Whitecap Resources Inc. — Management Reports 2020

Feb 27, 2020

MANAGEMENT’S DISCUSSION AND ANALYSIS

The following management’s discussion and analysis (“MD&A”) of financial condition and results of operations for Whitecap Resources Inc. (the “Company” or “Whitecap”) is dated February 26, 2020 and should be read in conjunction with the Company’s audited annual consolidated financial statements and related notes for the year ended December 31, 2019 and our Annual Information Form for the year ended December 31, 2019. These audited annual consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”), in Canadian dollars, except where indicated otherwise. Accounting policies adopted by the Company are set out in the notes to the audited annual consolidated financial statements for the year ended December 31, 2019. The MD&A should also be read in conjunction with Whitecap’s disclosure under “Non-GAAP Measures” and “Forward-Looking Information and Statements” below. Additional information respecting Whitecap, is available on SEDAR at www.sedar.com and on our website at www.wcap.ca.

The audited annual consolidated financial statements of Whitecap have been prepared by management and approved by the Company’s Board of Directors.

DESCRIPTION OF BUSINESS

Whitecap is a Calgary based oil and gas company that is engaged in the business of acquiring, developing and holding interests in petroleum and natural gas properties and assets. Whitecap's common shares are traded on the Toronto Stock Exchange (“TSX”) under the symbol WCP.

2019 ANNUAL FINANCIAL AND OPERATIONAL RESULTS

Production

Whitecap’s average production volumes and commodity splits were as follows:

	Three	months ended		Year ended
		December 31		December 31
	2019	2018	2019	2018
Crude oil (bbls/d)(1)	58,044	57,072	55,413	58,511
NGLs (bbls/d)	4,805	4,656	4,503	4,397
Natural gas (Mcf/d)(1)	70,811	68,739	66,801	69,042
Total(boe/d)(2)	74,651	73,185	71,050	74,415

Notes:

(1) References to crude oil or natural gas production in the above table and elsewhere in this MD&A refer to the light and medium crude oil and conventional natural gas, respectively, product types as defined in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities.

(2) Disclosure of production on a per boe basis in this MD&A consists of the constituent product types and their respective quantities disclosed in this table.

Exhibit 1

Production Split Three Months Ended December 31, 2019

Production Split Twelve Months Ended December 31, 2019

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16%
6%
78%
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Crude oil NGLs Natural gas

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16%
6%
78%
Crude oil NGLs Natural gas
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Average production volumes increased two percent to 74,651 boe/d in the fourth quarter of 2019 from 73,185 boe/d in the fourth quarter of 2018. The increase in production volumes was primarily attributable to the timing of the 2019 capital program compared to the 2018 program.

Average production volumes decreased five percent to 71,050 boe/d in 2019 from 74,415 boe/d in 2018. With the volatility in both West Texas Intermediate and Canadian oil price differentials late in 2018, the Company elected to take a cautious approach to 2019 by reducing capital spending compared to the prior year with the focus on further strengthening the balance sheet. On December 18, 2018, Whitecap released its 2019 capital budget of $425 - $475 million with expected average production of 70,000 - 72,000 boe/d. On August 26, 2019, Whitecap announced a reduced 2019 capital expenditure program of $400 million while still targeting 2019 average production of 70,000 - 72,000 boe/d. Copies of the press releases are available on SEDAR at www.sedar.com. The execution of the capital program was successful, drilling 193 (166.3 net) wells for the year ended December 31, 2019 compared to 261 (216.3 net) for the year ended December 31, 2018.

Our crude oil and NGLs weighting in the quarter and year ended December 31, 2019 is generally consistent compared to the same periods in 2018.

Petroleum and Natural Gas Sales

A breakdown of petroleum and natural gas revenues is as follows:

	Three	months ended		Year ended
		December 31		December 31
($000s)	2019	2018	2019	2018
Crude oil	343,985	247,927	1,337,035	1,419,363
NGLs	7,763	12,644	33,832	57,617
Natural gas	17,442	11,826	47,609	42,865
Petroleum and natural gas revenues	369,190	272,397	1,418,476	1,519,845
Tariffs	(2,885)	(4,038)	(12,459)	(19,524)
Processing & other income	3,457	2,954	17,869	12,210
Blending revenue	7,214	7,598	30,353	12,768
Petroleum and naturalgas sales	376,976	278,911	1,454,239	1,525,299

Exhibit 2

Petroleum and Natural Gas Revenues Three Months Ended December 31, 2019

Petroleum and Natural Gas Revenues Twelve Months Ended December 31, 2019

2%[5%] 3%[3%] 93% 94% Crude oil NGLs Natural gas Crude oil NGLs Natural gas

Petroleum and natural gas revenues in the fourth quarter of 2019 increased 36 percent to $369.2 million from $272.4 million in the fourth quarter of 2018. The increase of $96.8 million consists of $91.8 million attributed to higher realized prices and $5.0 million attributed to higher production volumes.

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Petroleum and natural gas revenues in 2019 decreased seven percent to $1,418.5 million from $1,519.8 million in 2018. The decrease of $101.3 million consists of $75.1 million attributed to lower production volumes and $26.2 million attributed to lower realized prices.

Benchmark and Realized Prices

Average benchmark and realized prices are as follows:

	Three	months ended		Year ended
		December 31		December 31
	2019	2018	2019	2018
Average benchmark prices
WTI (US$/bbl) (1)	56.96	58.81	57.03	64.77
Exchange rate (US$/C$)	1.32	1.32	1.33	1.30
WTI (C$/bbl)	75.19	77.56	75.69	83.90
MSW Par at Edmonton ($/bbl) (2)	67.99	42.75	69.05	69.36
Fosterton Par at Regina ($/bbl)	61.27	44.64	64.95	60.22
Midale Par at Cromer ($/bbl)	72.44	61.72	74.38	75.73
AECO natural gas ($/Mcf) (3)	2.48	1.56	1.76	1.50
Average realized prices (4)
Crude oil ($/bbl)	64.42	47.22	66.11	66.46
NGLs ($/bbl)	17.56	29.52	20.58	35.90
Natural gas ($/Mcf)	2.68	1.87	1.95	1.70
Combined($/boe)	53.76	40.46	54.70	55.96

Notes:

(1) WTI represents the calendar month average of West Texas Intermediate oil.

(2) Mixed Sweet Blend (“MSW”).

(3) AECO represents the AECO 5A Daily Index price.

(4) Prior to the impact of hedging activities and tariffs.

Whitecap’s weighted average realized price prior to the impact of hedging activities and tariffs increased 33 percent to $53.76 per boe in the fourth quarter of 2019 compared to $40.46 per boe in the fourth quarter of 2018. Whitecap’s weighted average realized price prior to the impact of hedging activities and tariffs decreased two percent to $54.70 per boe in 2019 compared to $55.96 per boe in 2018.

The WTI price decreased by three percent to average US$56.96 per barrel in the fourth quarter of 2019 compared to US$58.81 per barrel in the fourth quarter of 2018. The WTI price decreased by 12 percent to average US$57.03 per barrel in 2019 compared to US$64.77 in 2018. The decreases are primarily due to continued growth in US oil production. US oil production increased by an average of 1.3 million barrels per day or 11 percent in the fourth quarter of 2019 compared to the fourth quarter of 2018. In 2019, US oil production increased by an average of 1.5 million barrels per day, or 14 percent compared 2018.

The MSW par oil prices increased by 59 percent to average $67.99 per barrel in the fourth quarter of 2019 compared to $42.75 per barrel in the fourth quarter of 2018. The increase is primarily due to stronger MSW differentials to WTI in the fourth quarter of 2019 compared to the fourth quarter of 2018 when the MSW differentials were unusually high due to excess supply, high Canadian crude oil storage inventories and ongoing transportation constraints. On January 1, 2019, the Alberta Government implemented policies to curtail Alberta crude oil production in order to reduce excess supply and high crude oil storage levels. This policy continued to support oil price differentials through 2019. MSW differentials were further supported by slightly lower pipeline constraints as key export pipelines added incremental capacity in the fourth quarter of 2019. MSW par oil prices remained consistent averaging $69.05 per barrel in 2019 compared to $69.36 per barrel in 2018.

