Yangarra Resources Ltd. — Management Reports 2020

Mar 5, 2020

Yangarra Resources Ltd. Management's Discussion and Analysis For the year ended December 31, 2019

YANGARRA RESOURCES LTD. MANAGEMENT'S DISCUSSION AND ANALYSIS

For the year ended December 31, 2019 (000's, Canadian dollars, except per share and per unit amounts)

Management's discussion and analysis ("MD&A") of the financial condition and the results of operations should be read in conjunction with the December 31, 2019 audited consolidated financial statements, together with the accompanying notes.

Additional information about Yangarra filed with Canadian securities commissions is available on-line at www.sedar.com.

The MD&A has been prepared using information that is current to March 5, 2020.

The financial information presented herein has been prepared on the basis of International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board. Throughout this discussion, percentage changes are calculated using numbers rounded to the decimal to which they appear. All references to dollar amounts are in Canadian dollars.

BOE Presentation – Production information is commonly reported in units of barrel of oil equivalent ("boe"). For purposes of computing such units, natural gas is converted to equivalent barrels of oil using a conversion factor of six thousand cubic feet to one barrel of oil. This conversion ratio of 6:1 is based on an energy equivalent wellhead value for the individual products. Such disclosure of boe may be misleading, particularly if used in isolation. Readers should be aware that historical results are not necessarily indicative of future performance.

Non–IFRS and Additional IFRS Measures

This document contains "funds flow from (used in) operations", which is an additional IFRS measure. The Company uses funds flow generated from (used in) operations as a key measure to demonstrate the Company's ability to generate funds to repay debt and fund future capital investment. This document also contains the terms "net debt or adjusted working capital (deficit)" and "netbacks", which are non-IFRS financial measures. The Company uses these measures to help evaluate its performance. These non-IFRS financial measures do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures presented by other issuers.

Funds flow from operations

Yangarra's determination of funds flow from operations and funds flow from operations per share may not be comparable to that reported by other companies. Management uses funds flow from operations to analyze operating performance and leverage and considers funds flow from operations to be a key measure as it demonstrates the Company's ability to generate cash necessary to fund future capital investments and to repay debt, if applicable. Funds flow from operations is calculated using cash from operating activities before changes in non-cash working capital and decommissioning costs incurred. Yangarra presents funds flow from operations per share whereby per share amounts are calculated using weighted average shares outstanding consistent with the calculation of income per share.

The following table reconciles funds flow from operations to cash from operating activities, which is the most directly comparable measure calculated in accordance with IFRS:

	2019		2018		Year Ended
		Q4	Q4		2019		2018
Cash from operating activities	$	25,469	$25,952	$	81,205	$	83,768
Change in fair value of foreign exchange contracts		888	-		-
Decommissioning costs incurred		388	333		966		333
Changes in non-cash working capital		(5,740)	(9,118)		10,065		(1,767)
Funds flow from operations	$	21,005	$17,167	$	92,236	$	82,334

MANAGEMENT'S DISCUSSION AND ANALYSIS

For the year ended December 31, 2019 (000's, Canadian dollars, except per share and per unit amounts)

Netbacks

The Company considers corporate netbacks to be a key measure as they demonstrate Yangarra's profitability relative to current commodity prices. Corporate netbacks are comprised of operating, field operating, funds flow from operations and net income / (loss) netbacks. Operating netback is calculated as the average sales price of its commodities (including realized gains on financial instruments) and then subtracts royalties, operating costs and transportation expenses. Field operating netback subtractsthe realized gains on financial instruments, Funds flow from operations netback starts with the operating netback and further deducts general and administrative costs, finance expense and adds finance income. To calculate the net income (loss) netback, Yangarra takes the funds flow netback and deducts share-based compensation expense as well as depletion and depreciation charges, accretion expense, unrealized gains on financial instruments, any impairment or exploration and evaluation expense and deferred income taxes. There is no IFRS measure that is reasonably comparable to netbacks.

Funds flow from operations margins and Operating margins

Are calculated as the ratio of Funds flow from operations netbacks to sales price and operating netback to sales price.

Adjusted Net debt

Adjusted net debt, 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).

	Dec 31, 2019	Dec 31, 2018
Bank Debt	$190,291	$134,489
Accounts receivable	(24,591)	(26,203)
Prepaid expenses and inventory	(3,857)	(4,255)
Accounts payable and accrued liabilities	25,869	51,851
Foreign exchange contract	-	-
Adjusted net Debt	$187,712	$155,882

Adjusted earnings before interest, taxes, depletion & depreciation, amortization

Adjusted earnings before interest, taxes, depletion & depreciation, amortization ("Adjusted EBITDA") which represents EBITDA, excluding changes in derivative financial instruments are used to assess efficiency, liquidity and the general financial strength of the Company.

	2019		2018	Year Ended
		Q4	Q4		2019		2018
Net income (loss) for the year	$	7,020	$13,315	$	43,313	$	33,566
Finance		1,815	2,003		7,929		5,227
Deferred tax expense		2,385	5,527		4,665		14,229
Depletion, depreciation and impairment		9,630	8,568		38,413		32,645
Change in fair value of commodity contracts		512	(12,318)		450		(3,774)
Foreign exchange transactions		(358)	-		-		-
Adjusted EBITDA	$	21,004	$17,095	$	94,770	$	81,893

YANGARRA RESOURCES LTD. MANAGEMENT'S DISCUSSION AND ANALYSIS

For the year ended December 31, 2019 (000's, Canadian dollars, except per share and per unit amounts)

Working Capital deficit (surplus)

Working capital deficit (surplus) is the total of current assets less the total of current liabilities and is used to assess efficiency, liquidity and the general financial strength of the Company

Forward-looking Statements – Certain information regarding the Company set forth in this report, including management's assessment of the Company's future plans and operations, contain forward-looking statements that involve substantial known and unknown risks and uncertainties. These risks and uncertainties, many of which are beyond the Company's control, include the impact of general economic conditions and specific industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, the lack of available qualified personnel or management, stock market volatility and ability to access sufficient capital from internal and external sources. The Company's actual results, performance or achievements could differ materially from those expressed in, or implied by, these forward-looking statements, and accordingly, no assurance can be given that any events anticipated by the forward-looking statements will transpire or occur, or if any of them do, what benefits the Company can derive from such events.

