Sign Up for FREE Daily Energy News
CDN NEWS  |   US NEWS  | TIMELY. FOCUSED. REVELANT. FREE
  • Stay Connected
  • linkedin
  • twitter
  • facebook
  • instagram
  • youtube2
BREAKING NEWS:
WEC - Western Engineered Containment
Copper Tip Energy Services
Hazloc Heaters
Copper Tip Energy
Hazloc Heaters
WEC - Western Engineered Containment

Yangarra Announces 2020 Year End Financials, Operating Results and Reserves


English Français 简体中文
These translations are done via Google Translate

CALGARY, AB, March 4, 2021 /CNW/ – Yangarra Resources Ltd. (“Yangarra” or the “Company“) (TSX: YGR) announces its financials,  operating results and reserves for the year ended December 31, 2020.

2020 was a volatile year with many challenges for the oil & gas industry in North America. Yangarra quickly responded to COVID-19 in early 2020 by reducing the capital program to zero until August 2020. Although this resulted in a decline in production, the Company worked to streamline operations and internalize third-party capital expenditures. As a result, Yangarra achieved lower drilling & completion costs which it expects to maintain as industry activity ramps up.  In 2021, the Company has embarked on several ESG initiatives to address methane emissions, is working on creating a stronger management structure and plans to diversify the board of directors by adding two new members.

With improving economics, through a combination of reduced costs & increasing commodity prices, Yangarra expects to use free cash flow in excess of maintenance capital to fund growth capital and to reduce net debt through 2021.

2020 Highlights

  • Average Production of 9,888 boe/d (45% liquids) a decrease of 21% from 2019
  • Oil and gas sales were $85.7 million with funds flow from operations of $45.5 million ($0.53 per share – basic)
  • Adjusted EBITDA (which excludes changes in derivative financial instruments) was $52.7 million ($0.62 per share – basic).
  • Net income of $4.8 million ($0.06 per share – basic) or $7.4 million before tax, resulting in a net income margin of 6%
  • Operating costs were $6.32/boe (including $1.06/boe of transportation costs)
  • Operating netbacks, which include the impact of commodity contracts, were $16.02 per boe
  • Operating margins were 68% and funds flow margins were 47%
  • G&A costs of $0.65/boe
  • Royalties were 5% of oil and gas revenue
  • Capital expenditures (including $0.4 million of land) were $51.5 million
  • Net debt (which excludes the current derivative financial instruments) was $197.4 million
  • Retained earnings of $109 million
  • Corporate LMR is 7.6 with decommissioning liabilities of $12.6 million (discounted)

Fourth Quarter Highlights

  • Average production of 9,169 boe/d (45% liquids) during the quarter, a 27% decrease from the same period in 2019
  • Oil and gas sales were $23.1 million, a decrease of 37% from the same period in 2019
  • Funds flow from operations of $12.5 million ($0.15 per share – basic), a decrease of 41% from the same period in 2019
  • Adjusted EBITDA (which excludes changes in derivative financial instruments) was $14.9 million ($0.19 per share – basic)
  • Net income of $4.3 million ($0.05 per share – basic, $5.8 million before tax), a decrease of 39% from the same period in 2019
  • Operating costs were $6.05/boe (including $1.03/boe of transportation costs)
  • Field operating netbacks were $19.77/boe
  • Operating netbacks, which include the impact of commodity contracts, were $19.39/boe
  • Operating margins were 71% and funds flow from operations margins were 54%
  • G&A costs of $0.89/boe
  • Royalties were 6% of oil and gas revenue
  • All in cash costs were $12.19/boe
  • Capital expenditures were $15.2 million
  • Net Debt to fourth quarter annualized funds flow from operations was 3.96 : 1

Operations Update

Yangarra set its 2021 capital budget at $60 million prior to the announcement of multiple COVID-19 vaccines when WTI prices hovered around US$45.00/bbl. Recently, the general market tone has improved dramatically with spot prices increasing in excess of 40%. If commodity prices maintain current levels, Yangarra expects to keep one rig fully utilized for the year.