The Company’s realized crude oil price in southwest Saskatchewan is based on Fosterton par prices at Regina. Fosterton oil price increased 37 percent to average $61.27 per barrel in the fourth quarter of 2019 compared to $44.64 per barrel in the fourth quarter of 2018. Fosterton par oil prices increased by eight percent to average $64.95 per barrel in 2019 compared to $60.22 per barrel in 2018. The increases are primarily due to stronger Fosterton differentials to WTI for the quarter and year ended December 31, 2019

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compared to the same periods in 2018 when the Fosterton differentials to WTI were unusually high as a result of excess supply, high Canadian crude oil storage inventories and ongoing transportation constraints.

The Company’s realized crude oil price in southeast Saskatchewan is based on Midale par price at Cromer. Midale par price increased 17 percent to average $72.44 per barrel in the fourth quarter of 2019 compared to $61.72 per barrel in the fourth quarter of 2018. The increase is primarily due to stronger Midale oil price differentials to WTI in the fourth quarter of 2019 compared to the fourth quarter of 2018 when the Midale differentials to WTI were unusually high as a result of excess supply, high Canadian crude oil storage inventories and ongoing transportation constraints. Midale par oil prices decreased two percent to average $74.38 per barrel in 2019 compared to $75.73 per barrel in 2018. The decrease is primarily due to lower WTI prices.

The AECO daily spot price increased 59 percent to average $2.48 per Mcf in the fourth quarter of 2019 compared to an average of $1.56 per Mcf in the fourth quarter of 2018. The AECO daily spot price increased 17 percent to average $1.76 per Mcf in 2019 compared to an average of $1.50 per Mcf in 2018. The increases were primarily due to changes in pipeline capacity curtailment procedures in 2019. In addition, the increase in the fourth quarter was also attributed to stronger natural gas demand compared to the fourth quarter of 2018.

The natural gas liquids realized price decreased 41 percent to average $17.56 per barrel in the fourth quarter of 2019 compared to $29.52 per barrel in the fourth quarter of 2018. The natural gas liquids realized price decreased 43 percent to average $20.58 per barrel in 2019 compared to $35.90 per barrel in 2018. The decreases are primarily due to increased supply and higher transportation costs to market.

Risk Management and Hedging Activities

Whitecap maintains an ongoing risk management program to reduce the volatility of revenues in order to fund capital expenditures and pay cash dividends to shareholders.

The Company realized a loss of $2.5 million and $20.3 million on its commodity risk management contracts for the quarter and year ended December 31, 2019, respectively. The unrealized gains and losses are a result of the non-cash change in the mark-to-market values period over period. The significant assumptions made in determining the fair value of financial instruments are disclosed in Note 4 to the Company’s audited annual consolidated financial statements for the year ended December 31, 2019.

Risk Management Contracts($000s)	Three months ended December 31 Year ended December 31 2019 2018 2019 2018
Realized gain (loss) on commodity and foreign exchange (FX) contracts Unrealizedgain(loss)on commodityand FX contracts	(2,535) 32,133 (20,284) (64,000) (24,707) 218,259 (87,875) 122,481
Net gain (loss) on commodity and FX contracts Realized gain (loss) on interest rate contracts (1) Unrealized gain (loss) on interest rate contracts(1) Realized gain on equity contracts(2) Unrealized gainonequity contracts(2)	(27,242) 250,392 (108,159) 58,481 204 34 434 (1,623) 2,706 (36) 3,864 1,459 159 - 159 - 1,256 - 1,256 -
Netgain(loss)on risk management contracts	(22,917) 250,390 (102,446) 58,317

Notes:

(1) The gain (loss) on interest rate risk management contracts is included in interest and financing expenses.

(2) The gain on equity contracts is included in stock-based compensation expenses.

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Exhibit 3

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Exhibit 4
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Change in Risk Management Net Asset
September 30, 2019 to December 31, 2019
25 22.6
20
15
10
0.7
5 1.9
- (19.3) (2.2)
Change in Risk Management Net Asset
December 31, 2018 to December 31, 2019
84.6
90
80
70
60
50
40
30 1.4
20
10 (64.4) 1.9
- (19.7)
$ Millions
$ Millions
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At December 31, 2019, the following risk management contracts were outstanding with an asset fair market value of $5.8 million and a liability fair market value of $3.9 million.

WTI Crude Oil Derivative Contracts

			Volume	Bought Put Price	Sold Call Price
Type	Term		(bbls/d)	(C$/bbl) (1)	(C$/bbl) (1)
Collar	2020	Jan – Jun	11,000	68.18	87.45
Collar	2020	Jul – Dec	7,000	64.29	84.22
Collar	2020		10,000	62.30	80.23
Collar	2021		1,000	60.00	80.35

Note:

(1) Prices reported are the weighted average prices for the period.

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Natural Gas Derivative Contracts

			Volume	Swap Price
Type	Term		(GJ/d)	(C$/GJ) (1)
Swap	2020	Jan – Mar	20,000	2.19
Swap	2020	Apr – Oct	5,000	1.65
Swap	2020		5,000	1.82

Note:

(1) Prices reported are the weighted average prices for the period.

Power Derivative Contracts

		Volume	Fixed Rate
Type	Term	(MWh)	($/MWh) (1)
Swap	2020	8,784	50.50

Note:

(1) Prices reported are the weighted average prices for the period.

Interest Rate Contracts

			Amount	Fixed Rate
Type	Term		($000s)	(%) (1)	Index (2)
Swap	Aug 6, 2019	Aug 6, 2024	200,000	1.554	CDOR

Note:

(1) Rates reported are the weighted average rates for the period.

(2) Canadian Dollar Offered Rate (“CDOR”).

Equity Derivative Contracts

			Notional Amount
Type	Term		($000s) (1)	Share Volume
Swap	Jan 1, 2020	Oct 1, 2020	10,867	2,025,000
Swap	Jan 1, 2020	Oct 1, 2021	12,584	2,345,000
Swap	Jan 1, 2020	Oct 1, 2022	13,255	2,470,000

Note:

(1) Notional amount is calculated as the share volume for the period multiplied by the weighted average prices for the period.

Contracts entered into subsequent to December 31, 2019

WTI Crude Oil Derivative Contracts

				Bought Put	Sold Call
			Volume	Price	Price	Swap Price
Type	Term		(bbls/d)	(C$/bbl) (1)	(C$/bbl) (1)	(C$/bbl) (1)
Swap	2020	Jan – Jun	2,000			80.93
Collar	2020	Jul – Dec	2,000	65.00	83.20
Collar	2021	Jan–Jun	1,000	60.00	82.70

Note:

(1) Prices reported are the weighted average prices for the period.

WTI Crude Oil Differential Derivative Contracts

			Volume		Swap Price
Type	Term		(bbls/d)	Basis (1) (2)	(C$/bbl) (3)
Swap	2020	Apr – Jun	6,000	MSW	6.88
Swap	2020	Jul – Dec	2,000	MSW	8.00
Swap	2020	Apr – Jun	4,000	WCS	21.80
Swap	2020	Jul–Dec	2,000	WCS	21.65

Notes:

(1) Mixed Sweet Blend (“MSW”).

(2) Western Canadian Select (“WCS”).

(3) Prices reported are the weighted average prices for the period.

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Natural Gas Derivative Contracts

			Volume	Swap Price
Type	Term		(GJ/d)	(C$/GJ) (1)
Swap	2020	Apr – Oct	10,000	1.67
Swap	2021		5,000	1.86

Note:

(1) Prices reported are the weighted average prices for the period.

Royalties

Royalties
	Three months ended			Year ended
	December 31			December 31
($000s, except per boe amounts)	2019	2018	2019	2018
Royalties	60,975	45,585	253,763	268,090
As a % of petroleum and natural gas revenues	16.5	16.7	17.9	17.6
$ per boe	8.88	6.77	9.79	9.87

For both the quarter and year ended December 31, 2019, royalties as a percentage of revenues were generally consistent with the same periods in 2018.