MANAGEMENT'S DISCUSSION AND ANALYSIS

For the year ended December 31, 2019 (000's, Canadian dollars, except per share and per unit amounts)

Overview

Yangarra Resources Ltd. ("Yangarra" or the "Company") is a junior oil and gas company engaged in the exploration, development and production of natural gas and oil with operations in Western Canada, with a main focus on the Cardium in Central Alberta, where the Company has extensive infrastructure and land holdings. Yangarra is dedicated to creating value for its shareholders through its commitment to a clear business strategy and performance objectives. The Company's strategy is to increase the value of its corporate assets through the drill bit and by assembling a large focused land base in Central Alberta that features high-quality, long-life light oil and liquids-rich gas reserves. The Company has assembled a significant future drilling inventory and will strive to grow this inventory through drilling, geology and strategic acquisitions.

2019 Highlights

• Average Production of 12,572 boe/d (47% liquids) an increase of 33% from 2018
• Oil and gas sales were $145 million with funds flow from operations of $92 million ($1.08 per share - basic)
• Adjusted EBITDA (which excludes changes in derivative financial instruments) was $95 million ($1.12 per share - basic), with adjusted EBITDA margins of 66%
• Net income of $43 million ($0.51 per share basic) or $48 million before tax, resulting in a net income margin of 30%
• Operating costs were $6.85/boe (including $1.08/boe of transportation costs)
• Operating netbacks, which include the impact of commodity contracts, were $22.43 per boe
• Operating margins were 71% and funds flow margins were 64%
• G&A costs of $0.65/boe
• Royalties were 7% of oil and gas revenue
• Capital expenditures (including $6 million of land) were $120 million
• Net debt (which excludes the current derivative financial instruments) was $188 million
• Net Debt to funds flow from operations was 2.0 : 1
• Retained earnings of $104 million
• Corporate LMR is 11.92 with decommissioning liabilities of $15 million (discounted)

Fourth Quarter Highlights

• Average production of 12,568 boe/d (45% liquids) during the quarter, a decrease of 1% from the third quarter of 2019 and a 2% increase from the same period in 2018

• Oil and gas sales were $36 million, an increase of 19% from the same period in 2018

• Funds flow from operations of $21 million ($0.25 per share basic), an increase of 22% from the same period in 2018

• Adjusted EBITDA (which excludes changes in derivative financial instruments) was $21 million ($0.25 per share - basic)

• Net income of $7 million ($0.09 per share basic, $9 million before tax), a decrease of 47% from the same period in 2018 and represents the 12th consecutive quarter of net income

• Operating costs were $7.30/boe (including $1.11/boe of transportation costs)

• Field operating netbacks were $21.34/boe

• Operating netbacks, which include the impact of commodity contracts, were $21.59/boe

• Operating margins were 69% and funds flow from operations margins were 58%

• G&A costs of $1.17/boe

• Royalties were 8% of oil and gas revenue

• Capital expenditures (including $0.5 million on land) were $21 million

• Net Debt to fourth quarter annualized funds flow from operations was 2.2 : 1

Operations Update

Yangarra has drilled six wells and completed five wells in the first quarter of 2020 leaving four wells drilled and uncompleted at the end of the quarter. Yangarra elected to reduce first quarter activity as per the Company's strategy of reducing capital spending when commodity pricing falls below internal thresholds for rates of return.

	2019	2018			Year Ended
	Q4	Q4		2019		2018
Statements of Comprehensive Income
Petroleum & natural gas sales	$35,990	$30,174	$	143,976	$	134,978
Net income (before tax)	$9,405	$18,842	$	47,978	$	47,795
Net income	$7,020	$13,315	$	43,313	$	33,566
Net income per share - basic	$0.08	$0.16	$	0.51	$	0.40
Net income per share - diluted	$0.08	$0.15	$	0.51	$	0.39
Statements of Cash Flow
Funds flow from operations	$21,005	$17,167	$	92,236	$	82,335
Funds flow from operations per share - basic	$0.25	$0.20	$	1.08	$	0.97
Funds flow from operations per share - diluted	$0.25	$0.20	$	1.08	$	0.95
Cash from operating activities	$25,469	$25,952	$	81,205	$	83,768
Statements of Financial Position
Property and equipment	$541,799	$454,772	$	541,799	$	454,772
Total assets	$592,195	$501,974	$	592,195	$	501,974
Working capital deficit (surplus)	$(906)	$20,775	$	(906)	$	20,775
Adjusted Net Debt	$187,712	$155,882	$	187,712	$	155,882
Shareholders equity	$303,643	$255,336	$	303,643	$	255,336
Weighted average number of shares - basic	85,370	85,340		85,364		84,653
Weighted average number of shares - diluted	85,708	86,981		85,701		86,860

Financial Information

MANAGEMENT'S DISCUSSION AND ANALYSIS

For the year ended December 31, 2019 (000's, Canadian dollars, except per share and per unit amounts)

Business Environment

	2019	2018	Year Ended
	Q4	Q4	2019	2018
Realized Pricing (Including realized commodity contracts)
Oil ($/bbl)	$67.06	$44.46	$69.46	$63.42
NGL ($/bbl)	$19.65	$30.91	$25.83	$35.03
Gas ($/mcf)	$2.48	$1.64	$1.80	$1.59
Realized Pricing (Excluding commodity contracts)
Oil ($/bbl)	$67.06	$42.58	$69.46	$67.48
NGL ($/bbl)	$18.03	$29.73	$24.31	$37.87
Gas ($/mcf)	$2.48	$1.64	$1.80	$1.57
Oil Price Benchmarks
West Texas Intermediate ("WTI") (US$/bbl)	$56.95	$61.05	$57.03	$64.98
Edmonton Par (C$/bbl)	$68.05	$42.71	$69.16	$69.35
Edmonton Par to WTI differential (US$/bbl)	$(5.40) $	(28.77)	$(4.90) $	(11.48)
Natural Gas Price Benchmarks
AECO gas (Cdn$/mcf)	$2.48	$1.59	$1.71	$1.51
Foreign Exchange
U.S./Canadian Dollar Exchange	0.76	0.76	0.75	0.77

Crude oil prices decreased by 12% for the year ended December 31, 2019, with the West Texas Intermediate ("WTI") reference price averaging US$57.03/bbl compared with US$64.98/bbl in the same period in 2018 due to weakening global economic conditions combined with slower growth in North American crude oil demand. Demand for crude oil is generally tied to global economic growth, but is also influenced by factors such as infrastructure, political instability, market uncertainty, weather conditions and government regulations.