Yangarra has drilled and completed four wells to date in 2021. Drilling and completion costs for these wells continue to track with Yangarra’s previous disclosure on well costs. The wells have been brought on production and early indications are the wells meet area average type-curves.

As a result of inclement weather & completions activity, January & February production was negatively impacted. This production is now back on-stream.

ESG Initiatives

For 2020, Yangarra internally estimated that the Company’s Scope 1 & 2 carbon equivalent emissions were approximately 110,000 tons, resulting in a carbon per boe intensity of ~30 kg/boe based on average 2020 production.

In 2021, the Company has embarked on several key initiatives to target methane emissions reductions in a cost-effective manner. Yangarra’s targeted goal is to reduce overall methane emissions by 55% throughout 2021-2024 based on current production levels. The Company’s current emissions meet existing regulatory guidelines but the targeted improvements position Yangarra to exceed these guidelines and should result in the ability to create and sell carbon offset credits in the future. These initiatives target carbon intensity reductions of 25% during this period. The Company plans to utilize federal government funding to assist with financing a portion of the costs.

Yangarra’s decommissioning liability of $12.6 million is a direct result of the Company being a responsible stakeholder by abandoning & reclaiming well sites as the economic life of a well ends. There are currently 34 non-producing wells that need to be abandoned and reclaimed.  The Company has secured $535,000 from the Alberta Government’s site rehabilitation program to assist with these expenditures and plans to have a majority of these wells abandoned and reclaimed over the next two years. The Company’s strong decommissioning liability, along with a low-cost structure, were instrumental in the bank line review process.

The Company has adopted a management committee structure. The committee will be used review and approve key organizational, financial, operational and strategic decisions for the Company. This leadership structure utilizes a highly collaborative decision-making model that draws upon the collective knowledge, experience, business acumen and skills of the senior management team.  The current management committee is comprised of Jim Evaskevich, Trish Olynyk, Lorne Simpson, James Glessing and Gurdeep Gill.

In accordance with the principle of the Company’s Board Diversity Policy, Yangarra is pleased to announce that its Nominating, Compensation and Corporation Governance Committee has identified two new individuals to be nominated as board members at the Company’s upcoming, annual general meeting of shareholders:

Dale Miller, P.Eng: Mr. Miller is currently President of Dark Horse Energy Consultants Ltd. and the COO of Hillcrest Petroleum Ltd. He was previously the President and COO of Long Run Exploration. Mr. Miller has 35+ years of experience in the Western Canadian sedimentary basin, including AEC, Mobil Oil, Penn West Petroleum, Gibraltar Exploration and Pace Oil & Gas. He has a Bachelor Science, Petroleum Engineering (Honours) from the University of Tulsa.

Penny Payne, CPA, CA: Ms. Payne is currently President of Vercatis Consulting Ltd. and has 20 years of financial accounting and reporting experience.  Formerly, she was the Chief Financial Officer of Yangarra from 2006-2010. Ms. Payne started her accounting career at PwC Canada and MNP LLP and obtained her CA designation in 1996.

Reserve Report Highlights

All reserves information contained in this press release are based on the Company’s 2020 NI 51-101 oil and gas reserve report as prepared by Deloitte LLP (The “2020 Reserve Report“).

Proved Developed Producing (“PDP”) Reserves

  • 8 million boe (11% decrease from 2019)
    • Since Yangarra pioneered development of the bioturbated Cardium formation in 2016, decline profiles were determined without the benefit of production history as none existed and were therefore based entirely on initial production rates. Since then, Yangarra has accumulated production data and has now established expected well performance for new bioturbated wells. Yangarra’s new type curve in the January 2021 corporate presentation matches well performance. The 2020 year-end reserves were negatively impacted by this re-assessment.
  • Net present value before tax discounted at 10% (“NPV10”) of $316 million (24% decrease from 2019)
  • The reserve report uses an Edmonton Par price of $53.25/bbl for 2021 and current pricing for Edmonton par is over $70.00/bbl
  • Finding and development costs (“F&D”) of $60.76/boe, resulting in a PDP recycle ratio of 0.26 times
    • Yangarra’s trailing 3-year PDP F&D is $14.43/boe
  • PDP net asset value per fully diluted common share (“NAV per FD Share”) of $1.37
  • PDP additions replaced 23% of 2020 production

