Altura Energy Inc. announces its 2017 reserves and provides an operational update

CALGARY, Feb. 22, 2018 /CNW/ - 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, 2017, as prepared by McDaniel and Associates Consultants Ltd. ("McDaniel"), and an operational update.

Altura's audit of its 2017 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.

2017 OPERATING HIGHLIGHTS

• Production volumes averaged 1,128 boe per day, a per share increase of 97% from 2016. Exceeded exit rate guidance of 1,350 boe per day in December and averaged 1,202 boe per day in the fourth quarter, a per share increase of 22% from the fourth quarter of 2016.
• Drilled eight 100% working interest ("WI") horizontal wells, including three in the Leduc-Woodbend area, three in the Eyehill area, one in the Macklin area, and one in the Killam area.
• Capital expenditures totaled $21.2 million, including $14.7 million on drilling, completion and equipping, $1.8 million on land, $3.8 million on facilities and pipelines, $1.3 million on workovers and $0.7 million on other, less $1.1 million of property dispositions.
• Progressed its key growth property at Leduc-Woodbend with three new wells drilled, including two 1.5-mile extended reach horizontal wells ("ERH"), the conversion of two standing wells to water disposal wells, and constructed gas gathering, emulsion and water disposal pipelines, which will allow Altura to conserve natural gas and improve operating cost efficiencies by significantly reducing produced water trucking and disposal costs.
• Established a second growth area at Macklin with 9.5 sections of 100% WI land in a Sparky oil pool. Altura drilled one successful horizontal well in 2017, which was followed up with a second horizontal well drilled in January 2018 and a water disposal pipeline to improve operating cost efficiencies.
• Completed the water injection infrastructure at Eyehill and commenced the waterflood pilot project in August.

2017 YEAR-END RESERVE HIGHLIGHTS

• The 2017 year-end reserves are indicative of the exploration and capture phase of Altura's new Leduc-Woodbend and Macklin Upper Mannville oil pools where the capital focus has been on capturing land, delineation drilling and investing in infrastructure to position the Company as it transitions to the development phase in 2019.
• Proved developed producing ("PDP") reserves increased by 45 percent from 1,099 mboe to 1,595 mboe. Total proved ("1P") reserves increased by 71 percent from 1,821 mboe to 3,107 mboe. Total proved plus probable ("2P") reserves increased by 68 percent from 3,195 mboe to 5,370 mboe.
• All-in finding, development and acquisition ("FD&A") costs[1] were $23.36 per boe for PDP, $21.97 per boe for 1P and $17.21 per boe for 2P reserves, including the changes in future development costs ("FDC"). This includes $5.6 million of non-reserve adding capital (27% of capital expenditures) to acquire undeveloped land and construct pipelines and facilities.
• Recycle ratio² of 1.2 times for PDP, 1.3 times for 1P, and 1.6 times for 2P reserves based on the all-in 2017 FD&A costs and Altura's estimated 2017 operating netback² of $27.49 per boe. Using the Q4 2017 estimated operating netback of $29.39 per boe, the recycle ratios increase to 1.3 times for PDP, 1.3 times for 1P, and 1.7 times for 2P reserves.
• Replaced[2] 220 percent of annual production with new PDP reserves, 412 percent of annual production with new 1P reserves and 628 percent of annual production with new 2P reserves, based on 2017 estimated production of 412 mboe.
• Based on the strong well results, the majority of 2P reserves additions (88%) were at Leduc-Woodbend.
• Increased PDP reserve life index² ("RLI") from 3.0 years to 3.6 years, 1P RLI from 5.0 years to 7.0 years, and 2P RLI from 8.8 years to 12.1 years, all from year-end 2016 to year-end 2017

2018 OPERATIONAL UPDATE

Altura drilled and completed a 1.5-mile ERH well (100/02-02-049-26W4 or "02-02") at Leduc-Woodbend in the first quarter of 2018.  The well was drilled to a vertical depth of 1,300 meters with a horizontal length of approximately 2,000 meters with 46 frac stages and is expected to be placed on production by the end of February.   Drilling and completion costs for 02-02 are estimated at $2.4 million. 

Altura's first two ERH wells that were brought on production in the fourth quarter of 2017 are currently producing in line with management's expectations.  Please refer to the corporate presentation on the Company's website at www.alturaenergy.ca.

