59.74 2.92 0.763
2030 61.91 60.93 2.98 0.763
2031 63.15 62.15 3.04 0.763
2032 64.41 63.40 3.10 0.763
2033 65.70 64.66 3.16 0.763
2034 67.01 65.96 3.23 0.763
2035 68.35 67.28 3.29 0.763
thereafter +2.0%/yr +2.0%/yr +2.0%/yr 0.763

Price Forecast Sensitivity

Given the material oil price increase in the first quarter of 2021, Altura prepared a commodity price sensitivity comparing the net present value (before tax, discounted at 10%) of reserves effective December 31, 2020, using the average of the published price forecasts for McDaniel, GLJ Petroleum Consultants Ltd., and Sproule Associates Ltd. as at April 1, 2021 to the Company’s NI 51-101 net present values in the reserves evaluation using the January 1, 2021 price forecast.  Net present values of proved developed producing reserves increases 26% to $13.4 million, total proved reserves increases 25% to $32.4 million, and total proved plus probable reserves increases 14% to $65.7 million.  It should not be assumed that the net present value estimate represents the fair market value of the reserves.

On behalf of the Board of Directors and the Altura management team, we would like to thank our shareholders for their ongoing support.


Altura is a junior oil and gas exploration, development and production company with operations in central Alberta.  Altura predominantly produces from the Rex reservoir in the Upper Mannville group and is focused on delivering per share growth and attractive shareholder returns through a combination of organic growth and strategic acquisitions. An updated corporate presentation is available on Altura’s website at


Forward–looking Information and Statements

This press release contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words “expect”, “anticipate”, “budget”, “forecast”, “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 press release contains forward-looking information and statements pertaining to:

  • Altura’s expectation of bringing one shut-in well back on production in May 2021;
  • Altura’s ability to self-fund growth within cash flow and maintain a strong balance sheet;
  • plans to close stages 3b and 4 of the previously announced asset disposition on April 30, 2021 and June 30, 2021;
  • the 2021 capital expenditure budget;
  • forecasted average production and percent growth for 2021.

Statements relating to “reserves”, including but not limited to forecasted future net revenue and future development costs, are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.

The forward-looking information and statements contained in this press release reflect several material factors and expectations and assumptions of Altura including, without limitation:

  • the continued performance of Altura’s oil and gas properties in a manner consistent with its past experiences
  • that Altura will continue to conduct its operations in a manner consistent with past operations;
  • 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 Altura’s reserves and resource volumes;
  • certain commodity price and other cost assumptions;
  • the continued availability of oilfield services; and
  • the continued availability of adequate debt and equity financing and cash flow from operations to fund its planned expenditures.

Altura 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. To the extent that any forward-looking information contained herein may be considered future oriented financial information or a financial outlook, such information has been included to provide readers with an understanding of management’s assumptions used for budgeted and developing future plans and readers are cautioned that the information may not be appropriate for other purposes.

The forward-looking information and statements included in this press release report 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;
  • changes in the demand for or supply of Altura’s products;
  • unanticipated operating results or production declines;
  • changes in tax or environmental laws, royalty rates or other regulatory matters;
  • changes in development plans of Altura or by third party operators of Altura’s properties,
  • increased debt levels or debt service requirements;
  • inaccurate estimation of Altura’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 Altura’s public documents.

The forward-looking information and statements contained in this press release speak only as of the date of this press release, and Altura does not assume any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.

Oil and Gas Advisories


McDaniel & Associates Consultants Ltd. is the Corporation’s independent “qualified reserve evaluator” as defined in National Instrument 51-101.  The McDaniel Report has an effective date of December 31, 2020 and a preparation date of April 14, 2021 and was prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and NI 51-101. The reserve evaluation was based on the average of the published price forecasts for McDaniel, GLJ Petroleum Consultants Ltd., and Sproule Associates Ltd. at January 1, 2021. The Reserves Committee of the Board and the Board of Directors of Altura have reviewed and approved the evaluation prepared by McDaniel.

All reserve references in this press release are “company share reserves”. Company share reserves are the Company’s total working interest reserves before the deduction of any royalties and including any royalty interests of the Company.

It should not be assumed that the present value of estimated future net revenue presented in the tables above represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserve estimates of Altura’s crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.

All future net revenues are estimated using forecast prices, arising from the anticipated development and production of our reserves, net of the associated royalties, operating costs, development costs, and abandonment and reclamation costs and are stated prior to provision for interest and general and administrative expenses. Future net revenues have been presented on a before tax basis. Estimated values of future net revenue disclosed herein do not represent fair market value.

Barrels of Oil Equivalent

The term barrels of oil equivalent (“Boe”) may be misleading, particularly if used in isolation.  Per Boe amounts have been calculated by using the conversion ratio of six thousand cubic feet (6 mcf) of natural gas to one barrel (1 bbl) of crude oil.  The Boe conversion ratio of 6 mcf to 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 equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

Drilling Opportunities

Potential drilling opportunities are internal estimates based on the Corporation’s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and Altura’s internal review.  Potential drilling opportunities do not have attributed reserves or resources. Potential drilling opportunities have specifically been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves data on prospective acreage and geologic formations.  The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, crude oil and natural gas prices, costs, actual drilling results and other factors.  While certain of the potential drilling opportunities have been derisked by drilling existing wells in relative close proximity to such potential drilling opportunities, the majority of other potential drilling opportunities are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations, and if drilled there is more uncertainty that such wells will result in additional reserves, resources or production.

Original Oil in Place (OOIP)

For the purpose of this news release, Original Oil in Place (“OOIP”) means Discovered Petroleum Initially In Place (“DPIIP”). DPIIP is derived by Altura’s internal Qualified Reserve Evaluators (“QRE”) and prepared in accordance with National Instrument 51-101 and the Canadian Oil and Gas Evaluations Handbook (“COGEH”). DPIIP, as defined in COGEH, 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 Resources Other Than Reserves (ROTR). The OOIP/DPIIP and potential recovery rate estimates are as at December 31, 2020 and are based on current recovery technologies and have been prepared by Altura’s internal QRE. There is significant uncertainty as to the ultimate recoverability and commercial viability of any of the resource associated with the OOIP/DPIIP estimates, and as such a recovery project cannot be defined for this volume of OOIP/DPIIP at this time.

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

1 Adjusted funds flow, net debt and operating netback are non-GAAP measures that do not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other companies.  Refer to the heading entitled “Non-GAAP Measures” contained within the “Advisories” section of Altura’s MD&A
2 OOIP is original oil in place.  See advisories in this news release
3 Consists of 600 bbls/d of heavy crude oil, 52 bbls/d of NGLs and 2,450 Mcf/d of natural gas
4 Consists of 40 bbls/d of heavy crude oil, 25 bbls/d of NGLs and 270 Mcf/d of natural gas
5 Consists of 465 bbls/d of heavy crude oil, 6 bbls/d of light crude oil, 51 bbls/d of NGLs and 2,151 Mcf/d of natural gas
6 See advisories on drilling opportunities in this news release

SOURCE Altura Energy Inc.

For further information: Altura Energy Inc., 2500, 605 – 5th Avenue SW, Calgary, Alberta T2P 3H5, Telephone (403) 984-5197; David Burghardt, President and Chief Executive Officer, Direct (403) 984-5195; Tavis Carlson, Vice President, Finance and Chief Financial Officer, Direct (403) 984-5196

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