Edmonton par differentials to WTI narrowed in the year ended December 31, 2019 when compared to the same period in 2018, moving from a US$11.48/bbl differential in 2018 to US$4.90/bbl in 2019. In the year ended December 31, 2019 the US/CDN foreign exchange rate was 0.75 compared to 0.77 for in 2018. The Edmonton par reference price is denominated in Canadian dollars so the change in the foreign exchange rate has increased the Edmonton par price relative to WTI. Edmonton par is the closest reference price point for Yangarra's oil and therefore is the closest proxy to realized pricing.

When compared to 2018, realized pricing on oil increased by 3%, excluding commodity contracts, and increased by 10% when the effects of commodity contracts are included.

When compared to 2018, liquids pricing decreased by 36%, excluding commodity contracts, and decreased by 26% when the effects of commodity contracts are included, due to extremely low butane pricing during 2018.

AECO natural gas prices increased from $1.51/mcf in 2018 to $1.71/mcf in 2019.

When compared to 2018, realized pricing on natural gas increased by 15%.

MANAGEMENT'S DISCUSSION AND ANALYSIS

For the year ended December 31, 2019 (000's, Canadian dollars, except per share and per unit amounts)

Results of Operations

Net petroleum and natural gas production, pricing and revenue

	2019	2018	Year Ended
	Q4	Q4	2019	2018
Daily production volumes
Natural gas (mcf/d)	41,483	30,573	39,663	22,993
Oil (bbl/d)	3,712	5,111	3,941	4,120
NGL's (bbl/d)	1,942	2,032	2,020	1,473
Combined (boe/d 6:1)	12,568	12,238	12,572	9,425
Revenue
Petroleum & natural gas sales - Gross	$35,990	$30,174	$143,976	$134,978
Realized gain (loss) on commodity contract settlement	290	1,104	1,122	(7,449)
Total sales	36,280	31,278	145,098	127,529
Royalty expense	(2,879)	(3,763)	(10,760)	(13,405)
Total Revenue - Net of royalties	$33,401	$27,515	$134,338	$114,124

Total sales increased by 14% in 2019 to $145.1 million from $127.5 million in 2018. The increase is attributable to:

• a 20% decrease in average product prices
• a 33% increase in production (on a boe basis)
• $1.1 million gain from commodity contract settlement in 2019 compared to $7.4 million loss from commodity contract settlement in 2018

The increased production can be attributed to the 2019 drilling program, 20 wells were drilled in the year.

Company Netbacks ($/boe)

	2019	2018	Year Ended
	Q4	Q4	2019	2018
Sales price	$31.13$	26.80	$31.37$	39.24
Royalty expense	(2.49)	(3.34)	(2.34)	(3.90)
Production costs	(6.19)	(5.57)	(5.76)	(5.82)
Transportation costs	(1.11)	(1.31)	(1.08)	(1.31)
Field operating netback	21.34	16.58	22.19	28.21
Realized gain (loss) on commodity contract settlement	0.25	0.98	0.24	(2.17)
Operating netback	21.59	17.56	22.43	26.04
G&A	(1.17)	(1.01)	(0.65)	(0.72)
Finance expenses	(1.53)	(1.72)	(1.68)	(1.45)
Depletion and depreciation	(8.33)	(7.61)	(8.37)	(9.26)
Asset Impairment	-	-	-	(0.23)
Accretion	(0.04)	(0.06)	(0.05)	(0.07)
Abandonment Expenses	(0.75)	-	(0.19)	-
Provision for Credit Losses	(0.57)	-	(0.14)	-
Stock-based compensation	(0.61)	(1.37)	(0.79)	(1.52)
Unrealized gain (loss) on financial instruments	(0.44)	10.94	(0.10)	1.10
Deferred income tax	(2.06)	(4.91)	(1.02)	(4.14)
Net Income netback	$6.09$	11.82	$9.44$	9.76

The overall average price earned by the Company was lower when compared to the year ended December 31, 2019 as NGL pricing was lower during the year and the gas weighting increased from 41% to 53%.

Operating netbacks decreased by 14% for the year ended December 31, 2019 due to increased gas weighting.

MANAGEMENT'S DISCUSSION AND ANALYSIS

For the year ended December 31, 2019 (000's, Canadian dollars, except per share and per unit amounts)

Royalty Expense

	2019		2018		Year Ended
		Q4		Q4		2019		2018
Royalty expense	$	2,879	$	3,763	$	10,760	$	13,405
Per boe	$	2.49	$	3.34	$	2.34	$	3.90
As a % of sales (including commodity contracts)		8%		12%		7%		11%
As a % of sales (excluding commodity contracts)		8%		12%		7%		10%

Royalties decreased to $10.8 million for the year ended December 31, 2019 or 7% as a percentage of sales, respectively (excluding commodity contact settlements). The decrease is a result of reduced over-riding royalties being paid to partners as those wells have declined in production and higher gas cost allowance credits.

Production and Transportation Costs

	2019	2018	Year Ended
	Q4	Q4	2019	2018
Production costs	$7,162	$6,267	$26,452	$20,018
Per boe	$6.19	$5.57	$5.76	$5.82
Transportation costs	$1,284	$1,475	$4,972	$4,512
Per boe	$1.11	$1.31	$1.08	$1.31
Combined ($/boe)	$7.30	$6.88	$6.85	$7.13

Production and transportation costs decreased by 4% on a per boe basis when compared to 2018 due to the significant infrastructure spending completed in the first quarter.

The Company's truck division has grown to 18 units. The Company has a full complement of company staffed crew trucks, pressure trucks, wire-line trucks and mechanical services which provide significant savings to operating costs. The Company's power requirements are internally generated by lease fuel fired generators or primary drivers which provide significant cost savings over grid supplied power.