Total Proved reserves (“1P”)

  • 4 million boe (13% increase from 2019)
  • NPV10 of $1.1 billion (6% decrease from 2019)
  • 1P future development costs of $420 million
  • F&D costs of $2.88/boe resulting in a recycle ratio of 5.56 times
    • F&D costs were impacted by the significant cost reductions the Company created on drilling and completions, which resulted in a reduction in future development costs in the reserve report
    • Yangarra’s trailing 3-year 1P F&D is $6.75/boe
  • 1P NAV per FD Share of $9.40
  • 1P Reserve Life Index (“RLI”) based on fourth quarter 2020 production of 28.8 years
  • 1P additions replaced 400% of 2020 production

Proved plus probable reserves (“2P”)

  • 6 million boe (8% increase from 2019)
  • NPV10 of $1.5 billion (11% decrease from 2019)
  • 2P Future development costs of $622 million
  • Finding and development costs of $1.49/boe resulting in a recycle ratio of 10.74 times
    • Yangarra’s trailing 3-year 2P F&D is $4.83/boe
  • 2P NAV per FD Share of $14.21
  • RLI of 47.1 years
  • 2P additions replaced 430% of 2020 production

Financial Summary

2020 2019 Year Ended
Q4 Q3 Q4 2020 2019
Statements of Comprehensive Income
Petroleum & natural gas sales $ 23,064 $ 18,910 $ 35,990 $ 85,699 $ 143,976
Net income (loss) (before tax) $ 5,754 $ 691 $ 9,405 $ 7,389 $ 47,978
Net income (loss) $ 4,276 $ 537 $ 7,020 $ 4,847 $ 43,313
Net income (loss)  per share – basic $ 0.05 $ 0.01 $ 0.08 $ 0.06 $ 0.51
Net income (loss) per share – diluted $ 0.05 $ 0.01 $ 0.08 $ 0.06 $ 0.51
Statements of Cash Flow
Funds flow from operations $ 12,460 $ 10,038 $ 21,005 $ 45,524 $ 92,236
Funds flow from operations per share – basic $ 0.15 $ 0.12 $ 0.25 $ 0.53 $ 1.08
Funds flow from operations per share – diluted $ 0.15 $ 0.12 $ 0.25 $ 0.53 $ 1.08
Cash from operating activities $ 19,192 $ 7,411 $ 25,469 $ 43,872 $ 81,205
Statements of Financial Position
Property and equipment $ 563,290 $ 557,827 $ 541,799 $ 563,290 $ 541,799
Total assets $ 609,989 $ 603,817 $ 592,195 $ 609,989 $ 592,195
Working capital deficit (surplus) $ (6) $ (6,622) $ (906) $ (6) $ (906)
Adjusted Net Debt $ 197,379 $ 193,878 $ 187,712 $ 197,379 $ 187,712
Shareholders equity $ 312,260 $ 307,322 $ 303,643 $ 312,260 $ 303,643
Weighted average number of shares – basic 85,380 85,380 85,370 85,380 85,364
Weighted average number of shares – diluted 85,588 85,677 85,708 85,783 85,701

Company Netbacks ($/boe)