Whitecap pays royalties to the provincial governments and mineral owners in Alberta, Saskatchewan and British Columbia. Each province has separate royalty regimes which impact Whitecap’s overall corporate royalty rate.

Operating Expenses

Operating Expenses
	Three months ended			Year ended
		December 31		December 31
($000s, except per boe amounts)	2019	2018	2019	2018
Operating expenses	81,414	82,652	320,960	327,160
$ per boe	11.85	12.28	12.38	12.05

Operating expenses per boe in the fourth quarter of 2019 decreased four percent to $11.85 per boe compared to $12.28 per boe in the fourth quarter of 2018. The decrease in operating expenses per boe is primarily attributed a $0.39 per boe decrease, as a result of Whitecap’s adoption of IFRS 16 on January 1, 2019, as certain contracts which were previously accounted for as operating leases are now recognized on the consolidated balance sheet. The interest portion of lease payments is now included in interest and financing expenses and the principal portion of lease payments is applied against the lease liabilities.

Operating expenses per boe increased three percent to $12.38 per boe in 2019 compared to $12.05 per boe in 2018. The increase in operating expenses per boe is primarily attributed to higher per boe fixed operating expenses as a result of lower production volumes, partially offset by a $0.41 per boe decrease, as a result of Whitecap’s adoption of IFRS 16 on January 1, 2019.

Transportation Expenses

Transportation Expenses
	Three	months ended		Year ended
		December 31		December 31
($000s, except per boe amounts)	2019	2018	2019	2018
Transportation expenses	16,480	14,820	58,627	58,952
$ per boe	2.40	2.20	2.26	2.17

Transportation expenses per boe in the fourth quarter of 2019 increased nine percent to $2.40 per boe compared to $2.20 per boe in the fourth quarter of 2018. Transportation expenses per boe increased four percent to $2.26 per boe in 2019 compared to $2.17 per boe in 2018. The increases were primarily due to increased shipper status which resulted in higher transportation expenses with a corresponding decrease in tariffs netted against petroleum and natural gas sales.

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Transportation expenses per boe will fluctuate quarterly based on pipeline connectivity or downtime, weather, shipper status and pipeline shipping arrangements. When Whitecap has shipper status, pipeline tariffs incurred by the Company are included in transportation expenses. When Whitecap does not have shipper status, pipeline tariffs incurred by commodity purchasers subsequent to the delivery of the Company’s product are charged back to Whitecap and are netted against petroleum and natural gas sales.

Operating Netbacks

The components of operating netbacks are shown below:

	Three months ended	Three months ended		Year ended
	December 31			December 31
Netbacks ($/boe)	2019	2018	2019	2018
Petroleum and natural gas revenues	53.76	40.46	54.70	55.96
Tariffs	(0.42)	(0.60)	(0.48)	(0.72)
Processing & other income	0.50	0.44	0.69	0.45
Blending revenue	1.05	1.13	1.17	0.47
Petroleum and natural gas sales	54.89	41.43	56.08	56.16
Realized hedging loss	(0.37)	4.77	(0.78)	(2.36)
Royalties	(8.88)	(6.77)	(9.79)	(9.87)
Operating expenses	(11.85)	(12.28)	(12.38)	(12.05)
Transportation expenses	(2.40)	(2.20)	(2.26)	(2.17)
Blending expenses	(1.05)	(0.92)	(1.14)	(0.38)
Operating netbacks (1)	30.34	24.03	29.73	29.33

Note:

(1) Operating netbacks are a non-GAAP measure which is defined under the Non-GAAP Measures section of this MD&A.

General and Administrative (“G&A”) Expenses

	Three months ended	Three months ended		Year ended
	December 31			December 31
($000s, except per boe amounts)	2019	2018	2019	2018
G&A costs net of recoveries	6,329	6,614	32,104	37,083
Capitalized G&A	(1,410)	(1,366)	(7,277)	(7,227)
G&A expenses	4,919	5,248	24,827	29,856
$ per boe	0.72	0.78	0.96	1.10

G&A expenses per boe in the fourth quarter of 2019 decreased eight percent to $0.72 per boe compared to $0.78 per boe in the fourth quarter of 2018. G&A expenses per boe decreased 13 percent to $0.96 per boe in 2019 compared to $1.10 per boe in 2018. The decreases on a per boe basis are primarily attributed to a $0.12 and $0.15 per boe decrease in the quarter and year ended December 31, 2019, respectively, as a result of Whitecap’s adoption of IFRS 16 on January 1, 2019, as certain contracts which were previously accounted for as operating leases are now recognized on the consolidated balance sheet. The interest portion of lease payments is now included in interest and financing expenses and the principal portion of lease payments is applied against the lease liabilities.

The capitalized G&A in the quarter and year ended December 31, 2019, is generally consistent with the capitalized G&A for the same periods in 2018.

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Share-based Awards

Share-based Awards
	Three	months ended		Year ended
		December 31		December 31
($000s, except per boe amounts)	2019	2018	2019	2018
Stock-based compensation	7,073	(1,777)	24,407	18,347
Realized gain on total return contracts	(159)	-	(159)	-
Unrealized gain on total return contracts	(1,256)	-	(1,256)	-
Capitalized stock-based compensation	(1,463)	64	(6,249)	(5,731)
Stock-based compensation expenses	4,195	(1,713)	16,743	12,616
$ per boe	0.61	(0.25)	0.65	0.46

The change in stock-based compensation for the quarter and year ended December 31, 2019 is primarily attributable to changes in stock-based compensation expenses on cash-settled awards, due to remeasuring the fair value of the awards at Whitecap’s share price on December 31, 2019. Stock-based compensation will fluctuate with changes to the expected payout multipliers associated with the performance awards, vesting of existing grants, additional grants under the Award Incentive Plan, as well as changes in fair value for awards that are accounted for as cash-settled.

Award Incentive Plan

The Company implemented an Award Incentive Plan effective April 30, 2013. The Award Incentive Plan has time-based awards and performance awards which may be granted to directors, officers, employees of the Company and other service providers. Effective January 1, 2017, independent outside directors will receive only time-based awards as the primary form of long-term compensation. As at December 31, 2019, the maximum number of common shares issuable under the plan shall not at any time exceed 3.755 percent of the total common shares outstanding. Vesting is determined by the Company’s Board of Directors. Currently, time-based awards and performance awards issued to employees of the Company vest three years from date of grant. Time-based awards issued to independent outside directors have vesting periods ranging from 1 to 3 years. Performance awards issued to officers of the Company vest in two tranches with one half of such awards vesting February 1 and one half vesting October 1 of the third year following the grant date.

Each time-based award may in the Company’s sole discretion, entitle the holder to be issued the number of common shares designated in the time-based award plus dividend equivalents or payment in cash. Decisions regarding settlement method for insider and non-insider awards are mutually exclusive. On October 1, 2018, consistent with the terms of the Award Incentive Plan, awards vesting for insiders were settled in cash. As a result, the remaining insider awards were accounted for as cash-settled, resulting in the recognition of share award liabilities on the consolidated balance sheet. Performance awards are also subject to a performance multiplier. This multiplier, ranging from zero to two, will be applied on vesting and is dependent on the performance of the Company relative to predefined corporate performance measures set by the Board of Directors for the associated period.

A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of awards that vest. Based on the terms of the Award Incentive Plan, the fair value of share awards is equal to the underlying share price on grant date. The fair value of awards that are accounted for as cash-settled transactions are subsequently adjusted to the underlying share price at each period end. Performance awards are also adjusted by an estimated payout multiplier. The resulting stock-based compensation expense is recognized on a straight-line basis over the vesting period, with a corresponding increase to contributed surplus in the case of awards accounted for as equity-settled, or accounts payable and sharebased compensation liability in the case of awards accounted for as cash-settled. Upon the vesting of the awards that are accounted for as equity-settled, the associated amount in contributed surplus is recorded as an increase to share capital.

As at December 31, 2019, the Company had 7.5 million awards outstanding.

