Yangarra Announces Operations Update & Year End Corporate Reserves Information

CALGARY, Feb. 6, 2020 /CNW/ - Yangarra Resources Ltd. ("Yangarra" or the "Company") (TSX:YGR) releases operations update and the results of its 2019 year end oil and gas reserves evaluation.

Operations Update

In 2019 Yangarra achieved several key milestones, including the construction of a 100% owned gas plant, the doubling of capacity on one of its existing gas plants, the addition of a new core area and additional ESG initiatives that will benefit Yangarra shareholders from 2020 onwards as the Company transitions to free cash flow generation.

Yangarra originally planned to drill & complete 24 wells in 2019; however, budget was re-directed to infrastructure to accommodate Chedderville opportunities and as a result elected to drill & complete 17 wells in 2019.

Despite the limited drilling program, Yangarra's yearly average production was 12,550 boe/d (33% growth from an average of 9,425 boe/d in 2018) with fourth quarter production expected to average 12,500 boe/d. The average production is lower than guidance due to the reduced drilling & completions program. The infrastructure capital spend in the first quarter of 2019 resulted in lower operating costs and the reduced costs are reflected in the Company's independent reserves report as prepared by Deloitte LLP which is effective as of December 31, 2019 (the "2019 Reserve Report").

The Company recognized in late Q4 that industry was rapidly mobilizing in Alberta, commodity prices were improving and to ensure crews and equipment were not lost to competitors, the Board of Directors approved an acceleration of 2020 capital spending into 2019, resulting in a 2019 budget of $121 million. This allowed for 3 additional wells to be drilled late in the year and they were put onstream in January 2020. The Company's revised 2020 budget will be $105 million (originally $120 million), the production guidance range of 14,000-15,000 boe/d remains unchanged.

As highlighted by recent well results, Yangarra plans to focus the 2020 program primarily on higher IRR wells in the Chedderville area and will continue to implement the Company's refined completions strategy that had positive results in late 2019.

Yangarra's land position in Chedderville has increased from 9.5 sections, January 1, 2018 to 62 sections of Cardium land today. The infrastructure build in late 2018 and early 2019 is key to positioning the Company to support drilling in this area for several years to come.  

Updated Corporate Presentation

An updated corporate presentation is available on the Company website: www.yangarra.ca.

Reserve Report Highlights:

All reserves information contained in this press release is based on the 2019 Reserve Report. Unless specifically indicated, all financial and operational information in this press release is based on estimates and is unaudited and accordingly, such financial information is subject to change based on the results of the Company's year-end audit.

Proved Developed Producing ("PDP") Reserves

• 25.5 million boe (9% increase from 2018)
• Net present value before tax discounted at 10% ("NPV10") of $414 million (5% increase from 2018), including abandonment capital for all producing and non-producing wells
• Finding and development costs ("F&D") of $18.10/boe, resulting in a PDP recycle ratio of 1.24 times; 2019 F&D costs were impacted by the significant facilities spending in the first quarter. This allowed Yangarra to both reduce its corporate operating costs on its existing plays and allowed Yangarra to maintain its low-cost structure throughout the new Chedderville area
• PDP net asset value per fully diluted common share ("NAV per FD Share") of $2.63
• PDP additions replaced 146% of 2019 production
• PDP reserve additions were impacted by the testing of 15 tons per stage on completions during 2019, upon evaluation Yangarra discovered the old program of 20 tons per stage provided significantly better results and those improvements are reflected in the 1P and 2P bookings

Proved Non-Producing ("PNP") Reserves

• 2.2 million boe
• NPV10 of $40 million
• The majority of the PNP value consists of the three wells that were drilled before year-end. All these wells are now producing
• PDP + PNP NAV per FD Share of $3.08

Total Proved reserves ("1P")

• 85.6 million boe (13% increase from 2018)
• NPV10 of $1.1 billion (no change from 2018)
• The Deloitte price forecast was 10-15% lower in the later years for all products for the 2019 report versus 2018
• 1P future development costs of $429 million
• F&D costs of $10.74/boe resulting in a recycle ratio of 2.08 times
• 1P NAV per FD Share of $10.66
• 1P Reserve Life Index ("RLI") based on fourth quarter 2019 production of 18.8 years
• 1P additions replaced 320% of 2019 production

Proved plus probable reserves ("2P")

• 145.6 million boe (15% increase from 2018)
• NPV10 of $1.7 billion (no change from 2018)
• 2P Future development costs of $650 million
• The Deloitte price forecast was 10-15% lower in the later years for all products for the 2019 report versus 2018
• Finding and development costs of $6.86/boe resulting in a recycle ratio of 3.26 times
• 2P NAV per FD Share of $17.05
• RLI of 31.9 years
• 2P additions replaced 522% of 2019 production

Oil and Gas Reserves

The following tables summarize certain information contained in the 2019 Reserve Report. The 2019 Reserve Report encompasses 100% of Yangarra's oil and gas properties and was prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101") by Deloitte.

