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Altura Energy Inc. Announces 2018 Reserves, an Operational Update and 2019 Guidance TSX Venture Exchange:ATU



(MENAFN - GlobeNewsWire - Nasdaq) itemprop="articleBody">CALGARY, Alberta, March 05, 2019 (GLOBE NEWSWIRE) -- Altura Energy Inc. ("Altura" or the "Company") (TSX-V: ATU) is pleased to announce the results of the independent evaluation of the Company's oil and natural gas reserves (the "McDaniel Report"), effective December 31, 2018, as prepared by McDaniel and Associates Consultants Ltd. ("McDaniel"), an operational update and 2019 guidance.

Altura's audit of its 2018 annual financial statements is not yet complete and accordingly all financial amounts referred to in this news release are unaudited and represent management's estimates. Readers are advised that these financial estimates are subject to audit and may be subject to change as a result.

2018 YEAR-END RESERVE HIGHLIGHTS

    Year-over-year, proved developed producing ("PDP") reserves increased by eight percent from 1,595 mBoe to 1,725 mBoe. Total proved ("1P") reserves increased by 102 percent from 3,107 mBoe to 6,270 mBoe. Total proved plus probable ("2P") reserves increased by 89 percent from 5,370 mBoe to 10,126 mBoe. Percentage increases were the same on a per share basis.

    These reserve additions were achieved notwithstanding the May 2018 disposition of approximately 73 percent, 49 percent and 60 percent of the Company's year-end 2017 PDP, 1P and 2P reserve volumes respectively.

    In the Leduc-Woodbend Upper Mannville Rex oil pool, year-over-year reserve growth was significant with PDP increasing from 437 mBoe to 1,487 mBoe; 1P increased from 1,221 mBoe to 6,032 mBoe; and 2P increased from 2,140 mBoe to 9,818 mBoe.

    Finding, development and acquisition ("FD & A") costs1 were $17.30 per Boe for PDP, $16.48 per Boe for 1P and $12.53 per Boe for 2P reserves, including the changes in future development costs ("FDC"). This includes $6.4 million, or 19 percent of exploration and development capital expenditures, to construct a multi-well battery and pipelines at Leduc-Woodbend.

    Recycle ratio1 of 1.4 times for PDP, 1.5 times for 1P, and 2.0 times for 2P reserves based on the 2018 FD & A costs and Altura's estimated 2018 operating netback1 of $24.54 per Boe.

    Replaced1 130 percent of annual production with new PDP reserves, 839 percent of annual production with new 1P reserves and 1,212 percent of annual production with new 2P reserves, based on 2018 production of 1,172 Boe per day.

    2P reserves are booked on only 18 net sections of land at Leduc-Woodbend which is 26 percent of total lands in the area.

    Increased the 1P reserve life index1 ("RLI") from 7.0 years to 12.1 years, and 2P RLI from 12.1 years to 19.5 years, from year-end 2017 to year-end 2018.

    Increased net asset value1 per share 42 percent from $0.71 to $1.01, on a 2P reserves basis.

2019 OPERATIONAL UPDATE

On December 21, 2018, the Company announced that November and December 2018 production volumes were voluntarily curtailed in response to weak oil prices caused by wide Canadian oil differentials. The Canadian oil differentials narrowed significantly in January 2019 and Altura brought the curtailed production back on line.

In January, Altura completed the equipping operations for the last well of Altura's 2018 summer drilling program, which was drilled and fracked in 2018. This well commenced production on February 4, 2019 and initial production rates are consistent with the Company's other wells in the Leduc-Woodbend area.

2019 GUIDANCE

The board of directors of the Company has approved an initial capital budget of $15 million for 2019, funded with forecasted cash flow from operating activities. The budget is weighted to the second half of 2019 and includes drilling four extended reach horizontal ("ERH") wells at Leduc-Woodbend. Additionally, Altura plans to implement a waterflood pilot project which includes drilling on reduced inter-well spacing.

Altura's base production coupled with production from its capital program is forecasted to grow 2019 annual average production to range between 1,700 to 1,800 Boe per day in 2019, compared to 1,172 Boe per day in 2018, representing more than 45 percent growth on an absolute and per share basis.

Management intends to continuously monitor well performance and commodity prices throughout the year and may at any time adjust the 2019 capital program if well performance is exceeding expectations or if oil prices deteriorate or strengthen. The budget leaves Altura with a conservative balance sheet and the flexibility to accelerate development in the second half of 2019 if results and commodity prices are supportive.