Depletion and depreciation

	2019		2018			Year Ended
		Q4Q4			2019		2018
Depletion and depreciationPer boe	$$	9,6308.33	$$	8,5687.61	$$	38,4138.37	$$	31,8399.26

Depletion and depreciation increased in the year ended December 31, 2019 due to increases in production. On a per boe basis, the depletion decreased when compared 2018 due to lower finding and development costs in 2019.

MANAGEMENT'S DISCUSSION AND ANALYSIS

General and administrative expenses ("G&A")

	2019		2018	Year Ended
	Q4		Q4		2019		2018
Gross G&A expenses	$1,649	$	1,650	$	4,602	$	4,335
G&A recoveries	(292)		(517)		(1,624)		(1,853)
Net G&A expenses	$1,357	$	1,134	$	2,978	$	2,482
Per boe	$1.17	$	1.01	$	0.65	$	0.72

G&A increased by 20% on a net basis and increased by 6% on a gross basis when compared to 2018 due increased activity. G&A decreased by 10% on a boe basis due to increased production in 2019 with limited changes to staff.

Other expenses

	2019	2018		Year Ended
	Q4	Q4		2019		2018
Finance
Interest and Finance Expense	$1,780	$1,476	$	7,246	$	4,717
Interest on lease obligations	18	-		313		-
Realized gain on interest rate contract settlement	30	(2)		35		62
Change in fair value of interest rate contracts	(453)	401		(83)		(27)
Accretion of decommissioning liability	41	66		211		227
Accretion of debt issue costs	41	64		207		249
Foreign exchange transactions	358	-		-		-
	$1,815	$2,005	$	7,929	$	5,227
Share-based compensation	$700	$1,545	$	3,630	$	5,219

Interest and financing fees for the year ended December 31, 2019 include interest on the revolving operating demand loan (the average amount drawn in 2019 was $162 million), servicing charges on the demand loan and the change in fair value of the interest rate contracts. Included in the financing expense in the year ended December 31, 2019 were the setup fees and legal costs related to the increased $225 million syndicated credit facility.

The Company had the following interest rate contracts in place at December 31, 2019:

• Pay a floating rate to receive a 1.945% fixed rate on $10 million (June 2018-November 2023)
• Pay a floating rate to receive a 1.935% fixed rate on $10 million (May 2018-November 2023)
• Pay a floating rate to receive a 1.700% fixed rate on $20 million (August 2019-August 2022)
• Pay a floating rate to receive a 1.680% fixed rate on $20 million (August 2019-August 2022)

The fair value on the interest rate contracts was $366 as at December 31, 2019 (December 31, 2018 – $283).

During the year ended December 31, 2019, the Company granted options to purchase 500 common shares, the options will vest equally over three years with the first tranche vesting one year after the grant date. The fair value of the options was estimated at $455 ($0.91 per option) using the Black-Scholes option pricing model.

The sensitivity of the fair value of a 10 percent change in foreign exchange rates would have an immaterial impact on the consolidated statements of income and comprehensive income.

MANAGEMENT'S DISCUSSION AND ANALYSIS

For the year ended December 31, 2019 (000's, Canadian dollars, except per share and per unit amounts)

Deferred Taxes

	20192018		Year Ended
	Q4		Q4		2019		2018
Deferred income tax expense	$2,385	$	5,527	$	4,665	$	14,229

Yangarra did not pay income taxes in 2019 and does not expect to pay income taxes in 2020 as it has sufficient tax pools to cover taxable income. The deferred taxes reduced when compared to 2018 due to the changes in corporate tax rates in Alberta.

		Year Ended
	Rate %	2019		2018
Canadian oil and gas property expenses	10	$	28,067	$	25,081
Canadian development expenses	30		199,458		184,868
Canadian exploration expenses	100		19,168		18,679
Undepreciated capital costs	10-30		62,718		48,333
Non-capital losses (various expiry dates)	100		1,262		1,262
Share issuance costs	5 Years		161		725
		$	310,834	$	278,948

Commodity price risk contracts

	2019		2018	Year Ended
	Q4		Q4		2019		2018
Realized gain (loss) on commodity contract settlement	$290	$	1,104	$	1,122	$	(7,449)
Change in fair value of commodity contracts	(512)		12,318		(450)		3,774
	$(222) $		13,422	$	672	$	(3,675)

MANAGEMENT'S DISCUSSION AND ANALYSIS

For the year ended December 31, 2019 (000's, Canadian dollars, except per share and per unit amounts)

As at December 31, 2019 the Company was committed to the following commodity price risk contracts in place:

Year	Volume	Term	Reference	Type	Strike Price
Oil
2020	425bbl/d	Jan to Dec	US$ WTI	Sold Call	USD$ 65.00/bbl
Propane
2020	100 bbl/d	Jan to Dec	Conway -C3 to	Basis Swap	Minus USD
			Mont Belvieu C3		0.02875/Gallon
2020	100 bbl/d	Jan to Dec	Conway -C3 to	Basis Swap	Minus USD
			Mont Belvieu C3		0.02/Gallon

No new commodity contracts were entered after December 31, 2019.

As the Company had a limited number of derivatives in place as at December 31, 2019 the sensitivity of the fair value of a 10 percent volatility in commodity prices would have an immaterial impact on unrealized gains (losses) reported in the consolidated statement of income and comprehensive income.

Liquidity and Capital Resources

The following table summarizes the change in working capital during the year ended December 31, 2019 and year ended December 31, 2018:

	Year ended	Year ended
	December 31, 2019	December 31, 2018
Adjusted Net Debt - beginning of period	$(155,882)	$(93,533)
Funds flow from operations	92,235	82,334
Additions to property and equipment	(115,276)	(141,060)
Decommissioning costs incurred	(966)	(333)
Additions to E&E Assets	(5,723)	(9,773)
Issuance of shares	41	6,776
Other	(2,141)	(293)
Adjusted Net Debt - end of period	$(187,712)	$(155,882)
Credit facility limit	$225,000	$175,000

As at December 31, 2019, the maximum amount available under the syndicated credit facility was $225 million (December 31, 2018 – $175 million) comprised of a $200 million (December 31, 2018 – $160 million) extendible revolving term credit facility and a $25 million (December 31, 2018 – $15 million) operating facility. The amount available under these facilities is re-determined at least twice a year and is primarily based on the Company's oil and gas reserves, the lending institution's forecast commodity prices, the current economic environment and other factors as determined by the syndicate of lending institutions (the "Borrowing Base"). If the total advances made under the credit facilities are greater than the redetermined Borrowing Base, the Company has 60 days to repay any shortfall. The maturity date of the facility is May 29, 2021 (the "Maturity Date") and the next Borrowing Base review is scheduled for May 30, 2020. The Maturity Date may be extended for 364-day periods pursuant to delivery of a request for extension by the Company within certain time periods specified in the syndicated credit facility agreement.