2020 2019 Year Ended
Q4 Q3 Q4 2020 2019
Sales price $ 27.34 $ 24.44 $ 31.13 $ 23.68 $           31.37
Royalty expense (1.52) (1.26) (2.49) (1.16) (2.34)
Production costs (5.02) (4.83) (6.19) (5.26) (5.76)
Transportation costs (1.03) (1.28) (1.11) (1.06) (1.08)
Field operating netback 19.77 17.08 21.34 16.20 22.19
Realized gain (loss) on commodity contract settlement (0.38) (0.41) 0.25 (0.18) 0.24
Operating netback 19.39 16.67 21.59 16.02 22.43
G&A (0.89) (0.28) (1.17) (0.65) (0.65)
Cash Finance expenses (3.73) (3.41) (1.53) (4.21) (1.68)
Depletion and depreciation (8.04) (8.60) (8.33) (8.36) (8.37)
Non Cash – Finance expenses (0.06) (1.98) (0.04) (0.05) (0.05)
Abandonment Expenses (0.21) (0.75) (0.05) (0.19)
Provision for Credit Losses (0.57) (0.14)
Stock-based compensation (0.61) (0.13) (0.61) (0.74) (0.79)
Unrealized gain (loss) on financial instruments 0.96 (1.37) (0.44) 0.09 (0.10)
Deferred income tax (1.75) (0.20) (2.06) (0.70) (1.02)
Net Income netback $ 5.06 $ 0.69 $ 6.09 $ 1.34 $            9.44

Business Environment

2020 2019 Year Ended
Q4 Q3 Q4 2020 2019
Realized Pricing (Including realized commodity contracts)
Oil ($/bbl) $ 55.13 $ 49.49 $ 67.06 $ 47.64 $ 69.46
NGL ($/bbl) $ 24.32 $ 19.01 $ 19.65 $ 18.45 $ 25.83
Gas ($/mcf) $ 2.64 $ 2.47 $ 2.48 $ 2.28 $ 1.80
Realized Pricing (Excluding commodity contracts)
Oil ($/bbl) $ 55.13 $ 49.49 $ 67.06 $ 47.59 $ 69.46
NGL ($/bbl) $ 24.43 $ 18.96 $ 18.03 $ 18.49 $ 24.31
Gas ($/mcf) $ 2.75 $ 2.47 $ 2.48 $ 2.34 $ 1.80
Oil Price Benchmarks
West Texas Intermediate (“WTI”) (US$/bbl) $ 42.66 $ 40.89 $ 56.95 $ 39.40 $ 57.03
Edmonton Par ($/bbl) $ 50.24 $ 48.66 $ 68.05 $ 45.34 $ 69.16
Edmonton Par to WTI differential (US$/bbl) $ (4.01) $ (4.35) $ (5.40) $ (5.54) $ (4.90)
Natural Gas Price Benchmarks
AECO gas ($/mcf) $ 2.64 $ 2.28 $ 2.48 $ 2.23 $ 1.71
Foreign Exchange
U.S./Canadian Dollar Exchange 0.77 0.75 0.76 0.75 0.75

Operations Summary

Net petroleum and natural gas production, pricing and revenue are summarized below:

2020 2019 Year Ended
Q4 Q3 Q4 2020 2019
Daily production volumes
Natural gas (mcf/d) 30,322 27,445 41,483 32,404 39,663
Oil (bbl/d) 2,269 2,135 3,712 2,611 3,941
NGL’s (bbl/d) 1,846 1,700 1,942 1,876 2,020
   Combined (boe/d 6:1) 9,169 8,409 12,568 9,888 12,572
Revenue
Petroleum & natural gas sales – Gross $ 23,064 $ 18,910 $ 35,990 $ 85,699 $ 143,976
Realized gain (loss) on commodity contract settlement (323) (319) 290 (658) 1,122
Total sales 22,741 18,591 36,280 85,041 145,098
Royalty expense (1,283) (976) (2,879) (4,213) (10,760)
Total Revenue – Net of royalties $ 21,458 $ 17,615 $ 33,401 $ 80,828 $ 134,338

Working Capital Summary

The following table summarizes the change in working capital during the year ended December 31, 2020 and December 31, 2019: 

Year ended Year ended
December 31, 2020 December 31, 2019
Adjusted Net Debt – beginning of period $ (187,711) $ (155,882)
 Funds flow from operations 45,524 92,236
 Additions to property and equipment (51,093) (115,276)
 Decommissioning costs incurred (389) (966)
 Additions to E&E Assets (426) (5,723)
 Issuance of shares 41
 Provision for Credit Losses (664)
 Other (3,284) (1,477)
 Adjusted Net Debt – end of period $ (197,379) $ (187,711)
Credit facility limit $ 210,000 $ 225,000