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Interest and Financing Expenses

Interest and Financing Expenses
	Three	months ended		Year ended
		December 31		December 31
($000s, except per boe amounts)	2019	2018	2019	2018
Interest and financing expenses	9,659	13,501	47,972	52,702
$ per boe	1.41	2.01	1.85	1.94

Interest and financing expenses per boe decreased 30 percent to $1.41 per boe in the fourth quarter of 2019 compared to $2.01 per boe in the fourth quarter of 2018. Interest and financing expenses per boe decreased five percent to $1.85 per boe in 2019 compared to $1.94 per boe in 2018. The decreases on a per boe basis were mainly attributed to higher unrealized gains on interest rate contracts, which are included in interest and financing expenses, and lower outstanding debt balances and interest rates in the quarter and year ended December 31, 2019 compared to the same periods in 2018. The decreases were partially offset by a $0.13 and $0.15 per boe increase in the quarter and year ended December 31, 2019, respectively, as a result of Whitecap’s adoption of IFRS 16 on January 1, 2019, as the interest portion of lease payments is now included in interest and financing expenses.

Depletion, Depreciation and Amortization (“DD&A”)

	Three	months ended		Year ended
		December 31		December 31
($000s, except per boe amounts)	2019	2018	2019	2018
Depletion, Depreciation and Amortization	134,277	125,062	486,230	487,013
$ per boe	19.55	18.57	18.75	17.93

DD&A per boe in the fourth quarter of 2019 increased five percent to $19.55 per boe compared to $18.57 per boe in the fourth quarter of 2018. DD&A per boe increased five percent to $18.75 per boe in 2019 compared to $17.93 per boe in 2018.

The increases on a per boe basis were primarily attributed to a $0.51 and $0.54 increase in the quarter and year ended December 31, 2019, respectively, as a result of Whitecap’s adoption of IFRS 16 on January 1, 2019, as depreciation is recognized on the right-of-use assets over the lease terms. The increases were also attributed to an increased depletion rate in Northwest Alberta and British Columbia, in the fourth quarter of 2019, as a result of increased future development costs and reserves added in the quarter.

DD&A per boe will fluctuate from one period to the next depending on the amount and type of capital spending, the recognition or reversal of impairments, the amount of reserves added and production volumes. The depletion rates are calculated on proved and probable oil and natural gas reserves, taking into account the future development costs to produce the reserves.

Impairment expense

Impairment expense
	Three	months ended		Year ended
		December 31		December 31
($000s)	2019	2018	2019	2018
Impairment expense	296,914	219,253	296,914	219,253

As at December 31, 2019, the Company determined that the carrying amounts of the West Central Saskatchewan (“WCSK”) and West Central Alberta (“WCAB”) CGUs of $0.9 billion and $1.3 billion, respectively, exceeded their fair value less costs of disposal of $0.8 billion and $1.1 billion, respectively. The full amount of the impairment was attributed to PP&E and, as a result, a total impairment loss of $296.9 million was recorded in impairment expense. The impairment expense in 2019 was primarily a result of lower forecast benchmark commodity prices at December 31, 2019 compared to December 31, 2018.

As at December 31, 2018, the Company determined that the carrying amount of the WCSK CGU of $1.1 billion exceeded its fair value less costs of disposal of $0.8 billion. The full amount of the impairment was attributed to PP&E and, as a result, a total impairment loss of $219.3 million was recorded in impairment expense. The impairment expense in 2018 was primarily a result of negative technical revisions in reserves assigned due to well performance at December 31, 2018, compared to December 31, 2017.

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Taxes

For the quarter and year ended December 31, 2019, the Company recognized a deferred income tax recovery of $65.7 million and $47.5 million, respectively, compared to a deferred income tax expense of $1.9 million and $28.4 million, respectively, for the same periods in 2018. The general Provincial tax rate in Alberta was decreased on June 28, 2019 from 12 percent to 11 percent for the second half of 2019, 10 percent for 2020, 9 percent for 2021 and 8 percent for 2022 and beyond. As a result of the rate change, Whitecap recognized $12.5 million in deferred income tax recovery in the consolidated statement of comprehensive income for the year ended December 31, 2019.

The following gross deductions are available for deferred income tax purposes:

	December 31	December 31
($000s)	2019	2018	Annual Deductibility
Undepreciated capital cost	610,658	594,470	Various rates, primarily 25%
			declining balance
Canadian development expense	683,907	598,346	30% declining balance
Canadian oil & gas property expense	1,653,727	1,807,731	10% declining balance
Non-capital loss carry forward	688,645	919,893	100%
Share issue costs	10,714	30,467	20% straight line
Total	3,647,651	3,950,907

Net Income

For the quarter and year ended December 31, 2019, the Company recognized net losses of $203.9 million and $155.9 million, respectively, compared to net income of $7.0 million and $65.1 million for the same periods in 2018, respectively.

The following changes impacted net income:

The following changes impacted net income:
	Three months ended	Year ended
($000s)	December 31	December 31
2018 Net Income	6,966	65,128
Change in risk management contracts	(277,634)	(166,640)
Increase in impairment expenses	(77,661)	(77,661)
Change in petroleum and natural gas sales	98,065	(71,060)
Increase in blending expenses	(967)	(19,359)
Increase in stock-based compensation expenses	(5,908)	(4,127)
Change in deferred income tax expense	67,604	75,897
Change in royalties	(15,390)	14,327
Decrease in operating expenses	1,238	6,200
Decrease in accretion of decommissioning liabilities	297	5,542
Decrease in general and administrative expenses	329	5,029
Decrease in unrealized loss on investment	6,221	4,857
Change in depletion, depreciation and amortization	(9,215)	783
Other net changes	2,109	5,211
2019 Net Loss	(203,946)	(155,873)

The factors causing these changes are discussed in the preceding sections.

Cash Flow from Operating Activities, Funds Flow and Payout Ratios

Management considers funds flow to be a key measure of operating performance as it demonstrates Whitecap’s ability to generate the cash necessary to pay dividends, repay debt, make capital investments, and/or to repurchase common shares under the Company’s normal course issuer bid (“NCIB”). Management believes that by excluding the temporary impact of changes in non-cash operating working capital, funds flow provides a useful measure of Whitecap’s ability to generate cash that is not subject to short-term movements in non-cash operating working capital. Funds flow is not a standardized measure

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and, therefore, may not be comparable with the calculation of similar measures by other entities.

Whitecap reports funds flow in total and on a per share basis. Refer to Note 5(e) "Capital Management" in the Company’s audited annual consolidated financial statements. The following table reconciles cash flow from operating activities to funds flow and free funds flow:

	Three	months ended		Year ended
		December 31	December 31
($000s)	2019	2018	2019	2018
Cash flow from operating activities	162,887	158,244	645,358	727,934
Changes in non-cash workingcapital	21,659	(19,434)	30,252	(23,514)
Funds flow (1)	184,546	138,810	675,610	704,420
Expenditures on property, plant and equipment(“PP&E”)	98,762	76,485	403,977	440,499
Free funds flow (2)	85,784	62,325	271,633	263,921
Dividends paid or declared	35,018	33,611	138,341	132,295
Basic payout ratio (%) (2)	19	24	20	19
Total payout ratio (%) (2)	72	79	80	81
Funds flow per share, basic	0.45	0.33	1.64	1.69
Funds flow per share, diluted	0.45	0.33	1.63	1.67
Dividendspaid or declaredper share	0.09	0.08	0.34	0.32

Notes:

(1) Refer to Note 5(e) "Capital Management" in the audited annual consolidated financial statements.

(2) Free funds flow, basic payout ratio and total payout ratio are non-GAAP measures which are defined under the Non-GAAP Measures section of this MD&A.

Dividends are only declared once they are approved by the Company’s Board of Directors. The Board of Directors reviews Whitecap’s dividend policy on a monthly basis.