Summary of Oil and Gas Reserves ⁽¹⁾⁽²⁾
(Company Share Gross volumes based on forecast price and costs)

Reserves Category
	Light and Medium Oil (Mbbl)	Natural Gas Liquids (Mbbl)	Natural Gas (MMcf)	Total BOE 2019 (Mboe)		Total BOE 2018 (Mboe)
Proved Developed Producing	5,344	5,477	88,183	25,518		23,412
Proved Developed Non-Producing	620	423	6,802	2,176		1,917
Proved Undeveloped	13,225	12,149	195,141	57,897		50,178
Total Proved	19,189	18,049	290,126	85,592		75,507
Probable	12,553	13,324	205,010	60,045		50,799
Total Proved Plus Probable	31,741	31,373	495,136	145,637		126,305

Notes to table:
(1)	Total values may not add due to rounding.
(2)	BOEs are derived by converting gas to oil equivalent in the ratio of six thousand cubic feet of gas to one barrel of oil (6 Mcf:1 bbl).

Summary of Net Present Values of Future Net Revenue (Before Tax) ⁽¹⁾⁽⁴⁾
(Based on forecast price and costs)

	As At December 31, 2019^(2)						As At December 31, 2018 ^(3)
Reserves Category	0.0% (M$)	5.0% (M$)	10.0% (M$)	15.0% (M$)	20.0% (M$)		10.0% (M$)
Proved Developed Producing	660,728	507,846	413,669	351,521	307,629		393,103
Proved Developed Non- Producing	59,131	46,963	39,514	34,480	30,834		47,202
Proved Undeveloped	1,243,947	878,215	659,274	516,407	417,228		678,893
Total Proved	1,963,806	1,433,024	1,112,457	902,409	755,692		1,119,198
Probable	1,613,536	880,489	556,057	384,367	282,467		566,699
Total Proved Plus Probable	3,577,342	2,313,513	1,668,514	1,286,776	1,038,159		1,685,897

Notes to table:
(1)	Total values may not add due to rounding.
(2)	Forecast pricing used is based on Deloitte published price forecasts effective December 31, 2019.
(3)	Forecast pricing used is based on Deloitte published price forecasts effective December 31, 2018.
(4)	Cash flows are reduced for future abandonment costs and estimated capital for future development associated with the reserves.
Reserve Definitions:
(a)	"Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
(b)	"Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
(c)	"Developed" reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production.
(d)	"Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
(e)	"Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.
(f)	"Undeveloped" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned.

Reconciliations of Changes in Reserves

The following table sets out a reconciliation of the changes in the Corporation's reserves as at December 31, 2019 against such reserves at December 31, 2018 based on forecast prices and cost assumptions:

	Light and Medium Oil			Natural Gas Liquids
	Gross Proved	Gross Probable	Gross Proved Plus Probable	Gross Proved	Gross Probable	Gross Proved Plus Probable
	(Mstb)	(Mstb)	(Mstb)	(Mstb)	(Mstb)	(Mstb)
Opening Balance	19,562.5	13,048.1	32,610.7	15,577.6	10,690.6	26,268.2
Production	-1,448.7	-	-1,448.7	-905.5	-	-905.5
Technical Revisions	-1,552.0	-2,234.4	-3,786.5	1,530.2	1,312.5	2,842.7
Extensions	2,633.8	1,742.3	4,376.1	1,805.2	1,280.6	3,085.8
Economic Factors	-9.5	-6.3	-15.8	-11.0	-6.2	-17.2
Closing Balance	19,186.1	12,549.7	31,735.8	17,996.4	13,277.5	31,273.9
Royalty Interest	3.0	3.0	5.0	53.0	47.0	99.0
	Gas			MBOE
	Gross Proved	Gross Probable	Gross Proved Plus Probable	Gross Proved	Gross Probable	Gross Proved Plus Probable
	(MMcf)	(MMcf)	(MMcf)	(MBOE)	(MBOE)	(MBOE)
Opening Balance	241,075.3	161,356.1	402,431.4	75,319.3	50,631.4	125,950.8
Production	-14,569.0	-	-14,569.0	-4,782.4	-	-4,782.4
Technical Revisions	33,786.4	22,632.0	56,418.5	5,609.2	2,850.1	8,459.2
Extensions	29,267.5	20,457.2	49,724.6	9,316.9	6,432.5	15,749.4
Economic Factors	-185.6	-102.2	-287.8	-51.4	-29.5	-81.0
Closing Balance	289,374.6	204,343.1	493,717.7	85,411.6	59,884.4	145,296.0
Royalty Interest	751.0	667.0	1,419.0	180.0	161.0	341.0