YANGARRA RESOURCES LTD. MANAGEMENT'S DISCUSSION AND ANALYSIS

For the year ended December 31, 2019 (000's, Canadian dollars, except per share and per unit amounts)

As at December 31, 2019, the $190,291 (December 31, 2018 – $134,489) reported amount of bank debt was comprised of $15,767 (December 31, 2018 – $80) drawn on the operating facility, $174,766 (December 31, 2018 – $134,507) drawn on the extendible revolving term credit facility and net of unamortized transaction costs of $242 (December 31, 2018 – $98).

The Company is subject to a single financial covenant requiring an adjusted working capital ratio above 1:1 (current assets plus the undrawn availability under the revolving facility, divided by the current liabilities less the drawn portion of the revolving facility and excluding unrealized commodity contracts). The Company was in compliance with this covenant as at December 31, 2019 and December 31, 2018. The facility is secured by a general security agreement over all assets of the Company.

The total standby fees range, depending on the debt to EBITDA ratio, between 50 bps to 250 bps on bank prime borrowings and between 150 bps and 350 bps on bankers' acceptances. The undrawn portion of the credit facility is subject to a standby fee in the range of 33.75 bps to 78.75 bps. During the year ended December 31, 2019, the weighted average effective interest rate for the bank debt was approximately 4.21% (2018 – 3.97%).

The Company intends to fund the 2020 budget with cash flow from operations and the availability on the revolving operating demand loan.

Capital Spending

	2019	2018	Year Ended
Cash additions	Q4	Q4	2019		2018
Land, acquisitions and lease rentals	$38	$340	$344	$	569
Drilling and completion	16,997	22,299	83,060		106,855
Geological and geophysical	447	412	1,041		913
Equipment	2,503	11,991	28,977		32,337
Other asset additions	193	214	979		385
	$20,178	$35,256	$114,401	$	141,060
Exploration & evaluation assets	$480	$1,690	$5,723	$	9,773

Capital spending is summarized as follows:

The Company drilled 20 wells during the year and constructed a 100% owned gas plant, doubled the capacity on one of its existing gas plants and added a new core area.

Outlook

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.

Decommissioning Liabilities

As at December 31, 2019, the undiscounted decommissioning obligation associated with the Company's existing properties was estimated to be $17,200 for which $14,838 has been recorded using a discount rate of 1.37% - 1.92%, an inflation rate of 2% and an estimated weighted average timing of cash flows of 8.8 years.

Off Balance Sheet Arrangements

There were no off-balance sheet arrangements.

MANAGEMENT'S DISCUSSION AND ANALYSIS

For the year ended December 31, 2019 (000's, Canadian dollars, except per share and per unit amounts)

Share Capital

Details of changes in the number of outstanding equity instruments are detailed in the following table:

	Shares	Options
Balance - December 31, 2018	85,341	8,324
Grant of options	-	500
Forfeited options	-	(287)
Exercise of options	39	(39)
Balance - December 31, 2019	85,380	8,498

Contingency

Contractual Obligations and Commitments

				Common	Stock
	Shares			Options
Balance - December 31, 2018				85,341	8,324
Grant of options				-	500
Forfeited options				-	(287)
Exercise of options				39	(39)
Balance - December 31, 2019				85,380	8,498
Contingency
In the normal conduct of operations, there are other pending claims by and against the Company. Litigationis subject to many uncertainties, and the outcome of individual matters is not predictable with assurance.In the opinion of management, based on thedetermination of these other litigations will not materially affect the Company'sof operations.		advice and information provided by its legal counsel, the final		financial position or results
Contractual Obligations and Commitments
As at December 31, 2019, the contractual maturities of the Company's obligations are as follows:
	CarryingAmount	ContractualCash Flows	Less than 1year	1-2 Years	2-5Years	Morethan 5years
Accounts payable and
accrued liabilities	$25,869	$25,869	$25,869	$-	$-	$-
Bank debt	190,291	190,533	-	190,533	-	-
Lease liabilities	5,194	6,239	1,624	1,564	2,970	84
Other long-term liabilities	84	84	47	37	-	-
Commodity contracts	237	237	237	-	-	-
	$221,675	$222,962	$27,777	$192,134	$2,970	$84
Financial Instruments and Financial Risk Management
The Company's risk management policies are established to identify and analyze the risks faced by theCompany, to set appropriate risk limits and controls, and to monitor risks and adherence to marketconditions and the Company's activities. The Company has exposure to credit risk, liquidity risk andmarket risk as a result of its use of financial instruments.Company's exposure to each of the above risks and the Company's objectives, policies and processes formeasuring and managing these risks.financial statements. The Board of Directors has overall responsibility for the establishment and oversight		Further quantitative disclosures are included throughout these	This note presents information about the

Financial Instruments and Financial Risk Management

of the Company's risk management framework. The Board has implemented and monitors compliance with the risk management policies as set out herein:

a. Credit risk

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations. A substantial portion of the Company's accounts receivable are with natural gas and liquids marketers and partners on joint operations in the oil and gas industry and are subject to normal industry credit risks.