Cash flow from operating activities for the quarter and year ended December 31, 2019, were $162.9 million and $645.4 million, respectively, compared to $158.2 million and $727.9 million for the same periods in 2018. The following changes impacted cash flow from operating activities:

	Three months ended	Year ended
($000s)	December 31	December 31
2018 Cash flow from operating activities	158,244	727,934
Change in net income	(210,912)	(221,001)
Change in deferred income tax expense (recovery)	(67,604)	(75,897)
Net change in non-cash working capital items	(41,093)	(53,766)
Decrease in accretion of decommissioning liabilities	(297)	(5,542)
Decrease in unrealized loss on investment	(6,221)	(4,857)
Change in depletion, depreciation and amortization	9,215	(783)
Change in unrealized risk management contracts	238,968	206,695
Change in impairment expenses	77,661	77,661
Other net changes	4,926	(5,086)
2019 Cash flow from operatingactivities	162,887	645,358

Funds flow for the quarter ended December 31, 2019, was $184.5 million compared to $138.8 million for the same period in 2018. The increase in funds flow is primarily attributed to higher production volumes and commodity prices. Funds flow for the year ended December 31, 2019, was $675.6 million compared to $704.4 million for the same period in 2018. The decrease in funds flow is primarily attributed to lower production volumes.

The impact as a result of the adoption of IFRS 16 on funds flow, for the quarter and year ended December 31, 2019, was an increase of $2.6 million and $10.6 million, respectively.

Free funds flow for the quarter ended December 31, 2019, was $85.8 million, compared to $62.3 million for

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the same period in 2018. The increase in free funds flow is primarily attributed to higher funds flow, which was partially offset by higher expenditures on PP&E.

Free funds flow for the year ended December 31, 2019, was $271.6 million, compared $263.9 million in 2018. The increase in free funds flow is primarily attributed to lower expenditures on PP&E, which was partially offset by lower funds flow.

Capital Expenditures

Capital Expenditures
	Three months ended			Year ended
		December 31	December 31
($000s)	2019	2018	2019	2018
Land and geological	476	1,006	4,374	1,452
Drilling and completions	70,850	54,849	332,856	371,330
Investment in facilities	25,982	18,999	58,863	59,765
Capitalized administration	1,410	1,366	7,277	7,227
Corporate and other assets	44	265	607	725
Expenditures on PP&E	98,762	76,485	403,977	440,499
Property acquisitions	410	15,157	4,016	35,249
Property dispositions	(266)	(205)	(978)	(11,681)
Corporate acquisition	-	-	-	53,916
Total capital expenditures	98,906	91,437	407,015	517,983

For the quarter and year ended December 31, 2019, expenditures on PP&E totaled $98.8 million and $404.0 million respectively with 98 percent and 97 percent, respectively, spent on drilling, completions and facilities.

For the quarter and year ended December 31, 2019, Whitecap’s drilling activity was as follows:

	Three months ended	Three months ended		Year ended
	December 31, 2019		December 31, 2019
	Gross	Net	Gross	Net
Northwest Alberta and British Columbia	4	3.4	26	21.0
Southeast Saskatchewan	6	3.4	6	3.4
Southwest Saskatchewan (1)	6	4.4	48	37.0
West Central Alberta (2)	-	-	18	17.1
West Central Saskatchewan (3)	10	8.6	95	87.8
Total	26	19.8	193	166.3

Notes:

(1) Includes 3 (1.7 net) injection wells in the year ended December 31, 2019.

(2) Includes 3 (2.6 net) injection wells in the year ended December 31, 2019.

(3) Includes 2 (2.0 net) injection wells in the year ended December 31, 2019.

For the quarter and year ended December 31, 2018, Whitecap’s drilling activity was as follows:

	Three months ended	Three months ended		Year ended
	December 31, 2018		December 31, 2018
	Gross	Net	Gross	Net
Northwest Alberta and British Columbia	8	2.8	29	20.6
Southeast Saskatchewan (1)	9	5.4	16	9.6
Southwest Saskatchewan (2)	5	1.2	60	41.2
West Central Alberta (3)	1	1.4	21	17.5
West Central Saskatchewan	11	9.4	135	127.4
Total	34	20.2	261	216.3

Notes:

(1) Includes 4 (2.5 net) and 6 (3.7 net) injections wells for the quarter and year ended December 31, 2018, respectively.

(2) Includes 1 (0.5 net) injection well in the year ended December 31, 2018.

(3) Includes 1 (0.9 net) injection well in the year ended December 31, 2018.

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Corporate Acquisition

On February 22, 2018, the Company completed the acquisition of all of the issued and outstanding common shares of a private company for $56.8 million in cash, net of acquired working capital.

Decommissioning Liability

At December 31, 2019, the Company’s decommissioning liability balance was $859.1 million ($725.6 million as at December 31, 2018) for future abandonment and reclamation of the Company’s properties. The increase in the decommissioning liability as at December 31, 2019 compared to December 31, 2018 is primarily attributed to revisions in estimates as a result of a decrease in the risk-free rate from 2.2 percent as at December 31, 2018 to 1.8 percent as at December 31, 2019. Estimates are based on both operational knowledge of the properties and updated industry guidance provided by the Alberta Energy Regulator and the Saskatchewan Ministry of the Economy. The estimates are reviewed quarterly and adjusted as new information regarding the liability is determined.

Exhibit 5

==> picture [360 x 216] intentionally omitted <==

----- Start of picture text -----

Change in Decommissioning Liability
December 31, 2018 to December 31, 2019
900 122.7 859.1
850
800
750 725.6 7.8 2.6 10.2
700 (0.4)
(9.4)
650
$ Millions
----- End of picture text -----

Capital Resources and Liquidity

Credit Facilities

As at December 31, 2019, the Company had a $1.175 billion credit facility with a syndicate of banks. The credit facility consists of a $1.1 billion revolving syndicated facility and a $75 million revolving operating facility, with a maturity date of May 31, 2023. Prior to any anniversary date, being May 31 of each year, Whitecap may request an extension of the then current maturity date, subject to approval by the banks. Following the granting of such extension, the term to maturity of the credit facilities shall not exceed four years. The credit facility provides that advances may be made by way of direct advances, banker’s acceptances or letters of credit/guarantees. The credit facility bears interest at the bank's prime lending or bankers' acceptance rates plus applicable margins. The applicable margin charged by the bank is dependent upon the Company’s debt to earnings before interest, taxes, depreciation and amortization “EBITDA” ratio for the most recent quarter. The bankers’ acceptances bear interest at the applicable banker’s acceptance rate plus an explicit stamping fee based upon the Company’s debt to EBITDA ratio. The credit facilities are secured by a floating charge debenture on the assets of the Company.

In the second quarter of 2018, as part of our annual credit facility review, the credit facility transitioned from a borrowing-based structure with lending capacity re-determined on a semi-annual basis, to a financial covenant-based structure with an extendible four-year term governed by our existing financial covenants.

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The following table lists Whitecap’s financial covenants as at December 31, 2019:

		December 31
Covenant Description		2019
	Maximum Ratio
Debt to EBITDA (1) (2)	4.00	1.59
	Minimum Ratio
EBITDA to interest expense (1)	3.50	14.39

Notes:

(1) The EBITDA used in the covenant calculation is adjusted for non-cash items, transaction costs and extraordinary and nonrecurring items such as material acquisitions or dispositions.

(2) The debt used in the covenant calculation includes bank indebtedness, letters of credit, and dividends declared.

As of December 31, 2019, the Company was compliant with all covenants provided for in the lending agreement. Copies of the Company’s credit agreements may be accessed through the SEDAR website (www.sedar.com).

Senior Secured Notes

As at December 31, 2019, the Company had issued $595 million senior secured notes. The notes rank equally with Whitecap’s obligations under its credit facility. The terms, rates and principals of the Company’s outstanding senior notes are detailed below:

($000s)
Issue Date	Maturity Date	Coupon Rate	Principal
January 5, 2017	January 5, 2022	3.46%	200,000
May 31, 2017	May 31, 2024	3.54%	200,000
December 20, 2017	December 20, 2026	3.90%	195,000
Balance at December 31,2019			595,000

The senior secured notes are subject to the same debt to EBITDA ratio and EBITDA to interest expense ratio described under the credit facility. As of December 31, 2019, the Company was compliant with all covenants provided for in the lending agreements.

Equity

On May 16, 2017, the Company announced the approval of its NCIB by the TSX (the “2017 NCIB”). The 2017 NCIB allowed the Company to purchase up to 18,457,076 common shares over a period of twelve months commencing on May 18, 2017.