Forecast Prices Used in Estimates

The forecast price and market forecasts prepared by Deloitte are based on information available from numerous government agencies, industry publication, oil refineries, natural gas marketers, and industry trends. The prices are Deloitte's best estimate of how the future will look, based on the many uncertainties that exist in both the domestic Canadian and international petroleum industries. Deloitte considers the current monthly trends, the actual and trends for the year to date, and the prior year actual in determining the forecast. The crude oil and natural gas forecasts are based on yearly variable factors weighted to higher percent in current data and reflecting a higher percent to the prior year historical. These forecasts are Deloitte's interpretation of current available information and while they are considered reasonable, changing market conditions or additional information may require alteration from the indicated effective date.

Inflation forecasts and exchange rates, an integral part of the forecast, have also been considered.

	Price Inflation Rate	Cost Inflation Rate	Cdn to US Exchange Rate
2019	1.9%	1.9%	$0.753
2020	0.0%	0.0%	$0.760
2021	2.0%	2.0%	$0.760
2022	2.0%	2.0%	$0.780
2023	2.0%	2.0%	$0.800
2024 beyond	2.0%	2.0%	$0.800

Oil, NGL, and natural gas base case prices, utilized by Deloitte in the Deloitte Reserve Report were as follows:

	Oil			Natural Gas		Natural Gas Liquids
Year	WTI Cushing (Oklahoma)	Edmonton City Gate 40° API	Bow River 25° API Hardisty	Alberta Reference – Gas Prices	Alberta AECO – Gas Prices	Pentanes + Condensate Edmonton	Butanes Edmonton	Propane Edmonton
	($US/bbl)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/mcf)	($Cdn/mcf)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/bbl)
Forecast
2020	$58.00	$68.40	$53.95	$1.85	$2.10	$66.35	$23.95	$17.10
2021	$61.20	$73.15	$57.75	$2.05	$2.30	$73.15	$36.55	$25.60
2022	$65.55	$75.00	$59.35	$2.30	$2.55	$75.00	$48.75	$33.75
2023	$66.85	$76.95	$61.00	$2.55	$2.80	$76.95	$50.05	$34.65
2024	$68.20	$78.50	$62.25	$2.60	$2.85	$78.50	$51.05	$35.35
2025	$69.55	$80.05	$63.50	$2.65	$2.95	$80.05	$52.05	$36.05
2026	$70.95	$81.65	$64.75	$2.70	$3.00	$81.65	$53.10	$36.75
2027	$72.35	$83.30	$66.05	$2.75	$3.05	$83.30	$54.15	$37.50
2028	$73.80	$84.95	$67.35	$2.80	$3.10	$84.95	$55.25	$38.25
2029	$75.30	$86.65	$68.70	$2.85	$3.15	$86.65	$56.35	$39.00
Escalation of 2.0% Thereafter

Notes to table:
-	All prices are in Canadian dollars except WTI and NYMEX which are in U.S. dollars.
-	Edmonton City Gate prices based on light sweet crude posted at major Canadian refineries (40 Deg. API <0.5% Sulphur).
-	Natural Gas Liquid prices are forecasted at Edmonton therefore an additional transportation cost must be included to plant gate sales point.
-	1 Mcf is equivalent to 1 mmbtu.
-	Alberta gas prices, except AECO, include an average cost of service to the plant gate.