Capital Spending

Capital spending is summarized as follows:

2020 2019 Year Ended
Cash additions Q4 Q3 Q4 2020 2019
Land, acquisitions and lease rentals $ (75) $ 258 $ 38 $ 324 $ 344
Drilling and completion 14,030 8,036 16,997 44,816 83,060
Geological and geophysical 134 190 447 640 1,041
Equipment 753 1,232 2,503 4,226 28,977
Other asset additions 347 281 193 1,087 979
$ 15,189 $ 9,997 $ 20,178 $ 51,093 $ 114,401
Exploration & evaluation assets $ $ $ 480 $ 426 $ 5,723

Oil and Gas Reserves

The following tables summarize certain information contained in the 2020 Reserve Report. The 2020 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)

Conventional

Gas

(MMcf)

Shale  

Gas  

(MMcf)

Total BOE

2020

(Mboe)

Total BOE

2019

(Mboe)

Proved Developed Producing 4,576 4,686 79,807 1,147 22,754 25,518
Proved Developed Non-Producing 1,870 2,748 47,868 0 12,595 2,176
Proved Undeveloped 13,527 12,276 206,195 5496 61,084 57,897
Total Proved 19,972 19,709 333,870 6,643 96,434 85,592
Probable 12,154 12,959 207,953 8,132 61,127 60,045
Total Proved Plus Probable 32,126 32,668 541,823 14,775 157,561 145,637
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, 2020(2)

 

As At

December 31,

2019 (3)

Reserves Category 0.0%

(M$)

5.0%

(M$)

10.0%

(M$)

15.0%

(M$)

20.0%

(M$)

10.0%

(M$)

Proved Developed Producing 506,456 387,937 316,329 268,787 234,994 413,669
Proved Developed Non-Producing 263,656 198,336 160,446 135,571 117,893 39,514
Proved Undeveloped 1,054,480 758,251 573,429 450,352 363,872 659,274
Total Proved 1,824,592 1,344,523 1,050,203 854,710 716,759 1,112,457
Probable 1,354,564 722,397 439,246 290,103 202,846 556,057
Total Proved Plus Probable 3,179,157 2,066,921 1,489,449 1,144,813 919,604 1,668,514
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, 2020.
(3) Forecast pricing used is based on Deloitte published price forecasts effective December 31, 2019.
(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, 2020 against such reserves at December 31, 2019 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 19,186.1 12,549.7 31,735.8 17,996.4 13,277.5 31,273.9
Production -978.5 -978.5 -755.6 -755.6
Technical Revisions -328.6 -569.8 -898.4 1,235.2 152.2 1,387.4
Extensions 2,102.2 179.2 2,281.4 1,398.4 92.3 1,490.7
Economic Factors -8.8 -5.2 -14.0 -165.4 -562.7 -728.1
Closing Balance 19,972.4 12,153.9 32,126.4 19,709.0 12,959.3 32,668.2
Conventional Gas Shale Gas
Gross
Proved
Gross
Probable
Gross
Proved Plus
Probable
Gross
Proved
Gross
Probable
Gross
Proved Plus
Probable
(MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf)
Opening Balance 283,084.6 196,747.4 479,832.0 6,290.0 7.595.7 13,885.7
Production -12,839.2 -12,839.2 -92.1 -92.1
Technical Revisions 39,261.3 9,629.9 48,891.1 445.0 536.0 981.2
Extensions 24,363.2 1,607.5 25,970.6
Economic Factors -0.2 -31.4 -31.6
Closing Balance 333,869.6 207,953.4 541,823.0 6,643.0 8,131.8 14,774.8
MBOE
Gross
Proved
Gross
Probable
Gross
Proved Plus
Probable
(Mboe) (Mboe) (Mboe)
Opening Balance 85,411.6 59,884.4 145,296.0
Production -3,889.3 -3,889.3
Technical Revisions 7,524.3 1,276.7 8,801.0
Extensions 7,561.2 539.4 8,100.6
Economic Factors -174.3 -573.1 -747.4
Closing Balance 96,433.5 61,127.4 157,560.9