On May 16, 2018, the Company announced the approval of its renewed NCIB by the TSX (the “2018 NCIB”). The 2018 NCIB allowed the Company to purchase up to 20,864,806 common shares over a period of twelve months commencing on May 18, 2018.

On May 16, 2019, the Company announced the approval of its renewed NCIB by the TSX (the “2019 NCIB”). The 2019 NCIB allows the Company to purchase up to 20,657,914 common shares over a period of twelve months commencing on May 21, 2019.

Purchases are made on the open market through the TSX or alternative platforms at the market price of such common shares. All common shares purchased under the NCIB are cancelled. The total cost paid, including commissions and fees, is first charged to share capital to the extent of the average carrying value of Whitecap’s common shares and the excess is charged to contributed surplus.

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The following table summarizes the share repurchase activities during the period:

	Three months ended	Three months ended		Year ended
	December 31		December 31
(000s except pershare amounts)	2019	2018	2019	2018
Shares repurchased (1)	-	3,303	4,621	6,277
Average cost ($/share)	-	5.22	4.25	6.81
Amounts charged to
Share capital	-	17,235	19,628	42,708
Contributed surplus	-	-	-	11
Share repurchase cost	-	17,235	19,628	42,719

Note:

(1) As at December 31, 2018, 910,000 shares repurchased under the NCIB were held in treasury. Subsequent to year-end, all of the shares held in treasury were cancelled.

The Company is authorized to issue an unlimited number of common shares. As at February 26, 2020, there were 408.0 million common shares and 7.1 million share awards outstanding.

Liquidity

The Company generally relies on funds flow, equity issuances and its credit facility to fund its capital requirements, dividend payments and provide liquidity. From time to time, the Company accesses capital markets to meet its additional financing needs and to maintain flexibility in funding its capital programs. Future liquidity depends primarily on funds flow, existing credit facilities and the ability to access debt and equity markets. All repayments on the revolving production and operating facilities are due at the term maturity date. As none of the facilities mature within the next year, the liabilities are considered to be noncurrent. At December 31, 2019, the Company had $593.4 million of unutilized credit to cover any working capital deficiencies. The Company believes that available credit facilities combined with anticipated funds flow will be sufficient to satisfy Whitecap’s 2020 development capital program and dividend payments for the 2020 fiscal year.

Contractual Obligations

Whitecap has contractual obligations in the normal course of business which may include purchase of assets and services, operating agreements, transportation commitments, sales commitments, royalty obligations, lease rental obligations, employee agreements and debt. These obligations are of a recurring, consistent nature and impact Whitecap’s cash flows in an ongoing manner. The Company is committed to future payments under the following agreements:

($000s)	2020	2021	2022	2023+	Total
Lease liabilities	13,993	14,287	14,651	50,843	93,774
Service agreements	2,254	2,251	2,249	10,955	17,709
Transportation agreements	23,281	16,845	24,239	135,554	199,919
CO2purchase commitments	38,350	39,011	39,790	119,246	236,397
Long-term debt (1)	21,605	21,605	14,780	1,216,440	1,274,430
Total	99,483	93,999	95,709	1,533,038	1,822,229

Note:

(1) These amounts include the notional principal and interest payments.

Related Party Transactions

The Company has retained the law firm of Burnet, Duckworth & Palmer LLP (“BD&P”) to provide Whitecap with legal services. A director of Whitecap is a partner of this firm. During the quarter and year ended December 31, 2019, the Company incurred $0.2 million and $0.4 million for legal fees and disbursements, respectively ($0.1 million and $0.7 million for the quarter and year ended December 31, 2018, respectively). These amounts have been recorded at the amounts that have been agreed upon by the two parties. The Company expects to retain the services of BD&P from time to time. As of December 31, 2019, a $0.1 million payable balance (nil – December 31, 2018) was outstanding.

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Changes in Accounting Policies Including Initial Adoption

Whitecap adopted IFRS 16, Leases (“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, Whitecap recognized lease liabilities of $91.6 million 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, short-term and low-value leases, and discounted using the Company’s incremental borrowing rate as of January 1, 2019. The weighted average incremental borrowing rate used to determine the lease liabilities at adoption was approximately 4.5 percent. The difference in operating lease commitments disclosed as at December 31, 2018 and lease liabilities recognized on the consolidated balance sheet at January 1, 2019 is primarily due to non-lease components of contracts reassessed as service agreements. The associated right-of-use assets were measured at the amount equal to the lease liabilities on January 1, 2019, with no impact on retained earnings.

In applying IFRS 16 for the first time, Whitecap has used the following practical expedients permitted by the standard:

• the use of a single discount rate to a portfolio of leases with reasonably similar characteristics; and

• · the accounting for operating leases with a remaining lease term of less than 12 months as at January 1, 2019 as short-term leases.

Upon the adoption of IFRS 16, the Company adopted the following significant accounting policy effective January 1, 2019:

Leases

A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. A lease liability is recognized at the commencement of the lease term at the present value of the lease payments that are not paid at that date. At the commencement date, a corresponding right-of-use asset is recognized at the amount of the lease liability, adjusted for lease incentives received, retirement costs and initial direct costs. Depreciation is recognized on the right-of-use asset over the lease term. Interest expense is recognized on the lease liabilities using the effective interest rate method and payments are applied against the lease liability.

Key areas where management has made judgments, estimates, and assumptions related to the application of IFRS 16 include:

• The incremental borrowing rates are based on judgments including economic environment, term, currency, and the underlying risk inherent to the asset. The carrying balance of the right-of-use assets, lease liabilities, and the resulting interest expense and depreciation expense, may differ due to changes in the market conditions and lease term.

• Lease terms are based on assumptions regarding extension terms that allow for operational flexibility and future market conditions.

Standards Issued but not yet Effective

There are no other standards or interpretations issued, but not yet adopted, that are anticipated to have a material effect on the reported net income (loss) or net assets of the Company.

Off Balance Sheet Arrangements

The Company does not have any special purpose entities nor is it party to any arrangements that would be excluded from the balance sheet other than commitments disclosed in Note 22 to the Company’s audited annual consolidated financial statements for the year ended December 31, 2019.

Critical Accounting Estimates

Whitecap’s financial and operating results may incorporate certain estimates including:

• estimated revenues, royalties and operating expenses on production as at a specific reporting date but for which actual revenues and expenses have not yet been received;

17

• estimated capital expenditures on projects that are in progress;

• estimated depletion, depreciation and accretion that are based on estimates of oil and gas reserves that the Company expects to recover in the future, commodity prices, estimated future salvage values and estimated future capital costs;

• estimated fair values of derivative contracts that are subject to fluctuation depending upon the underlying commodity prices and foreign exchange rates;

• estimated value of decommissioning liabilities that are dependent upon estimates of future costs, timing of expenditures and the risk-free rate;

• estimated income and other tax liabilities requiring interpretation of complex laws and regulations. All tax filings are subject to audit and potential reassessment after the lapse of considerable time;

• estimated stock-based compensation expense using the Black-Scholes option pricing model;

• · estimated fair value of business combinations and goodwill requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of PP&E and exploration and evaluation assets acquired generally require the most judgment and include estimates of reserves acquired, forecast benchmark commodity prices and discount rates; and

• estimated recoverable amounts are based on estimated proved plus probable reserves, production rates, oil and gas prices, future costs, discount rates and other relevant assumptions.

The Company has hired individuals and consultants who have the skills required to make such estimates and ensures that individuals or departments with the most knowledge of the activity are responsible for the estimates. Furthermore, past estimates are reviewed and compared to actual results, and actual results are compared to budgets in order to make more informed decisions on future estimates.

Business Risks

Whitecap’s exploration and production activities are concentrated in the Western Canadian Sedimentary Basin, where activity is highly competitive and includes a variety of different-sized companies. Whitecap is subject to a number of risks that are also common to other organizations involved in the oil and gas industry. Such risks include finding and developing oil and gas reserves at economic costs, estimating amounts of recoverable reserves, production of oil and gas in commercial quantities, marketability of oil and gas produced, fluctuations in commodity prices, stock market volatility, debt service which may limit timing or amount of dividends as well as market price of shares, financial and liquidity risks and environmental and safety risks.