Finding and Development Costs

Yangarra's F&D costs for 2019, 2018 and the three-year average are presented in the tables below. The costs used in the F&D calculation are the capital costs related to: land acquisition and retention; drilling; completions; tangible well site; tie-ins; and facilities, plus the change in estimated future development costs as per the independent reserve report. Acquisition costs are net of any proceeds from dispositions of properties. Due to the timing of capital costs and the subjectivity in the estimation of future costs, the aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year. The reserves used in this calculation are Company net reserve additions, including revisions.

Proved Developed Producing Finding & Development Costs ($ millions)

	2019	2018	2017 – 2019
Capital expenditures	121.0	151.0	355.0
Reserve additions, net production (Mboe)	6,687	14,878	27,778
Proved Developed Producing F&D costs – including future capital ($/boe)	18.10	10.15	12.78
Proved Recycle Ratio ($22.35/boe operating netback)	1.24	2.69

Proved Finding & Development Costs ($ millions)

	2019	2018	2017 - 2019
Capital expenditures	121.0	151.0	355.0
Change in future capital	36.5	1.9	179.2
Total capital for F&D	157.5	152.9	534.2
Reserve additions, net production (Mboe)	14,665	23,072	59,241
Proved F&D costs – including future capital ($/boe)	10.74	6.63	9.02
Proved F&D costs – excluding future capital ($/boe)	8.25	6.54	5.99
Proved Recycle Ratio ($22.35/boe operating netback)
Including future capital	2.08	4.12
Excluding future capital	2.71	4.17

Proved plus Probable Finding & Development Costs ($ millions)

	2019	2018	2017 - 2019
Capital expenditures	121.0	151.0	355.0
Change in future capital	43.1	54.2	283.6
Total capital for F&D	164.1	205.2	638.6
Reserve additions, net production (Mboe)	23,912	41,847	95,108
Proved plus Probable F&D costs – including future capital ($/boe)	6.86	4.90	6.71
Proved plus Probable F&D costs – excluding future capital ($/boe)	5.06	3.61	3.73
Proved plus Probable Recycle Ratio ($22.35/boe operating netback)
Including future capital	3.26	5.57
Excluding future capital	4.42	7.57

Net Asset Value ("NAV")

As at December 31, 2019	PDP	PDP +PNP	Total Proved	Proved + Probable
Present Value Reserves, before tax (discounted at 10%)	413.7	453.2	1,112.5	1,668.5
Total Net Debt ($ million) (unaudited)	(187.0)	(187.0)	(187.0)	(187.0)
Proceeds from the exercise of options (2)	1.8	1.8	1.8	1.8
Net Asset Value	228.5	268.0	927.3	1,483.3
Fully diluted common shares outstanding (million)	87.0	87.0	87.0	87.0
Net asset value per share	$2.63	$3.08	$10.66	$17.05

Notes to table:
(1)	The preceding table shows what is customarily referred to as a "produce out" net asset value calculation under which the current value of Yangarra's reserves would be produced at the Deloitte forecast future prices and costs. The value is a snapshot in time as at December 31, 2019 and is based on various assumptions including commodity prices and foreign exchange rates that vary over time. In this analysis, the present value of the proved and probable reserves is calculated at a before tax 10 percent discount rate.
(2)	The calculation of proceeds from exercise of stock options and the diluted number of common shares outstanding only include stock options that are "in-the-money" based on the closing price of YGR of $1.35 as at December 31, 2019.
(3)	Net debt or adjusted working capital (deficit), which represent current assets less current liabilities, excluding current derivative financial instruments, are used to assess efficiency, liquidity and the general financial strength of the Company. There is no IFRS measure that is reasonably comparable to net debt or adjusted working capital (deficit).

Year End Disclosure

The financial statements for the year-ended December 31, 2019 are scheduled to be released on March 5, 2020.

Additional reserve information as required under NI 51-101 will be included in the Company's Annual Information Form which will be filed on SEDAR on or before March 31, 2020.

Reader Advisories:

Unaudited Financial Information and Non-IFRS Measures

Certain financial and operating information included in this press release for the quarter and year ended December 31, 2019, including F&D costs and netbacks are based on estimated unaudited financial results for the quarter and year then ended, and are subject to the same limitations as discussed under Forward Looking Information set out below. These estimated amounts may change upon the completion of audited financial statements for the year ended December 31, 2019 and changes could be material.