2018 OPERATING HIGHLIGHTS

    The Company closed the sale of its eastern Alberta and Saskatchewan assets (the "Disposition") producing 668 Boe per day in May 2018 for $27.3 million (net of transaction costs and adjustments) leaving Altura with production of 502 Boe per day in June.

    Following the eight-well summer drilling program and construction of key infrastructure, production increased to 2,053 Boe per day in October but was voluntarily curtailed in November to 1,512 Boe per day and in December to 675 Boe per day due to weak oil prices caused by wide Canadian oil differentials.

    Fourth quarter 2018 production averaged 1,412 Boe per day which was impacted by Altura's production curtailment. 2018 production volumes averaged 1,172 Boe per day (81 percent oil and liquids), an increase of four percent from 2017.

    Drilled 10 (9.95 net) wells, including nine (8.95 net) ERH wells in the Leduc-Woodbend area and one (1.0 net) horizontal well in the Macklin area. Additionally, the Company invested in key infrastructure at Leduc-Woodbend including the construction of a multi-well battery and a natural gas gathering pipeline that connects Altura's northern area production to a third-party gas plant.

    Capital expenditures totaled $33.5 million, including $24.8 million on drilling, completion and equipping, and $6.4 million on facilities and pipelines.

    Closed two separate acquisitions, acquiring 3.0 net sections of highly prospective lands in the Upper Mannville oil pool at Leduc-Woodbend and a 60 percent working interest in a producing oil unit in the Leduc-Woodbend area, adding net production of approximately 120 Boe per day (90 percent oil & liquids) of low decline, Glauconite oil (33° API) production for aggregate cash consideration of $3.6 million.

    Operating and transportation costs totaled $10.93 per Boe, down 11 percent from 2017. This decrease is largely a result of lower cost production growth into the new multi-well battery at Leduc-Woodbend and the Disposition which had higher average operating costs. Fourth quarter operating and transportation costs further improved to $8.60 per Boe.

    Operating netback2 was $24.54 per Boe, down 11 percent from 2017 due to the sharp commodity price decline in the fourth quarter.
2018 INDEPENDENT RESERVES EVALUATION

The McDaniel Report was prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101 ("NI 51-101"). 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, 2019. The Reserves Committee of the Board and the Board of Directors of Altura have reviewed and approved the evaluation prepared by McDaniel.

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, 2018, which will be filed on SEDAR by April 30, 2019.

2018 Capital Expenditures

Altura drilled 10 (9.95 net) wells, including nine (8.95 net) ERH wells in the Leduc-Woodbend area, and one (1.0 net) horizontal well in the Macklin area. Additionally, the Company invested in key infrastructure at Leduc-Woodbend including the construction of a multi-well battery and a natural gas gathering pipeline that connects Altura's northern area production to a third-party gas plant.

In 2018, the Corporation closed two separate acquisitions, acquiring 3.0 net sections of highly prospective lands in the Upper Mannville oil pool at Leduc-Woodbend and a 60 percent working interest in a producing oil unit in the Leduc-Woodbend area, adding net production of approximately 120 Boe per day (90 percent oil & liquids) of low decline, Glauconite oil (33° API) production for aggregate cash consideration of $3.6 million. The acquisitions secured Altura operatorship of the Glauconite Unit battery.

In 2018, Altura closed the disposition of the Corporation's crude oil and natural gas assets in east central Alberta and Saskatchewan for $27.3 million of cash, net of customary post-closing adjustments and transaction costs of $0.4 million.

Estimated 2018 capital expenditures include:

($000)(1) Geological and geophysical 38 Land 720 Drilling and completions 23,481 Workovers 826 Equipping and tie-in 1,366 Facilities and pipelines 6,384 Other 642 Capital expenditures 33,457 Property acquisitions 3,597 Property dispositions (27,275) Total capital expenditures, acquisitions and dispositions 9,779

(1) Estimated and unaudited

Company Gross Reserves as at December 31, 2018

The following table summarizes the Company's gross reserve volumes at December 31, 2018 utilizing the Consultant Average Price Forecast and cost estimates outlined further below in this press release.



Company Gross Reserves(1)(2) Category Crude Oil
(Mbbl) Conventional
Natural Gas
(Mmcf) Natural
Gas
Liquids
(Mbbl) 2018 Oil
Equivalent
(MBoe) 2017 Oil
Equivalent
(MBoe) 2018/
2017
Percent
Change Proved Developed Producing 1,226.9 2,560.8 70.9 1,724.6 1,594.5 8% Developed Non-Producing 106.0 181.6 4.5 140.8 96.6 46% Undeveloped 3,107.7 6,764.6 169.1 4,404.2 1,416.3 211% Total Proved(3) 4,440.6 9,507.0 244.6 6,269.7 3,107.4 102% Total Probable 2,653.2 6,264.8 158.7 3,856.0 2,262.5 70% Total Proved + Probable(3) 7,093.9 15,771.8 403.2 10,125.7 5,369.9 89% (1) Gross reserves are Company working interest reserves before royalty deductions.
(2) Based on the January 1, 2019 Consultant Average Price Forecast.
(3) Numbers may not add due to rounding.