Purchasers of the Company's natural gas and liquids are subject to credit review to minimize the risk of non-payment. As at December 31, 2019, the maximum credit exposure is the carrying amount of the accounts receivable of $24,591 (December 31, 2018 – $26,203). The maximum exposure to credit risk for accounts receivable as at December 31, 2019 and December 31, 2018 by type of customer was:

	December 31, 2019	December 31, 2018
Natural gas and liquids marketers	$12,406	$8,441
Partners on joint operations	9,530	11,170
Realized commodity contracts	97	2,156
Provision for expected credit losses	(664)	–
Other	3,222	4,436
	$24,591	$26,203

Receivables from natural gas and liquids marketers are typically collected on the 25th day of the month following production. The Company has mitigated the credit risk associated with the natural gas and liquids marketer through a security arrangement with Computershare. The Company historically has not experienced any significant collection issues with its natural gas and liquids marketers. The majority of the revenue accruals and receivables from natural gas and liquids marketers were received in January 2020.

Receivables from partners on joint operations are typically collected within one to three months of the bill being issued to the partner. The Company mitigates the risk from receivables from partners on joint operations by obtaining partner approval of capital expenditures prior to starting a project. However, the receivables are from participants in the petroleum and natural gas sector, and collection is dependent on typical industry factors such as commodity price fluctuations, escalating costs and the risk of unsuccessful drilling. Further risk exists with partners on joint operations as disagreements occasionally arise which increases the potential for non-collection. For properties that are operated by the Company, production can be withheld from partners on joint operations who are in default of amounts owing. In addition, the Company often has offsetting amounts payable to partners on joint operations from which it can net receivable balances.

As at December 31, 2019 and December 31, 2018, the Company considers its receivables to be aged as follows:

	December 31, 2019	December 31, 2018
Under 30 days	$14,273	$14,196
30 to 60 days	187	515
60 to 90 days	358	2,846
Over 90 days	9,773	8,646
	$24,591	$26,203

97% (2018 – 86%) of the over 90-day receivables are made up of four (2018 – two) industry partners. The Company has performed an analysis of each partner's financial situation and have determined they have the ability to pay. Included in the over 90-day receivables are balances with a significant portion in dispute with four of the industry partners. The Company recorded a provision of expected credit losses during the year ended December 31, 2019 for $664 (2018 - $nil).

Risk management assets and liabilities consist of commodity contracts used to manage the Company's exposure to fluctuations in commodity prices. The Company manages the credit risk exposure related to risk management contracts by selecting investment grade counterparties and by not entering into contracts for trading or speculative purposes. During 2019 and 2018, the Company did not experience any collection issues with risk management contracts. The Company typically does not obtain or post collateral or security from its oil and natural gas marketers or financial institution counterparties. The carrying amounts of accounts receivable represent the maximum credit exposure

b. Liquidity risk

Liquidity risk is the risk that the Company will incur difficulties meeting its financial obligations as they are due. The Company's approach to managing liquidity is to ensure, as far as possible, that it will have sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions without incurring unacceptable losses or risking harm to the Company's reputation. The Company prepares annual capital expenditure budgets, which are regularly monitored and updated as considered necessary. The Company uses authorizations for expenditures on both operated and non-operated projects to further manage capital expenditures.

To facilitate the capital expenditure program, the Company has a credit facility agreement which is regularly reviewed by the lender. The Company monitors its total debt position monthly. The Company also attempts to match its payment cycle with collection of petroleum and natural gas revenues on the 25th of each month. The Company anticipates it will have adequate liquidity to fund its financial liabilities through its future cash flows and availability on bank facilities. The Company's financial liabilities are comprised of accounts payable and accrued liabilities, interest rate contracts, commodity contracts, other long-term liabilities and bank debt, which are classified as current or non-current on the consolidated statement of financial position based on their maturity dates.

The Company will fund the 2020 budget with cash flow from operations and availability on the credit facility.

c. Market risk

Market risk consists of interest rate risk, currency risk and commodity price risk. The objective of market risk management is to manage and control market risk exposures within acceptable limits, while maximizing returns. The Company may use both financial derivatives and physical delivery sales contracts to manage market risks. All such transactions are conducted in accordance with a risk management policy as set out herein:

i. Interest rate risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Company is exposed to interest rate fluctuations on its bank debt which bears interest at a floating rate and to mitigate this risk, the Company has entered into interest rate contracts. For the year ended December 31, 2019, if interest rates (including the effect of the interest rate contract) had been 1% lower with all other variables held constant, net income for the period would have been $1,624 (2018 - $1,097) higher, due to lower interest expense. An equal and opposite impact would have occurred had interest rates been higher by the same amount.

ii. Foreign currency exchange risk

Foreign currency exchange rate risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in foreign exchange rates. All of the Company's petroleum and natural gas sales are denominated in Canadian dollars, however, the underlying market prices in Canada for petroleum and natural gas are impacted by changes in the exchange rate between the Canadian and United States dollar.

iii. Commodity price risk

Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for petroleum and natural gas are impacted by world economic events that dictate the levels of supply and demand as well as the relationship between the Canadian dollar and United States dollar, as outlined above

Capital Resources

The Company's objective when managing capital is to maintain a flexible capital structure which will allow it to execute its capital expenditure program, which includes expenditures in oil and gas activities which may or may not be successful. Therefore, the Company monitors the level of risk incurred in its capital expenditures to balance the proportion of debt and equity in its capital structure.

The Company considers its capital structure to include shareholders equity and debt:

	December 31, 2019	December 31,2018
Shareholders' equity	$303,643	$255,336
Bank debt	$190,291	$134,489

The Company monitors capital based on annual cash from operations before changes in non-cash working capital and capital expenditure budgets, which are updated as necessary and are reviewed and periodically approved by the Board of Directors.

The Company manages its capital structure and makes adjustments by continually monitoring its business conditions including the current economic conditions, the risk characteristics of the Company's petroleum and natural gas assets, the depth of its investment opportunities, current and forecasted net debt levels, current and forecasted commodity prices and other facts that influence commodity prices and funds from operations such as quality and basis differentials, royalties, operating costs and transportation costs.

YANGARRA RESOURCES LTD. MANAGEMENT'S DISCUSSION AND ANALYSIS For the year ended December 31, 2019 (000's, Canadian dollars, except per share and per unit amounts)

In order to maintain or adjust the capital structure, the Company considers its forecasted cash from operations before changes in non-cash working capital while attempting to finance an acceptable capital expenditure program including acquisition opportunities, the current level of bank debt available from the Company's lender, the level of bank debt that may be attainable from its lender as a result of petroleum and natural gas reserve growth, the availability of other sources of debt with different characteristics than existing debt, the sale of assets, limiting the size of the capital expenditure program and the issue of new equity if available on favorable terms. At December 31, 2019, the Company's capital structure was subject to the banking covenants disclosed in the financial statements. No changes were made to the capital policy in 2019.