Oil and Gas Advisories. Natural gas has been converted to a barrel of oil equivalent (Boe) using 6,000 cubic feet (6 Mcf) of natural gas equal to one barrel of oil (6:1), unless otherwise stated. The Boe conversion ratio of 6 Mcf to 1 Bbl is based on an energy equivalency conversion method and does not represent a value equivalency; therefore Boe's may be misleading if used in isolation. References to natural gas liquids ("NGLs") in this news release include condensate, propane, butane and ethane and one barrel of NGLs is considered to be equivalent to one barrel of crude oil equivalent (Boe). One ("BCF") equals one billion cubic feet of natural gas. One ("Mmcf") equals one million cubic feet of natural gas.

All reserve references in this press release are "Company share gross reserves". Company share gross reserves are the Company's total working interest reserves (operating or non-operating) before the deduction of any royalty obligation s but including royalty interests payable the Company. It should not be assumed that the present worth of estimated future cash flow 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 Yangarra'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.

This press release contains metrics commonly used in the oil and natural gas industry which have been prepared by management, such as "recycle ratio", "operating netback", "finding and development costs", "reserve life index" and "net asset value". These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies and, therefore, should not be used to make such comparisons.

Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Yangarra's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from metrics presented in this press release, should not be relied upon for investment or other purposes.

All amounts in this news release are stated in Canadian dollars unless otherwise specified. Our oil and gas reserves statement for the year ended December 31, 2019, which will include complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, will be contained within our Annual Information Form which will be available on our SEDAR profile at www.sedar.com on or before March 31, 2020. The recovery and reserve estimates contained herein are estimates only and there is no guarantee that the estimated reserves will be recovered. In relation to the disclosure of estimates for individual properties, such estimates may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. The Company's belief that it will establish additional reserves over time with conversion of probable undeveloped reserves into proved reserves is a forward-looking statement and is based on certain assumptions and is subject to certain risks, as discussed below under the heading "Forward-Looking Information".

Forward Looking Information. This press release contains forward-looking statements and forward-looking information (collectively "forward-looking information") within the meaning of applicable securities laws relating to the Company's plans and other aspects of our anticipated future operations, management focus, strategies, financial, operating and production results and business opportunities. Forward-looking information typically uses words such as "anticipate", "believe", "continue", "sustain", "project", "expect", "forecast", "budget", "goal", "guidance", "plan", "objective", "strategy", "target", "intend" or similar words suggesting future outcomes, statements that actions, events or conditions "may", "would", "could" or "will" be taken or occur in the future, including statements about our strategy, plans, objectives, priorities and focus, growth plans; our estimations on future costs; volatility of commodity prices, and currency fluctuations. 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 is based on certain key expectations and assumptions made by our management, including expectations and assumptions concerning prevailing commodity prices, exchange rates, interest rates, applicable royalty rates and tax laws; future production rates and estimates of operating costs; performance of existing and future wells; reserve volumes; anticipated timing and results of capital expenditures; the success obtained in drilling new wells; the sufficiency of budgeted capital expenditures in carrying out planned activities; benefits to shareholders of our programs and initiatives, the timing, location and extent of future drilling operations; the expected timing of release of our audited financials and AIF; the state of the economy and the exploration and production business; results of operations; performance; business prospects and opportunities; the availability and cost of financing, labour and services; the impact of increasing competition; ability to efficiently integrate assets and employees acquired through acquisitions, ability to market oil and natural gas successfully and our ability to access capital.

Although we believe that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Yangarra can give no assurance that they will prove to be correct. Since forward-looking information addresses future events and conditions, by its very nature they involve inherent risks and uncertainties. Our actual results, performance or achievement could differ materially from those expressed in, or implied by, the forward-looking information and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking information will transpire or occur, or if any of them do so, what benefits that we will derive therefrom. Management has included the above summary of assumptions and risks related to forward-looking information provided in this press release in order to provide security holders with a more complete perspective on our future operations and such information may not be appropriate for other purposes.

Readers are cautioned that the foregoing lists of factors are not exhaustive. Additional information on these and other factors that could affect our operations or financial results are included in reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com).

These forward-looking statements are made as of the date of this press release and we disclaim any intent or obligation to update publicly any forward-looking information, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.

All reference to $ (funds) are in Canadian dollars unless otherwise stated.

Neither the TSX nor its Regulation Service Provider (as that term is defined in the Policies of the TSX) accepts responsibility for the adequacy and accuracy of this release.

SOURCE Yangarra Resources Ltd.

Jim Evaskevich, President and CEO, at [phone].

Related Links

http://www.yangarra.ca