In the Leduc-Woodbend Upper Mannville Rex oil pool, reserve growth was significant with PDP increasing from 437 mBoe to 1,487 mBoe which represents 86% of total PDP reserves. 1P increased from 1,221 mBoe to 6,032 mBoe which represents 96% of total 1P reserves. 2P increased from 2,140 mBoe to 9,818 mBoe which represents 97% of total 2P reserves. Altura's other reserves consist of the Glauconitic oil assets that were acquired in 2018.

Reconciliation of Company Gross Reserves for 2018(1)(2)

Total Proved Oil Equivalent
(mBoe) Total Proved + Probable
Oil Equivalent (mBoe) December 31, 2017 3,107.4 5,369.9 Extensions & Improved Recovery 4,592.5 7,833.1 Technical Revisions 517.3 144.1 Discoveries - - Acquisitions 247.4 317.5 Dispositions (1,767.4) (3,111.4) Economic Factors - - Production (427.6) (427.6) December 31, 2018 6,269.7 10,125.7

(1) Gross reserves are Company working interest reserves before royalty deductions.
(2) Numbers may not add due to rounding.

Technical revisions for 1P and 2P reserves categories are positive due to well performance exceeding the previous year's forecast. Additionally, 1P reserves include category transfers from total probable reserves.

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 increased by $49.5 million and FDC for 2P undeveloped reserves increased by $55.3 million compared to year-end 2017. The increases in FDC were driven by additional locations at Leduc-Woodbend consistent with the increases in 1P and 2P reserve volumes.

Total Proved
FDC(1)(2)
($000) Total Proved
Wells(2)
Gross (Net) Total Proved +
Probable FDC(1)(2)
($000) Total Proved +
Probable Wells(2)
Gross (Net) 2019 10,200 4 (4.0) 10,200 4 (4.0) 2020 22,468 9 (8.7) 22,468 9 (8.7) 2021 30,152 13 (11.3) 30,152 13 (11.3) 2022 12,506 7 (4.5) 32,650 15 (11.8) Total Undiscounted 75,327 33 (28.5) 95,471 41 (35.8)

(1) Numbers may not add due to rounding.
(2) FDC and well counts as per the McDaniel Report and based on the January 1, 2019 Consultant Average Price Forecast.

The forecasted future net operating income for the next four years from the McDaniel Report based on the January 1, 2019 Consultant Average Price Forecast is estimated to be $118.9 million for 1P reserves and $146.9 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, 2018

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, 2019 as outlined in the price forecast table further below in this press release. The NPVs include a deduction for estimated future well abandonment and reclamation 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% Proved Developed Producing 40,085 36,613 33,645 31,155 29,068 Developed Non-Producing 3,903 3,592 3,330 3,109 2,923 Undeveloped 59,568 44,019 32,576 24,117 17,793 Total Proved 103,556 84,224 69,551 58,381 49,784 Total Probable 93,012 64,848 47,070 35,471 27,611 Total Proved + Probable 196,568 149,072 116,621 93,852 77,395

(1) Based on the January 1, 2019 Consultant Average Price Forecast.
(2) Includes abandonment and reclamation costs.
(3) Numbers may not add due to rounding.

Company Net Asset Value

The Company's net asset value as at December 31, 2018 and 2017 are detailed in the following table. This net asset value determination is a "point-in-time" measurement and does not take into account the possibility of Altura being able to recognize additional reserves through successful future capital investment in its existing properties beyond those included in the 2018 year-end reserve report and the 2017 year-end reserve report.