Selected Quarterly Financial Information

	2019	2019	2019	2019
	Q4($)	Q3($)	Q2($)	Q1($)
Petroleum &natural gassales	35,990	31,606	36,473	39,907
Net income	7,020	6,560	18,219	11,514
Net income per share –basic	0.08	0.08	0.21	0.13
Net income per share–diluted	0.08	0.08	0.21	0.13
Fundsflow from operations	21,005	19,055	24,445	27,731
Fundsflow from operationsper share –basic	0.25	0.22	0.29	0.32
Fundsflow from operationsper share –diluted	0.25	0.22	0.28	0.32
Capital expenditures	20,660	26,603	13,813	59,048
	2018	2018	2018	2018
	Q4($)	Q3($)	Q2($)	Q1($)
Petroleum &natural gassales	30,174	45,132	29,922	29,750
Net income (loss)	13,315	12,947	1,646	5,658
Net income (loss) per share –basic	0.16	0.15	0.02	0.07
Net income (loss)per share–diluted	0.15	0.15	0.02	0.07
Fundsflow from operations	17,167	29,524	17,005	18,638
Fundsflow from operationsper share –basic	0.20	0.35	0.20	0.22
Fundsflow from operationsper share –diluted	0.20	0.34	0.20	0.22
Capital expenditures	36,946	50,044	27,482	36,360

Fourth Quarter activities

Fluctuations in quarterly revenues, net income and funds flow from operations over the last eight quarters are due primarily to the volatility in commodity prices and changes in sales volumes due to production growth and declines tied to the timing of drilling activity. The Company has focused capital expenditures on drilling and completions. Production has grown steadily, with significant increases starting with the fourth quarter of 2016 due to a positive change in the productivity of new wells.

Business Risks and Uncertainties

The Company is exposed to several operational risks inherent in exploring, developing, producing and marketing crude oil and natural gas. These inherent risks include: economic risk of finding and producing reserves at a reasonable cost; financial risk of marketing reserves at an acceptable price given current market

YANGARRA RESOURCES LTD. MANAGEMENT'S DISCUSSION AND ANALYSIS For the year ended December 31, 2019 (000's, Canadian dollars, except per share and per unit amounts)

conditions; cost of capital risk associated with securing the needed capital to carry out the Company's operations; risk of environment impact; and credit risk of non-payment for sales contracts and joint venture partners. Other than the risks described herein (including the risks and uncertainties listed in the Forward-Looking Statements section in this MD&A) the Company is also subject to the risk factors set forth in the most recently filed AIF of the Company available on SEDAR which can be accessed at www.sedar.com

The Company attempts to control operating risks by maintaining a disciplined approach to implementation of its exploration and development programs. Exploration risks are managed by hiring experienced technical professionals and by concentrating the exploration activity on specific core regions that have multi-zone potential where the Company has experience and expertise. The Company also generates internal prospects and participates in projects where ownership interest is considered sufficient to minimize risk. Operational control allows the Company to manage costs, timing and sales of production and to ensure new production is brought on-stream in a timely manner. The Company maintains a comprehensive insurance program to reduce risk to an acceptable level and to protect it against significant losses.

Environmental Risks

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Compliance with such legislation can require significant expenditures and a breach could result in the imposition of fines and penalties, some of which could be material. Senior management continually assesses new and existing regulatory requirements and environmental risks and determines the impact these risks might have on the Company, as well as the appropriate actions necessary to manage those risks. These assessments and the resulting policy decisions are discussed quarterly with the Board of Directors which evaluates the performance and effectiveness of the Company's environmental policies and programs.

The Company's environmental responsibilities includes removing property, plant and equipment as well as reclaiming land and property to its original state, subsequent to the completion of oil and natural gas extraction activities. This requirement results in an asset retirement obligation that provides current recognition of estimated expenditures that will be incurred in the future. The Company's decommissioning liabilities are discussed in further detail under "Critical Accounting Estimates" below, as well as in note 6 to the Company's Consolidated Financial Statements.

Disclosure Controls and Procedures and Internal Controls over Financial Reporting

As at December 31, 2019, an evaluation of the effectiveness of the Company's disclosure controls and procedures, as defined under the rules adopted by the Canadian securities regulatory authorities, was carried out under the supervision and with the participation of Management, including the President and Chief Executive Officer ("CEO"), and the Chief Financial Officer ("CFO"). Based on this evaluation, the CEO and CFO concluded that, as at December 31, 2019, the design and operation of the Company's disclosure controls and procedures were effective in meeting all regulatory filing requirements.

Internal control over financial reporting means a process designed by, or under the supervision of, an issuer's certifying officers, and effected by the issuer's board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer's Generally Accepted Accounting Procedures ("GAAP") and includes those policies and procedures that:

(a) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the issuer;

(b) are designed to provide reasonable assurance that transactions are recorded as necessary to permit

For the year ended December 31, 2019 (000's, Canadian dollars, except per share and per unit amounts)

preparation of financial statements in accordance with the issuer's GAAP, and that receipts and expenditures of the issuer are being made only in accordance with authorizations of management and directors of the issuer; and

(c) are designed to provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the issuer's assets that could have a material effect on the annual financial statements or interim financial reports;

Management is responsible for establishing and maintaining adequate internal controls over financial reporting.

Management has conducted an evaluation of its internal controls over financial reporting and determined that at December 31, 2019 the controls were effective to provide reasonable assurance regarding the reliability of financial reporting, and the preparation of financial statements for external reporting purposes. In May 2013, the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") issued an updated Internal Control-Integrated Framework ("2013 Framework") replacing the Internal Control - Integrated Framework (1992). The control framework Yangarra's officers used to design the Company's ICFR is the 2013 Framework.

During the period beginning on October 1, 2019 and ending on December 31, 2019, there were no material changes to the Company's internal controls over financial reporting, and the CEO and CFO have filed certifications with the Canadian securities regulators regarding the Company's 2019 public filing documents.