At Macklin, Altura has drilled and completed one 1.0-mile horizontal well (09-33-039-28W3 or "09-33") in the first quarter of 2018.  The well was drilled to a vertical depth of 725 meters with a horizontal length of 1,485 meters with 36 frac stages and was placed on production on February 1, 2018.  Drilling and completion costs are estimated at $1.3 million. 

Altura plans to update shareholders with initial production rates for the Leduc-Woodbend 02-02 and Macklin 09-33 wells on March 22, 2018 when year-end results are released. 

In February, the Company commissioned a new produced water disposal pipeline at Macklin which is connected to third party water disposal facilities.  This has eliminated water hauling and is expected to reduce area operating costs.

Altura's 2018 capital budget is expected to be $15.0 million.  The budget is split approximately 60% to drilling, completion, equipping and tie-in capital and 40% to infrastructure and other capital.  The significant weighting to infrastructure investments positions Altura to reduce operating costs and grow production profitably as it continues to evaluate the Leduc-Woodbend pool. 

Management intends to monitor commodity prices and may adjust the 2018 capital program if oil prices deteriorate or strengthen. For details on Altura's 2018 capital budget, see the Company's December 14, 2017 news release.

2017 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 ("COGE Handbook") and National Instrument 51-101 ("NI 51-101").  The reserve evaluation was based on McDaniel's forecast pricing and foreign exchange rates at January 1, 2018. 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, 2017, which will be filed on SEDAR by April 30, 2018.

2017 Capital Expenditures

Altura's activity in 2017 included drilling eight (8.0 net) horizontal wells, including three (3.0 net) in the Leduc-Woodbend area, three (3.0 net) in the Eyehill area, one (1.0 net) in the Macklin area, and one (1.0 net) in the Killam area.  Estimated 2017 capital expenditures include: 

			($000)(1)
Geological and geophysical			138
Land			1,840
Drilling and completions			12,751
Well equipping			1,958
Capitalized workovers			1,343
Facilities and pipelines			3,798
Other			465
Exploration and development capital expenditures			22,293
Property dispositions			(1,106)
Total capital expenditures, acquisitions and dispositions			21,187
(1) Estimated and unaudited

 

Company Gross Reserves as at December 31, 2017

The following table summarizes the Company's gross reserve volumes at December 31, 2017 utilizing McDaniel's forecast pricing and cost estimates outlined further below in this press release.

			Company Gross Reserves(1)(2)
Category			Light and Medium Oil (Mbbl)	Heavy Oil (Mbbl)	Conventional Natural Gas (Mmcf)	Natural Gas Liquids (Mbbl)	2017 Oil Equivalent (Mboe)	2016 Oil Equivalent (Mboe)	2017/ 2016 Percent Change
Proved
	Developed Producing		729.8	458.6	2,183.2	42.3	1,594.5	1,099.2	45%
	Developed Non-Producing		114.9	-	(98.5)	(1.8)	96.6	-	-
	Undeveloped		294.8	825.4	1,538.4	39.6	1,416.3	722.2	96%
Total Proved(3)			1,139.4	1,284.1	3,623.2	80.1	3,107.4	1,821.4	71%
Total Probable			588.1	1,288.8	1,986.7	54.5	2,262.5	1,373.8	65%
Total Proved + Probable(3)			1,727.5	2,572.9	5,609.8	134.5	5,369.9	3,195.2	68%

(1)	Gross reserves are Company working interest reserves before royalty deductions.
(2)	Based on McDaniel's January 1, 2018 forecast prices.
(3)	Numbers may not add due to rounding.

 

At Leduc-Woodbend, reserve growth was significant with PDP increasing from 70 mboe to 437 mboe and represents 27% of total PDP reserves.  1P increased from 70 mboe to 1,221 mboe and represents 39% of total 1P reserves.  2P increased from 235 mboe to 2,140 mboe and represents 40% of total 2P reserves. 

Total capital at Leduc-Woodbend in 2017 was $13.4 million, including $9.6 million of drilling, completion, equipping and workover capital, and $3.8 million of non-well related capital including land, pipelines, facilities and other capital.  The FD&A at Leduc-Woodbend on a 2P basis was $16.75 per boe with a recycle ratio of 1.5 using its 2017 average area operating netback of $25.11 per boe.  Excluding the $3.8 million of non-well related capital, the Leduc-Woodbend FD&A was $14.84 per boe with a recycle ratio of 1.7.