Before Tax NPV @ 10% Discount Rate 2018 2017 ($000) ($/Diluted
Share(7)) ($000) ($/Diluted
Share(7)) Per Share
% Change NPV of Future Net Revenue Developed Producing(1)(2) 33,645 0.29 28,832 0.25 16% Total Proved(1)(2) 69,551 0.59 42,335 0.36 64% Total Proved + Probable(1)(2) 116,621 0.99 76,059 0.65 52% Net Asset Value(3) Total Proved + Probable(1)(2) 116,621 0.99 76,059 0.65 52% Decommissioning liability(4) (1,443) (0.01) (2,726) (0.02) (50%) Undeveloped acreage(5) 6,210 0.05 10,267 0.09 (44%) Net debt(6) (4,819) (0.04) (3,730) (0.03) 33% Proceeds from stock options(7) 2,850 0.02 2,408 0.02 - Net asset value(7) 119,419 1.01 82,278 0.71 42% (1) Evaluated by McDaniel as at December 31, 2018 and December 31, 2017. Net present value of future net revenue does not represent the fair market value of the reserves.
(2) 2018 Net present values are based on the January 1, 2019 Consultant Average Price Forecast and 2017 net present values are based on McDaniel's January 1, 2018 price forecast.
(3) Net asset value does not have a standardized meaning. See "Oil and Gas Metrics" contained in this news release.
(4) The decommissioning liability included above is unaudited, discounted at 10% and is incremental to the amount included in the net present value of reserves as evaluated by McDaniel.
(5) Undeveloped acreage was determined from independent land valuation reports by Seaton-Jordan & Associates Ltd. as at December 31, 2018 and December 31, 2017. Fair market values were determined in accordance with NI 51-101 5.9(1)(e).
(6) Net debt as at December 31, 2018 is estimated and unaudited. Net debt does not have a standardized meaning. See "Oil and Gas Metrics" contained in this news release.
(7) Diluted shares as at December 31, 2018 were 108.9 million basic common shares plus 8.4 million stock options that were in-the-money as at December 31, 2018. Diluted shares as at December 31, 2017 were 108.9 million basic common shares plus 7.2 million stock options that were in-the-money as at December 31, 2017.

Performance Metrics(1)

Altura's 2018 Finding, Development & Acquisitions ('FD & A') costs were burdened with the investment of $6.4 million, 19% of total capital expenditures, to construct facilities and pipeline infrastructure. The infrastructure investments will benefit future development, lower water handling costs and increase gas handling capabilities. The following table highlights Altura's FD & A, recycle ratio, reserve replacement and reserve life index for 2018, 2017 and 2016.

2018 2017 2016 Capital expenditures, acquisitions and dispositions(2) ($000) 9,647 21,187 17,492 Change in FDC – Total Proved ($000) 49,520 16,109 5,704 Change in FDC – Total Proved + Probable ($000) 55,320 23,329 7,664 Q4 production (Boe/d) 1,412 1,202 988 Annual operating netback ($/Boe)(3) 24.54 27.49 25.29 Proved Developed Producing FD & A costs ($/Boe)(3) 17.30 23.36 19.99 Recycle ratio(3) 1.4 1.2 1.3 Reserve replacement(3) 130% 220% 417% Reserve life index ("RLI") (years)(3) 3.3 3.6 3.0 Total Proved FD & A costs ($/Boe)(3) 16.48 21.97 17.76 Recycle ratio(3) 1.5 1.3 1.4 Reserve replacement(3) 839% 412% 622% Reserve life index ("RLI") (years)(3) 12.1 7.0 5.0 Total Proved + Probable FD & A costs ($/Boe)(3) 12.53 17.21 12.32 Recycle ratio(3) 2.0 1.6 2.1 Reserve replacement(3) 1,212% 628% 973% Reserve life index ("RLI") (years)(3) 19.5 12.1 8.8

(1) Financial and production information is per the Company's 2018 preliminary unaudited financial statements and is therefore subject to audit.
(2) Capital expenditures excludes office furniture and computer and office equipment of $132,000 in 2018.
(3) "Operating netback", "Finding, development & acquisitions costs" or "FD & A costs", "Recycle ratio", "Reserve replacement", and "Reserve life index" or "RLI" do not have standardized meanings. See "Oil and Gas Metrics" contained in this news release.

Altura's recycle ratios in 2018 were negatively impacted by the sharp decline in Canadian oil prices in the fourth quarter of 2018. Using Altura's operating netback for the nine months ended September 30, 2018 of $29.77 per Boe, recycle ratios in 2018 are 1.7 for PDP, 1.8 for 1P and 2.4 for 2P.

Price Forecast

The McDaniel Report was based on the Consultant Average Price Forecast at January 1, 2019 as outlined below.