New Accounting Standards

Yangarra adopted IFRS 16 on January 1, 2019 using the modified retrospective approach. The modified retrospective approach does not require restatement of prior period financial information as it recognizes the cumulative effect as an adjustment to opening retained earnings and applies the standard prospectively.

On adoption of IFRS 16, Yangarra recognized lease obligations of $3,321 in relation to all lease arrangements measured at the present value of the remaining lease payments from commitments disclosed as at December 31, 2018, adjusted by commitments in relation to arrangements not containing leases, shortterm and low-value leases, and discounted using the incremental borrowing rate. The associated right-ofuse assets were measured at $3,321 with no impact on retained earnings. No impairments were recognized for the right-of-use assets upon adoption.

Critical Accounting Estimates

The preparation of the consolidated financial statements in accordance with IFRS requires management to make judgments, estimates and assumptions that affect reported amounts and presentation of assets, liabilities, revenues, expenses and disclosures of contingencies and commitments. Such estimates primarily relate to unsettled transactions and events at the statement of financial position date which are based on information available to management at each financial statement date. Actual results could differ from those estimated. Judgments, estimates and assumptions are continuously evaluated and are based on management's experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances.

Critical judgments in applying accounting policies

Business combinations

Determination of the fair value of acquired assets and liabilities in a business combination requires management to make assumptions and estimates about future events. The fair value of crude oil and natural gas interests is estimated with reference to the discounted cash flows expected to be derived from crude oil and natural gas production. These assumptions and estimates generally require judgment and include

YANGARRA RESOURCES LTD. MANAGEMENT'S DISCUSSION AND ANALYSIS

For the year ended December 31, 2019 (000's, Canadian dollars, except per share and per unit amounts)

estimates of reserves acquired, liabilities assumed, forecast commodity prices, expected production volumes, future development and operating costs, income taxes, and discount rates. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to the net assets acquired, goodwill or gain on business combination.

CGU Determination

The Company's assets are aggregated into CGUs based on their ability to generate largely independent cash flows and are used for impairment testing. CGUs are determined by similar geological structure, shared infrastructure and geographical proximity.

Impairment indicator assessment

The Company assesses its P&E and E&E assets for possible impairment if there are events or changes in circumstances that indicate the carrying values of the assets may not be recoverable. Such indicators include changes in the Company's business plans, changes in commodity prices, evidence of physical damage and significant downward revisions to estimated recoverable volumes or increases in estimated future development expenditures.

Contingencies

By their nature, contingencies will only be resolved when one or more of the future events occur or fail to occur. The assessment of contingencies inherently involves the estimates of the outcome of future events.

Key sources of estimation uncertainty

Reserves

Reserves are used in the unit of production calculation for depletion and depreciation as well as impairment analysis. The quantity of reserves is subject to a number of estimates and projections including assessment of engineering data, projected future rates of production, commodity prices, regulatory changes, operating costs and sustaining capital expenditures. These estimates and projections are uncertain as the Company does not have a long commercial production history to assist in the development of these forward-looking estimates. However, all reserve and associated financial information is evaluated and reported on by a firm of qualified independent reserve evaluators in accordance with the standards prescribed by applicable securities regulators. The calculation of future cash flows based on these reserves is dependent on a number of estimates including: production volumes, facility performance, commodity prices, and royalties, operating costs, sustaining capital and tax rates. The price used in the Company's assessment of future cash flows is based on the Company's independent evaluator's estimate of future prices and evaluated for reasonability by the Company against other available information. The Company believes these prices are reasonable estimates for a long-term outlook.

Decommissioning liabilities

The Company measures decommissioning liabilities at each financial statement date. The estimate is based on the Company's share of costs to reclaim the assets and certain facilities. To determine the future value of the liability, estimates of the amount, timing and inflation of the associated abandonment costs are made. The present value of the cost is recorded as the decommissioning liability using a risk-free discount rate. Due to the long-term nature of current and future project developments, abandonment costs will be incurred many years in the future. As a result of these factors, different estimates could be used for such abandonment costs and the associated timing. Assumptions of higher future abandonment costs, regulatory changes, higher inflation, lower risk-free rates or an assumption of earlier or specified timing of abandonment would cause the decommissioning liability of the corresponding asset to increase. These changes would also cause future accretion expenses to increase and future income to decrease.

MANAGEMENT'S DISCUSSION AND ANALYSIS

Impairment Estimate

The assessment for impairment for P&E and E&E assets involves comparing the carrying value of the CGU with the higher of value in use calculations and fair value less costs to sell. Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation on operating expenses, discount rates, production profiles and the outlook for regional supply-and-demand conditions for crude oil, natural gas and liquids. Impairment is recognized in the statement of income (loss) and comprehensive income (loss) in the period in which carrying amount exceeded the recoverable amount.

Accounts Receivable

Significant estimates are included in accounts receivable in terms of collectability as a significant portion of the balance is in dispute, the outcome for which is uncertain and could result in a material adjustment to the financial statements.

Deferred taxes

Deferred income tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amount and the tax basis of assets and liabilities. An estimate is required for both the timing and corresponding tax rate for this reversal. Should these estimates change, it may impact the measurement of the Company's assets or liabilities as well as deferred tax recovery or expense recognized to earnings. Where unfavorable evidence exists, additional considerations and evidence for recognition of deferred tax assets is required. The Company has applied management's judgment and evaluated applicable factors necessary in making this determination and has concluded that the positive evidence in consideration of the estimated future cash flows based on reserve reports from the Company's independent engineers, does not sufficiently outweigh negative factors. The Company only recognizes deferred tax assets arising from unused tax losses to the extent that the Company has sufficient taxable temporary differences or it is probable that sufficient taxable profit will be available against which the unused tax losses can be utilized.

Contingencies

When recognized, management makes its best estimate with respect to future cash outflows.

Other areas of estimates

The recognition of amounts in relation to stock-based compensation requires estimates related to valuation of stock options at the time of issuance including share price, risk free rate, volatility, expected life and dividend yield. The fair value of commodity contracts is calculated using valuation models that require estimates as to future market prices expected interest rates and expected volatility in these variables. By their nature, these estimates are subject to measurement uncertainty and the effect of changes in such estimates on the financial statements for current and future periods could be significant.