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
2020 1.9% 0.8% 0.754
2021 0.0% 0.0% 0.770
2022 2.0% 2.0% 0.780
2023 2.0% 2.0% 0.800
2024 2.0% 2.0% 0.800
2025 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
Alberta
Reference – Gas
Prices
Alberta
AECO – Gas
Prices
Pentanes +
Condensate
Edmonton
Butanes
Edmonton
Propane
Edmonton
($US/bbl) ($Cdn/bbl) ($Cdn/mcf) ($Cdn/mcf) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl)
Forecast
2021 $46.00 $53.25 $2.40 $2.65 $53.25 $23.95 $18.65
2022 $54.05 $62.80 $2.45 $2.70 $62.80 $34.55 $28.25
2023 $59.80 $68.30 $2.50 $2.75 $68.30 $44.35 $30.75
2024 $61.00 $69.65 $2.55 $2.80 $69.65 $45.25 $31.35
2025 $62.25 $71.05 $2.60 $2.85 $71.05 $46.15 $32.00
2026 $63.50 $72.50 $2.65 $2.95 $72.50 $47.10 $32.65
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 2020, 2019 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)

2020 2019 2018 – 2020
Capital expenditures 51.5 121.0 323.5
Reserve additions, net production (Mboe) 845 6,687 22,410
Proved Developed Producing F&D costs – including future capital ($/boe) 60.76 18.10 14.43
Proved Recycle Ratio ($16.02/boe operating netback) 0.26 1.24

Proved Finding & Development Costs ($ millions)

2020 2019 2018 – 2020
Capital expenditures 51.5 121.0 323.5
Change in future capital (9.7) 36.5 28.7
Total capital for F&D 41.8 157.5 352.2
Reserve additions, net production (Mboe) 14,452 14,665 52,189
Proved F&D costs – including future capital ($/boe) 2.88 10.74 6.75
Proved F&D costs – excluding future capital ($/boe) 3.55 8.25 6.20
Proved Recycle Ratio ($16.02/boe operating netback)
   Including future capital 5.56 2.08
   Excluding future capital 4.51 2.71

Proved plus Probable Finding & Development Costs ($ millions)

2020 2019 2018 – 2020
Capital expenditures 51.5 121.0 323.5
Change in future capital (28.2) 43.1 69.1
Total capital for F&D 23.3 164.1 392.6
Reserve additions, net production (Mboe) 15,534 23,912 81,293
Proved plus Probable F&D costs – including future capital ($/boe) 1.49 6.86 4.83
Proved plus Probable F&D costs – excluding future capital ($/boe) 3.31 5.06 3.98
Proved plus Probable Recycle Ratio ($16.02/boe operating netback)
   Including future capital 10.74 3.26
   Excluding future capital 4.85 4.42

Net Asset Value (“NAV”)

As at December 31, 2020 PDP Total
Proved
Proved +
Probable
Present Value Reserves, before tax (discounted at 10%) 316.3 1,050.2 1,489.4
Total Net Debt ($ million) (unaudited) (197.4) (197.4) (197.4)
Proceeds from the exercise of options (2) 6.2 6.2 6.2
Net Asset Value 125.1 859.0 1,298.3
Fully diluted common shares outstanding (million)

 

91.3 91.3 91.3
Net asset value per share $1.37 $9.40 $14.21
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, 2020 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 $0.66 as at December 31, 2020.
(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).

Annual General Meeting of Shareholders

The Company’s Annual General Meeting of Shareholders is scheduled for 10:00 AM on Thursday April 29, 2021 in the Tillyard Management Conference Centre, Main Floor, 715 5th Avenue SW, Calgary, AB.