WTI
Crude Oil
($US/bbl)

Western Canadian Select
Crude Oil
($CAD/bbl) Alberta AECO
Gas
($CAD/mmbtu)

Foreign Exchange
($US/$CAD) 2019 58.58 51.55 1.88 0.757 2020 64.60 59.58 2.31 0.782 2021 68.20 65.89 2.74 0.797 2022 71.00 68.61 3.05 0.803 2023 72.81 70.53 3.21 0.807 2024 74.59 72.34 3.31 0.808 2025 76.42 74.31 3.39 0.808 2026 78.40 76.44 3.46 0.808 2027 79.98 78.10 3.54 0.808 2028 81.59 79.81 3.62 0.808 2029 83.22 81.41 3.69 0.808 2030 84.89 83.04 3.77 0.808 2031 86.58 84.70 3.84 0.808 2032 88.31 86.39 3.92 0.808 2033 90.08 88.12 4.00 0.808 thereafter +2.0%/yr +2.0%/yr +2.0%/yr 0.808 ABOUT ALTURA ENERGY INC.

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 www.alturaenergy.ca.

READER ADVISORIES

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:

    the 2019 capital expenditure budget; forecasted average production and percent growth for 2019; plans to implement a waterflood pilot project in 2019; and timing of filing the Company's year-end results and annual information form.
Statements relating to "reserves" 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

Reserves

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, 2018 and a preparation date of March 4, 2019 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, 2019. 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.

Oil and Gas Metrics

This news release contains metrics commonly used in the oil and natural gas industry. Each of these metrics is determined by Altura as set out below. These metrics are "finding, development and acquisition costs", "recycle ratio", "reserve replacement", "reserve life index", "operating netbacks" and "net asset value". These metrics do not have standardized meanings and may not be comparable to similar measures presented by other companies. As such, they should not be used to make comparisons. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Altura's performance over time, however, such measures are not reliable indicators of Altura's future performance and future performance may not compare to the performance in previous periods.

    "Finding, development and acquisition costs" or "FD & A costs" are calculated by dividing the sum of the total capital expenditures for the year inclusive of the net acquisition costs and disposition proceeds (in dollars) by the change in reserves within the applicable reserves category inclusive of changes due to acquisitions and dispositions (in Boe). FD & A costs, including FDC, includes all capital expenditures in the year inclusive of the net acquisition costs and disposition proceeds as well as the change in FDC required to bring the reserves within the specified reserves category on production.

    FD & A costs take into account reserves revisions and capital revisions during the year. The aggregate of the costs incurred in the financial year and changes during that year in estimated FDC may not reflect total FD & A costs related to reserves additions for that year. FD & A costs have been presented in this news release because acquisitions and dispositions can have a significant impact on Altura's ongoing reserves replacement costs and excluding these amounts could result in an inaccurate portrayal of its cost structure. Management uses FD & A as measures of its ability to execute its capital programs (and success in doing so) and of its asset quality.

    "Recycle ratio" or is calculated by dividing the operating netback (in dollars per Boe) by the FD & A costs (in dollars per Boe) for the year. Altura uses recycle ratio as an indicator of profitability of its oil and gas activities.

    "Reserve replacement" is calculated by dividing the annual change in reserves before production (in Boe) in the referenced category by Altura's annual production (in Boe). Management uses this measure to determine the relative change of its reserves base over a period of time.

    "Reserve life index" or "RLI" is calculated by dividing the reserves (in Boe) in the referenced category by the Q4 2018 production estimate (in Boe). Management uses this measure to determine how long the booked reserves will last at current production rates if no further reserves were added.

    "Operating netback" is a non-GAAP measure and does not have a standardized meaning under IFRS. Altura calculates operating netback on a per Boe basis as petroleum and natural gas sales less royalties, operating and transportation costs. Management feels that operating netback is a key industry benchmark and a measure of performance for Altura that provides investors with information that is commonly used by other crude oil and natural gas producers. The measurement on a per Boe basis assists management and investors with evaluating operating performance on a comparable basis.

    "Net asset value" is calculated by taking the 2P future net revenues per the McDaniel Report, on a before tax basis, discounted at 10% and adding undeveloped land value and proceeds from stock option exercises and subtracting decommissioning obligations, discounted at 10%, and net debt. Management uses this to measure the relative change in net asset value over a period of time.

    "Net debt" is a non-GAAP measure and does not have a standardized meaning under IFRS. Management views net debt as a key industry benchmark and a measure to assess the Company's financial position and liquidity. Net debt is equivalent to current assets less current liabilities.
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 "Operating netback", "Finding, development & acquisitions costs" or "FD & A costs", "Recycle ratio", "Reserve life index" or "RLI", "Reserve replacement" and "net asset value" do not have standardized meanings. See "Oil and Gas Metrics" contained in this news release.

2 "Operating netback" does not have a standardized meaning. See "Oil and Gas Metrics" contained in this news release.

For further information please contact: 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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Altura Energy Inc. Announces 2018 Reserves, an Operational Update and 2019 Guidance TSX Venture Exchange:ATU

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