Reconciliation of Company Gross Reserves for 2017⁽¹⁾⁽²⁾

	Total Proved Oil Equivalent (mboe)	Total Probable Oil Equivalent (mboe)	Total Proved + Probable Oil Equivalent (mboe)
December 31, 2016	1,821.4	1,373.8	3,195.2
Extensions & Improved Recovery	1,250.8	722.2	1,973.0
Technical Revisions	294.8	(237.5)	57.0
Discoveries	161.3	410.7	570.9
Acquisitions & Dispositions	(10.0)	(6.0)	(16.0)
Economic Factors	-	-	-
Production	(411.7)	-	(411.7)
December 31, 2017	3,107.4	2,262.5	5,369.9

(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 reserve 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 $16.1 million and FDC for 2P undeveloped reserves increased by $23.3 million compared to year-end 2016. The increases in FDC were driven by additional locations at Leduc-Woodend and Macklin and are 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)
2018	7,082	3   (1.9)	11,032	4   (2.9)
2019	14,035	8   (8.0)	16,407	11 (11.0)
2020	4,689	7   (5.7)	12,711	14 (11.7)
Total Undiscounted	25,806	18 (15.6)	40,150	29 (25.6)
Total Discounted 10%	22,701		34,779

(1)	Numbers may not add due to rounding.
(2)	FDC and well counts as per the McDaniel Report and based on McDaniel's January 1, 2018 forecast prices.

 

The forecasted future net operating income for the next three years from the McDaniel Report based on the January 1, 2018 forecasted pricing is estimated to be $44.4 million for 1P reserves and $62.3 million for 2P reserves, which is sufficient to fund Altura's FDC for the next three years.

Summary of Before Tax Net Present Value ("NPV") of Future Net Revenue as at December 31, 2017

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 McDaniel's forecast pricing and foreign exchange rates at January 1, 2018 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	37,929	32,795	28,832	25,765	23,355
	Developed Non-Producing	3,953	3,494	3,068	2,700	2,390
	Undeveloped	21,193	14,965	10,435	7,126	4,675
Total Proved		63,074	51,254	42,335	35,591	30,420
Total Probable		67,600	46,505	33,725	25,557	20,053
Total Proved + Probable		130,675	97,760	76,059	61,148	50,473

(1)	Based on McDaniel's January 1, 2018 forecast prices.
(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, 2017 and 2016 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 2017 year-end reserve report and the 2016 year-end reserve report.

	Before Tax NPV @ 10% Discount Rate
	2017		2016
	($000)	($/Share)	($000)	($/Share)
NPV of Future Net Revenue
Developed Producing(1)(2)	28,832	0.25	23,328	0.20
Total Proved(1)(2)	42,335	0.36	31,353	0.27
Total Proved + Probable(1)(2)	76,059	0.65	54,540	0.47
Net Asset Value(3)
Total Proved + Probable(1)(2)	76,059	0.65	54,540	0.47
Undeveloped acreage(4)	10,267	0.09	5,488	0.05
Working capital surplus (deficit)(5)	(3,730)	(0.03)	8,455	0.07
Proceeds from stock options(6)	2,408	0.02	1,744	0.02
Net asset value (diluted)(6)	85,004	0.73	70,227	0.61

(1)	Evaluated by McDaniel as at December 31, 2017 and December 31, 2016. Net present value of future net revenue does not represent the fair market value of the reserves.
(2)	Net present values are based on McDaniel's January 1, 2018 price forecast and January 1, 2017 price forecast.
(3)	Net asset value does not have a standardized meaning.  See "Oil and Gas Metrics" contained in this news release.
(4)	Undeveloped acreage was determined by an independent land valuation report by Seaton-Jordan & Associates Ltd. as at December 31, 2017. Fair market value was determined in accordance with NI 51-101 5.9(1)(e).  As at December 31, 2016, undeveloped acreage was valued internally by Altura at an average of $100 per acre over 54,877 net undeveloped acres.
(5)	Working capital deficit as at December 31, 2017 (estimated and unaudited).
(6)	Diluted shares as at December 31, 2017 was 108.9 million basic common shares plus 7.2 million stock options that were in-the-money as at December 31, 2017.  Diluted shares as at December 31, 2016 was 108.9 million basic common shares plus 5.6 million stock options that were in-the-money as at December 31, 2016.