In order to reduce exploration risk, Whitecap employs or contracts highly qualified and motivated professionals who have demonstrated the ability to generate quality proprietary geological and geophysical prospects.

Whitecap has retained an independent engineering consulting firm that assists the Company in evaluating recoverable amounts of oil and gas reserves. Values of recoverable reserves are based on a number of variable factors and assumptions such as commodity prices, projected production, future production costs and government regulations. Such estimates may vary from actual results.

The Company mitigates its risk related to producing hydrocarbons through the utilization of current technology and information systems. In addition, Whitecap strives to operate the majority of its prospects, thereby maintaining operational control. When the Company does not operate, it relies on its partners in jointly owned properties to maintain operational control.

Whitecap is exposed to market risk to the extent that the demand for oil and gas produced by the Company exists within Canada and the United States. External factors beyond the Company’s control may affect the marketability of oil and gas produced. These factors include commodity prices and variations in the Canada–United States currency exchange rate which, in turn responds to economic and political circumstances throughout the world. Oil prices are affected by worldwide supply and demand fundamentals while natural gas prices are affected by North American supply and demand fundamentals. Whitecap uses futures and options contracts to hedge its exposure to the potential adverse impact of commodity price volatility. The primary objective of the risk management program is to provide a measure of stability to Whitecap dividends and its capital development program.

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Exploration and production for oil and gas is capital intensive. In addition to funds flow, the Company accesses the equity markets as a source of new capital. In addition, Whitecap utilizes bank financing to support ongoing capital investments which exposes the Company to fluctuations in interest rates on its bank debt. Funds flow also fluctuates with changing commodity prices. Equity and debt capital are subject to market conditions, and availability may increase or decrease from time to time.

Additional information regarding risk factors including, but not limited to, business risks is available in our Annual Information Form, a copy of which may be accessed through the SEDAR website (www.sedar.com).

Environmental Risks

General Risks

Oil and gas exploration and production can involve environmental risks such as litigation, physical and regulatory risks. Physical risks include the pollution of the environment, climate change and destruction of natural habitat, as well as safety risks such as personal injury. The Company works hard to identify the potential environmental impacts of its new projects in the planning stage and during operations. The Company conducts its operations with high standards in order to protect the environment, its employees and consultants, and the general public. Whitecap maintains current insurance coverage for comprehensive and general liability as well as limited pollution liability. The amount and terms of this insurance are reviewed on an ongoing basis and adjusted as necessary to reflect current corporate requirements, as well as industry standards and government regulations. Without such insurance, and if the Company becomes subject to environmental liabilities, the payment of such liabilities could reduce or eliminate its available funds or could exceed the funds the Company has available and result in financial distress.

Climate Change Risks

Our exploration and production facilities and other operations and activities emit greenhouse gasses ("GHG") which may require us to comply with federal and/or provincial GHG emissions legislation. Climate change policy is evolving at regional, national and international levels, and political and economic events may significantly affect the scope and timing of climate change measures that are ultimately put in place to prevent climate change or mitigate our effects. The direct or indirect costs of compliance with GHG-related regulations may have a material adverse effect on our business, financial condition, results of operations and prospects. Some of our significant facilities may ultimately be subject to future regional, provincial and/or federal climate change regulations to manage GHG emissions. In addition, climate change has been linked to long-term shifts in climate patterns and extreme weather conditions both of which pose the risk of causing operational difficulties.

Additional information regarding risk factors including, but not limited to, environmental risks is available in our Annual Information Form, a copy of which may be accessed through the SEDAR website (www.sedar.com).

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Selected Annual Information

Selected Annual Information
($000s, except as noted)	2019	2018	2017
Financial
Petroleum and natural gas revenues	1,418,476	1,519,845	1,031,240
Funds flow (1)	675,610	704,420	508,627
Basic ($/share) (1)	1.64	1.69	1.37
Diluted ($/share) (1)	1.63	1.67	1.36
Net income (loss)	(155,873)	65,128	(123,968)
Basic ($/share)	(0.38)	0.16	(0.33)
Diluted ($/share)	(0.38)	0.15	(0.33)
Expenditures on PP&E	403,977	440,499	339,761
Property acquisitions	4,016	35,249	970,883
Property dispositions	(978)	(11,681)	(14,598)
Corporate acquisitions	-	53,916	-
Total assets	5,358,465	5,958,964	5,961,347
Net debt	1,193,267	1,296,330	1,295,906
Common shares outstanding (000s)	409,619	414,063	418,029
Dividends paid or declared per share	0.34	0.32	0.28
Operational
Average daily production
Crude oil (bbls/d)	55,413	58,511	43,589
NGLs (bbls/d)	4,503	4,397	3,415
Naturalgas(Mcf/d)	66,801	69,042	62,676
Total(boe/d)	71,050	74,415	57,450

Note:

(1) Refer to Note 5(e) "Capital Management" in the financial statements and to the section entitled "Cash Flow from Operating Activities, Funds Flow and Payout Ratios " contained within this MD&A.

In the past three years, fluctuations in production volumes and realized commodity prices have impacted the Company's petroleum and natural gas revenues and funds flow. In 2019, the Company reduced capital spending compared to the prior year with the focus on further strengthening the balance sheet by reducing net debt. As a result of the decreased capital program, production volumes were slightly lower than the prior year. Net income (loss) has fluctuated over the past three years due to changes in funds flow, impairment expense (reversal) and unrealized derivative gains and losses which fluctuate with the changes in forward commodity prices.

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Summary of Quarterly Results

ummary of Quarterly Results
2019	2018
($000s, except as noted) Q4 Q3 Q2 Q1	Q4 Q3 Q2 Q1
Financial Petroleum and natural gas revenues 369,190 331,317 374,730 343,239 Funds flow (1) 184,546 154,306 175,537 161,221 Basic ($/share) (1) 0.45 0.37 0.42 0.39 Diluted ($/share) (1) 0.45 0.37 0.42 0.39 Net income (loss) (203,946) 42,277 58,357 (52,561) Basic ($/share) (0.50) 0.10 0.14 (0.13) Diluted ($/share) (0.50) 0.10 0.14 (0.13) Expenditures on PP&E 98,762 153,848 26,463 124,904 Property acquisitions 410 2,020 196 1,390 Property dispositions (266) (89) 44 (667) Corporate acquisition - - - - Total assets 5,358,465 6,075,973 5,968,862 6,120,622 Net debt 1,193,267 1,241,579 1,189,750 1,297,412 Common shares outstanding (000s) 409,619 410,562 412,907 413,158 Dividends paid or declared per share 0.09 0.09 0.08 0.08 Operational Average daily production Crude oil (bbls/d) 58,044 53,245 55,155 55,199 NGLs (bbls/d) 4,805 4,399 4,417 4,386 Naturalgas(Mcf/d) 70,811 63,663 66,231 66,486	272,397 446,018 433,380 368,050 138,810 204,995 195,816 164,799 0.33 0.49 0.47 0.39 0.33 0.49 0.47 0.39 6,966 69,532 (3,615) (7,755) 0.02 0.17 (0.01) (0.02) 0.02 0.17 (0.01) (0.02) 76,485 114,955 66,444 182,615 15,157 18,369 1,108 615 (205) (9,764) (1,585) (127) - 750 - 53,166 5,958,964 6,142,384 6,136,672 6,165,095 1,296,330 1,288,259 1,323,093 1,414,606 414,063 416,456 417,485 417,255 0.08 0.08 0.08 0.08 57,072 59,212 59,786 57,976 4,656 4,460 4,461 4,002 68,739 71,141 69,393 66,852
Total(boe/d) 74,651 68,255 70,611 70,666	73,185 75,529 75,813 73,120

Note:

(1) Refer to Note 5(e) "Capital Management" in the financial statements and to the section entitled "Cash Flow from Operating Activities, Funds Flow and Payout Ratios " contained within this MD&A.