As a precaution due to the COVID-19 pandemic, the Company will ensure social distancing will be in effect at the annual meeting and Yangarra does not plan to have a formal presentation at the conclusion of the meeting.  Please ensure your vote is represented at the meeting by submitting your Proxy as per the instructions in the in the Notice of Meeting of Shareholders.   A conference call number will be provided for shareholders to listen to the formal portion of the meeting.  We strongly encourage all shareholders to register their votes by proxy and participate in the meeting via the conference call.

Year End Disclosure

The Company’s financial statements, notes to the financial statements, management’s discussion and analysis and annual information form will be filed on SEDAR (www.sedar.com) and are available on the Company’s website (www.yangarra.ca).

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, 2020, 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 is be available on our SEDAR profile at www.sedar.com. 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”

Non-IFRS Financial Measures

This press release contains references to measures used in the oil and natural gas industry such as “funds flow from operations”, “operating netback”, “adjusted working capital deficit”, and “net debt”.  These measures do not have standardized meanings prescribed by International Financial Reporting Standards (“IFRS“) and, therefore should not be considered in isolation.  These reported amounts and their underlying calculations are not necessarily comparable or calculated in an identical manner to a similarly titled measure of other companies where similar terminology is used.  Where these measures are used they should be given careful consideration by the reader.  These measures have been described and presented in this press release in order to provide shareholders and potential investors with additional information regarding the Company’s liquidity and its ability to generate funds to finance its operations.

Funds flow from operations should not be considered an alternative to, or more meaningful than, cash provided by operating, investing and financing activities or net income as determined in accordance with IFRS, as an indicator of Yangarra’s performance or liquidity.  Funds flow from operations is used by Yangarra to evaluate operating results and Yangarra’s ability to generate cash flow to fund capital expenditures and repay indebtedness.  Funds flow from operations denotes cash flow from operating activities as it appears on the Company’s Statement of Cash Flows before decommissioning expenditures and changes in non-cash operating working capital. Funds flow from operations is also derived from net income (loss) plus non-cash items including deferred income tax expense, depletion and depreciation expense, impairment expense, stock-based compensation expense, accretion expense, unrealized gains or losses on financial instruments and gains or losses on asset divestitures.  Funds from operations netback is calculated on a per boe basis and funds from operations per share is calculated as funds from operations divided by the weighted average number of basic and diluted common shares outstanding.  Operating netback denotes petroleum and natural gas revenue and realized gains or losses on financial instruments less royalty expenses, operating expenses and transportation and marketing expenses calculated on a per boe basis.  Adjusted working capital deficit includes current assets less current liabilities excluding the current portion of the amount drawn on the credit facilities, the current portion of the fair value of financial instruments and the deferred premium on financial instruments.  Yangarra uses net debt as a measure to assess its financial position.  Net debt includes current assets less current liabilities excluding the current portion of the fair value of financial instruments and the deferred premium on financial instruments, plus the long-term financial obligation.

Readers should also note that adjusted earnings before interest, taxes, depletion & depreciation, amortization (“Adjusted EBITDA”) is a non-IFRS financial measures and do not have any standardized meaning under IFRS and is therefore unlikely to be comparable to similar measures presented by other companies. Yangarra believes that Adjusted EBITDA is a useful supplemental measure, which provide an indication of the results generated by the Yangarra’s primary business activities prior to consideration of how those activities are financed, amortized or taxed. Readers are cautioned, however, that Adjusted EBITDA should not be construed as an alternative to comprehensive income (loss) determined in accordance with IFRS as an indicator of Yangarra’s financial performance.

Please refer to the management discussion and analysis for the year ended December 31, 2020 for Non- IFRS financial measure reconciliation tables.

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, expectations on well economics, availability and use of cash flow, well performance expectations, availability of funding and capital plans, 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 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.

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.

For further information: James Evaskevich, President & CEO 403-262-9558.

Related Links

http://www.yangarra.ca

 



Share This:



More News Articles


New SHOWCASE Directory Companies

 

Delta Remediation Inc.
The Coverall Shop
Axis Communciations
Muddy Boots
Di-Corp
Vista Projects Limited
Payload Technologies Inc.
Smart-Project Management Inc. / Trusted Pipeline Advisor