 

Performance Metrics⁽¹⁾

Altura's 2017 all-in FD&A costs were burdened with the investment of $5.6 million (27% of capital expenditures) to acquire undeveloped land and construct pipelines and facilities infrastructure.  The land and infrastructure investments will benefit future development as well as 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 2017 and 2016. 

		2017	2016
Total capital expenditures, acquisitions and dispositions ($000)		21,187	17,494
Change in FDC – Total Proved ($000)		16,109	5,704
Change in FDC – Total Proved + Probable ($000)		23,329	7,664
Q4 production (boe/d)		1,202	988
Q4 operating netback ($/boe)(2)		29.39	30.02
Annual operating netback ($/boe)(2)		27.49	25.30
Proved Developed Producing
FD&A costs ($/boe)(2)		23.36	19.99
Recycle ratio(2) (Q4 operating netback)		1.3	1.5
Recycle ratio(2) (annual operating netback)		1.2	1.3
Reserve replacement(2)		220%	417%
Reserve life index ("RLI") (years)(2)		3.6	3.0
Total Proved
FD&A costs ($/boe)(2)		21.97	17.76
Recycle ratio(2) (Q4 operating netback)		1.3	1.7
Recycle ratio(2) (annual operating netback)		1.3	1.4
Reserve replacement(2)		412%	622%
Reserve life index ("RLI") (years)(2)		7.0	5.0
Total Proved + Probable
FD&A costs ($/boe)(2)		17.21	12.32
Recycle ratio(2) (Q4 operating netback)		1.7	2.4
Recycle ratio(2) (annual operating netback)		1.6	2.1
Reserve replacement(2)		628%	973%
Reserve life index ("RLI") (years)(2)		12.1	8.8

(1)	Financial and production information is per the Company's 2017 preliminary unaudited financial statements and is therefore subject to audit.
(2)	"Operating netback", "Finding, development & acquisitions costs" or "FD&A costs", "Recycle ratio", "Reserve replacement", "Reserve life index" or "RLI" do not have standardized meanings.  See "Oil and Gas Metrics" contained in this news release.

 

Price Forecast

The McDaniel Report was based on McDaniel's forecast pricing and foreign exchange rates at January 1, 2018 as outlined below.

	WTI Crude Oil ($US/bbl)	Western Canadian Select Crude Oil ($CAD/bbl)	Alberta AECO Gas ($CAD/mmbtu)	Foreign Exchange ($US/$CAD)
2018	58.50	51.90	2.25	0.790
2019	58.70	57.00	2.65	0.790
2020	62.40	61.40	3.05	0.800
2021	69.00	66.00	3.40	0.825
2022	73.10	67.90	3.60	0.850
2023	74.50	69.20	3.65	0.850
2024	76.00	70.60	3.75	0.850
2025	77.50	72.00	3.80	0.850
2026	79.10	73.50	3.90	0.850
2027	80.70	74.90	3.95	0.850
2028	82.30	76.40	4.05	0.850
2029	83.90	77.90	4.15	0.850
2030	85.60	79.50	4.25	0.850
2031	87.30	81.10	4.30	0.850
2032	89.10	82.70	4.35	0.850
thereafter	+2.0%/yr	+2.0%/yr	+2.0%/yr	0.850

 

ABOUT ALTURA ENERGY INC.

Altura is a junior oil and gas exploration, development and production company with operations in central and east central Alberta.  Altura predominantly produces from the Sparky and Rex reservoirs 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 2018 capital expenditure budget, expected drilling costs at Leduc-Woodbend and Macklin, expected water hauling cost savings at Leduc-Woodbend and Macklin 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

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 2017 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. Operating netback is calculated using production revenues, less royalties, transportation and operating expenses, calculated on a per boe equivalent basis. Management uses this measure to benchmark operating results between areas and/or time periods.
• 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, working capital surplus and proceeds from stock option exercises. Management uses this to measure the relative change in net asset value over a period of 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	"Operating netback", "Finding, development & acquisitions costs" or "FD&A costs", "Recycle ratio", and "Reserve replacement" do not have standardized meanings. See "Oil and Gas Metrics" contained in this news release.
2	"Operating netback", "Finding, development & acquisitions costs" or "FD&A costs", "Recycle ratio", and "Reserve replacement" do not have standardized meanings. See "Oil and Gas Metrics" contained in this news release.

 

SOURCE Altura Energy Inc.

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