Over the past eight quarters, fluctuations in production volumes and realized commodity prices have impacted the Company's petroleum and natural gas revenues and funds flow. Net income (loss) has fluctuated due to changes in funds flow, impairment expense and unrealized derivative gains and losses which fluctuate with the changes in forward commodity prices and exchange rates. Capital expenditures and production volumes have fluctuated over time as a result of the timing of acquisitions and the impact of market conditions on the Company’s development capital expenditures.

The following outlines the significant events over the past eight quarters:

In 2019, the Company reduced capital spending compared to the prior year with the focus on further strengthening the balance sheet by reducing net debt. As a result of the decreased capital program, production volumes were slightly lower than the prior year.

In the fourth quarter of 2019, the Company recognized an impairment of $296.9 million attributed to PP&E. The impairment expense in 2019 was primarily a result lower forecast benchmark commodity prices at December 31, 2019 compared to December 31, 2018.

In the fourth quarter of 2018, the Company recognized an impairment of $219.3 million attributed to PP&E. The impairment expense was primarily a result of negative technical revisions in reserves assigned due to well performance at December 31, 2018 compared to December 31, 2017. Additionally, in the fourth quarter of 2018, there was increased volatility with a decrease in the WTI benchmark price and wider Canadian crude oil price differentials that negatively impacted petroleum and natural gas revenues and funds flow.

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DISCLOSURE CONTROLS AND PROCEDURES

Disclosure controls and procedures (“DC&P”), as defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings , are designed to provide reasonable assurance that information required to be disclosed in the Company’s annual filings, interim filings or other reports filed, or submitted by the Company under securities legislation is recorded, processed, summarized and reported within the time periods specified under securities legislation and include controls and procedures designed to ensure that information required to be so disclosed is accumulated and communicated to management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. The Chief Executive Officer and the Chief Financial Officer of Whitecap evaluated the effectiveness of the design and operation of the Company’s DC&P. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that Whitecap’s DC&P were effective as at December 31, 2019.

INTERNAL CONTROLS OVER FINANCIAL REPORTING

Internal control over financial reporting (“ICFR”), as defined in National Instrument 52-109, includes those policies and procedures that:

1. pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets of Whitecap;

2. are designed to provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of Whitecap are being made in accordance with authorizations of management and Directors of Whitecap; and

3. are designed to provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements.

The Chief Executive Officer and the Chief Financial Officer are responsible for establishing and maintaining ICFR for Whitecap. They have, as at the financial year ended December 31, 2019, designed ICFR, or caused it to be designed under their supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. 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 Whitecap’s officers used to design the Company’s ICFR is the 2013 Framework.

Under the supervision of the Chief Executive Officer and the Chief Financial Officer, Whitecap conducted an evaluation of the effectiveness of the Company’s ICFR as at December 31, 2019 based on the COSO Framework. Based on this evaluation, the officers concluded that as of December 31, 2019, Whitecap maintained effective ICFR.

It should be noted that while Whitecap’s officers believe that the Company’s controls provide a reasonable level of assurance with regard to their effectiveness, they do not expect that the DC&P and ICFR will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, but not absolute, assurance that the objectives of the control system are met.

There were no changes in Whitecap’s ICFR during the year ended December 31, 2019 that materially affected, or are reasonably likely to materially affect, the Company’s ICFR.

NON-GAAP MEASURES

This MD&A includes non-GAAP measures as further described herein. These non-GAAP measures do not have a standardized meaning prescribed by IFRS and, therefore, may not be comparable with the calculation of similar measures by other companies. Management believes that the presentation of these non-GAAP measures provides useful information to investors and shareholders as the measures provide increased transparency and the ability to better analyze performance against prior periods on a comparable basis.

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“Basic payout ratio” is calculated as dividends paid or declared divided by funds flow. Management believes that basic payout ratio provides a useful measure of Whitecap's dividend policy and the amount of funds flow retained by the Company for capital reinvestment.

“Free funds flow” represents funds flow less expenditures on PP&E. Management believes that free funds flow provides a useful measure of Whitecap's ability to increase returns to shareholders and to grow the Company’s business. Previously, Whitecap also deducted dividends paid or declared in the calculation of free funds flow. The Company believes the change in presentation better allows comparison with both dividend paying and non-dividend paying peers.

“Operating netbacks” are determined by adding blending revenue and processing & other income, deducting realized hedging losses or adding realized hedging gains and deducting tariffs, royalties, operating expenses, transportation expenses and blending expenses from petroleum and natural gas revenues. Operating netbacks are per boe measures used in operational and capital allocation decisions. Presenting operating netbacks on a per boe basis allows management to better analyze performance against prior periods on a comparable basis.

“Total payout ratio” is calculated as dividends paid or declared plus expenditures on PP&E, divided by funds flow. Management believes that total payout ratio provides a useful measure of Whitecap's capital reinvestment and dividend policy, as a percentage of the amount of funds flow.

BOE PRESENTATION

Boe means barrel of oil equivalent. All boe conversions in this MD&A are derived by converting gas to oil at the ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of oil. Boe may be misleading, particularly if used in isolation. A Boe conversion rate of 1 Bbl : 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio of oil compared to natural gas based on currently prevailing prices is significantly different than the energy equivalency ratio of 1 Bbl : 6 Mcf, utilizing a conversion ratio of 1 Bbl : 6 Mcf may be misleading as an indication of value.

FORWARD-LOOKING INFORMATION AND STATEMENTS

Certain statements contained in this MD&A constitute forward-looking statements and are based on Whitecap’s beliefs and assumptions based on information available at the time the assumption was made. By its nature, such forward-looking information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forwardlooking statements. The Company believes the expectations reflected in those forward-looking statements are reasonable, but no assurance can be given that these expectations will prove to be correct and such forward-looking statements should not be unduly relied upon.

This MD&A contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "estimate", "objective", "ongoing", "may", "will", "project", "believe", “measure”, “stability”, “depends”, “could”, “sustainability” and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this MD&A contains forward-looking information and statements pertaining to the following: Whitecap’s focus and strategy; Whitecap’s commodity risk management program and the benefits to be derived therefrom; the amount of future decommissioning liabilities; future liquidity and financial capacity; sources of funding the Company’s capital program; transportation expenses, stock-based compensation expenses; Whitecap’s ability to fund its current development capital program and dividend payments for 2020 and Whitecap’s deductions available for deferred income tax purposes.

The forward-looking information and statements contained in this MD&A reflect several material factors and expectations and assumptions of Whitecap including, without limitation: that Whitecap will continue to conduct its operations in a manner consistent with past operations; the general continuance or improvement in current industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; the accuracy of the estimates of Whitecap’s reserve volumes; the impact of increasing competition; the general stability of the economic and political environment in which Whitecap operates; the ability of Whitecap to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects which the Company has an interest in to operate in a safe, efficient and effective manner; field production and

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decline rates; the ability to reduce operating costs; the ability to replace and expand oil and natural gas reserves through acquisition, development or exploration; the timing and costs of pipeline, storage and facility construction and expansion; the ability of the Company to secure adequate product transportation; future petroleum and natural gas prices; currency, exchange and interest rates; the continued availability of adequate debt and equity financing and cash flow to fund Whitecap’s planned expenditures; and the ability to maintain dividends. Whitecap believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable, but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

The forward-looking information and statements included in this MD&A are not guarantees of future performance and should not be unduly relied upon. Such information and statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; changes in the demand for or supply of Whitecap’s products; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in Whitecap’s development plans or by third party operators of Whitecap’s properties; competition from other producers; inability to retain drilling rigs and other services; incorrect assessment of the value of acquisitions; failure to realize the anticipated benefits of acquisitions; delays resulting from or inability to obtain required regulatory approvals; increased debt levels or debt service requirements; inaccurate estimation of Whitecap’s oil and gas reserve volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time to time in Whitecap’s public disclosure documents (including, without limitation, those risks identified in this MD&A) and may be accessed through the SEDAR website (www.sedar.com).

The forward-looking information and statements contained in this MD&A speak only as of the date of this MD&A, and Whitecap does not assume any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.

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